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SUBCHAPTER B—OFFSHORE

PART 250—OIL AND GAS AND SUL-PHUR OPERATIONS IN THE OUTERCONTINENTAL SHELF

Subpart A—General

AUTHORITY AND DEFINITION OF TERMS

Sec.250.101 Authority and applicability.250.102 What does this part do?250.103 Where can I find more information

about the requirements in this part?250.104 How may I appeal a decision made

under MMS regulations?250.105 Definitions.

PERFORMANCE STANDARDS

250.106 What standards will the Director useto regulate lease operations?

250.107 What must I do to protect health,safety, property, and the environment?

250.108 What requirements must I follow forcranes and other material-handlingequipment?

250.109 What documents must I prepare andmaintain related to welding?

250.110 What must I include in my weldingplan?

250.111 Who oversees operations under mywelding plan?

250.112 What standards must my weldingequipment meet?

250.113 What procedures must I follow whenwelding?

250.114 How must I install and operate elec-trical equipment?

250.115 How do I determine wellproducibility?

250.116 How do I determine producibility ifmy well is in the Gulf of Mexico?

250.117 How does a determination of wellproducibility affect royalty status?

250.118 Will MMS approve gas injection?250.119 Will MMS approve subsurface gas

storage?250.120 How does injecting, storing, or treat-

ing gas affect my royalty payments?250.121 What happens when the reservoir

contains both original gas in place andinjected gas?

250.122 What effect does subsurface storagehave on the lease term?

250.123 Will MMS allow gas storage on un-leased lands?

250.124 Will MMS approve gas injection intothe cap rock containing a sulphur de-posit?

INSPECTION OF OPERATIONS

250.130 Why does MMS conduct inspections?

250.131 Will MMS notify me before con-ducting an inspection?

250.132 What must I do when MMS conductsan inspection?

250.133 Will MMS reimburse me for my ex-penses related to inspections?

DISQUALIFICATION

250.135 What will MMS do if my operatingperformance is unacceptable?

250.136 How will MMS determine if my oper-ating performance is unacceptable?

SPECIAL TYPES OF APPROVALS

250.140 When will I receive an oral approval?250.141 May I ever use alternate procedures

or equipment?250.142 How do I receive approval for depar-

tures?250.143 How do I designate an operator?250.144 How do I designate a new operator

when a designation of operator termi-nates?

250.145 How do I designate an agent or alocal agent?

250.146 Who is responsible for fulfillingleasehold obligations?

NAMING AND IDENTIFYING FACILITIES ANDWELLS (DOES NOT INCLUDE MODUS)

250.150 How do I name facilities and wells inthe Gulf of Mexico Region?

250.151 How do I name facilities in the Pa-cific Region?

250.152 How do I name facilities in the Alas-ka Region?

250.153 Do I have to rename an existing fa-cility or well?

250.154 What identification signs must I dis-play?

RIGHT-OF-USE AND EASEMENT

250.160 When will MMS grant me a right-of-use and easement, and what require-ments must I meet?

250.161 What else must I submit with my ap-plication?

250.162 May I continue my right-of-use andeasement after the termination of anylease on which it is situated?

250.163 If I have a State lease, will MMSgrant me a right-of-use and easement?

250.164 If I have a State lease, what condi-tions apply for a right-of-use and ease-ment?

250.165 If I have a State lease, what fees doI have to pay for a right-of-use and ease-ment?

250.166 If I have a State lease, what suretybond must I have for a right-of-use andeasement?

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30 CFR Ch. II (7–1–01 Edition)Pt. 250

SUSPENSIONS

250.168 May operations or production be sus-pended?

250.169 What effect does suspension have onmy lease?

250.170 How long does a suspension last?250.171 How do I request a suspension?250.172 When may the Regional Supervisor

grant or direct an SOO or SOP?250.173 When may the Regional Supervisor

direct an SOO or SOP?250.174 When may the Regional Supervisor

grant or direct an SOP?250.175 When may the Regional Supervisor

grant an SOO?250.176 Does a suspension affect my royalty

payment?250.177 What additional requirements may

the Regional Supervisor order for a sus-pension?

PRIMARY LEASE REQUIREMENTS, LEASE TERMEXTENSIONS, AND LEASE CANCELLATIONS

250.180 What am I required to do to keep mylease term in effect?

250.181 When may the Secretary cancel mylease and when am I compensated forcancellation?

250.182 When may the Secretary cancel alease at the exploration stage?

250.183 When may MMS or the Secretary ex-tend or cancel a lease at the developmentand production stage?

250.184 What is the amount of compensationfor lease cancellation?

250.185 When is there no compensation for alease cancellation?

INFORMATION AND REPORTING REQUIREMENTS

250.190 What reporting information and re-port forms must I submit?

250.191 What accident reports must I sub-mit?

250.192 What evacuation statistics must Isubmit?

250.193 Reports and investigations of appar-ent violations.

250.194 What archaeological reports and sur-veys must I submit?

250.195 Reimbursements for reproductionand processing costs.

250.196 Data and information to be madeavailable to the public.

REFERENCES

250.198 Documents incorporated by ref-erence.

250.199 Paperwork Reduction Act state-ments—information collection.

Subpart B—Exploration and Developmentand Production Plans

250.200 General requirements.250.201 Preliminary activities.250.202 Well location and spacing.

250.203 Exploration Plan.250.204 Development and Production Plan.

Subpart C—Pollution Prevention andControl

250.300 Pollution prevention.250.301 Inspection of facilities.250.302 Definitions concerning air quality.250.303 Facilities described in a new or re-

vised Exploration Plan or Developmentand Production Plan.

250.304 Existing facilities.

Subpart D—Oil and Gas Drilling Operations

250.400 Control of wells.250.401 General requirements.250.402–250.403 [Reserved]250.404 Well casing and cementing.250.405 Pressure testing of casing.250.406 Blowout preventer systems and sys-

tem components.250.407 Blowout preventer (BOP) systems

tests, inspections, and maintenance.250.408 Well-control drills.250.409 Diverter systems.250.410 Mud program.250.411 Securing of wells.250.412 Field drilling rules.250.413 Supervision, surveillance, and train-

ing.250.414 Applications for permit to drill.250.415 Sundry notices and reports on wells.250.416 Well records.250.417 Hydrogen sulfide.

Subpart E—Oil and Gas Well-CompletionOperations

250.500 General requirements.250.501 Definition.250.502 Equipment movement.250.503 Emergency shutdown system.250.504 Hydrogen sulfide.250.505 Subsea completions.250.506 Crew instructions.250.507–250.508 [Reserved]250.509 Well-completion structures on fixed

platforms.250.510 Diesel engine air intakes.250.511 Traveling-block safety device.250.512 Field well-completion rules.250.513 Approval and reporting of well-com-

pletion operations.250.514 Well-control fluids, equipment, and

operations.250.515 Blowout prevention equipment.250.516 Blowout preventer system tests, in-

spections, and maintenance.250.517 Tubing and wellhead equipment.

Subpart F—Oil and Gas Well-WorkoverOperations

250.600 General requirements.250.601 Definitions.


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Minerals Management Service, Interior Pt. 250

250.602 Equipment movement.250.603 Emergency shutdown system.250.604 Hydrogen sulfide.250.605 Subsea workovers.250.606 Crew instructions.250.607–250.608 [Reserved]250.609 Well-workover structures on fixed

platforms.250.610 Diesel engine air intakes.250.611 Traveling-block safety device.250.612 Field well-workover rules.250.613 Approval and reporting for well-

workover operations.250.614 Well-control fluids, equipment, and

operations.250.615 Blowout prevention equipment.250.616 Blowout preventer system testing,

records, and drills.250.617 Tubing and wellhead equipment.250.618 Wireline operations.

Subpart G—Abandonment of Wells

250.700 General requirements.250.701 Approvals.250.702 Permanent abandonment.250.703 Temporary abandonment.250.704 Site clearance verification.

Subpart H—Oil and Gas Production SafetySystems

250.800 General requirements.250.801 Subsurface safety devices.250.802 Design, installation, and operation

of surface production–safety systems.250.803 Additional production system re-

quirements.250.804 Production safety-system testing

and records.250.805 Safety device training.250.806 Safety and pollution prevention

equipment quality assurance require-ments.

250.807 Hydrogen sulfide.

Subpart I—Platforms and Structures

250.900 General requirements.250.901 Application for approval.250.902 Platform Verification Program re-

quirements.250.903 Certified Verification Agent duties

and nomination.250.904 Environmental conditions.250.905 Loads.250.906 General design requirements.250.907 Steel platforms.250.908 Concrete-gravity platforms.250.909 Foundation.250.910 Marine operations.250.911 Inspection during construction.250.912 Periodic inspection and mainte-

nance.250.913 Platform removal and location

clearance.250.914 Records.

Subpart J—Pipelines and Pipeline Rights-of-Way

250.1000 General requirements.250.1001 Definitions.250.1002 Design requirements for DOI pipe-

lines.250.1003 Installation, testing and repair re-

quirements for DOI pipelines.250.1004 Safety equipment requirements for

DOI pipelines.250.1005 Inspection requirements for DOI

pipelines.250.1006 Abandonment and out-of-service re-

quirements for DOI pipelines.250.1007 What to include in applications.250.1008 Reports.250.1009 General requirements for a pipeline

right-of-way grant.250.1010 Applications for a pipeline right-of-

way grant.250.1011 Granting a pipeline right-of-way.250.1012 Requirements for construction

under a right-of-way grant.250.1013 Assignment of a right-of-way grant.250.1014 Relinquishment of a right-of-way

grant.

Subpart K—Oil and Gas Production Rates

250.1100 Definitions for production rates.250.1101 General requirements and classi-

fication of reservoirs.250.1102 Oil and gas production rates.250.1103 Well production testing.250.1104 Bottomhole pressure survey.250.1105 Flaring or venting gas and burning

liquid hydrocarbons.250.1106 Downhole commingling.250.1107 Enhanced oil and gas recovery oper-

ations.

Subpart L—Oil and Gas Production Meas-urement, Surface Commingling, andSecurity

250.1200 Question index table.250.1201 Definitions.250.1202 Liquid hydrocarbon measurement.250.1203 Gas measurement.250.1204 Surface commingling.250.1205 Site security.

Subpart M—Unitization

250.1300 What is the purpose of this subpart?250.1301 What are the requirements for unit-

ization?250.1302 What if I have a competitive res-

ervoir on a lease?250.1303 How do I apply for voluntary unit-

ization?250.1304 How will MMS require unitization?


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30 CFR Ch. II (7–1–01 Edition)§ 250.101

Subpart N—Outer Continental Shelf (OCS)Civil Penalties

250.1400 How does MMS begin the civil pen-alty process?

250.1401 Index table.250.1402 Definitions.250.1403 What is the maximum civil pen-

alty?250.1404 Which violations will MMS review

for potential civil penalties?250.1405 When is a case file developed?250.1406 When will MMS notify me and pro-

vide penalty information?250.1407 How do I respond to the letter of

notification?250.1408 When will I be notified of the Re-

viewing Officer’s decision?250.1409 What are my appeal rights?

Subpart O—Well Control and ProductionSafety Training

250.1500 Definitions.250.1501 What is the goal of my training pro-

gram?250.1502 Is there a transition period for com-

plying with the regulations in this sub-part?

250.1503 What are my general responsibil-ities for training?

250.1504 May I use alternative trainingmethods?

250.1505 Where may I get training for myemployees?

250.1506 How often must I train my employ-ees?

250.1507 How will MMS measure training re-sults?

250.1508 What must I do when MMS admin-isters written or oral tests?

250.1509 What must I do when MMS admin-isters or requires hands-on, simulator, orother types of testing?

250.1510 What will MMS do if my trainingprogram does not comply with this sub-part?

Subpart P—Sulphur Operations

250.1600 Performance standard.250.1601 Definitions.250.1602 Applicability.250.1603 Determination of sulphur deposit.250.1604 General requirements.250.1605 Drilling requirements.250.1606 Control of wells.250.1607 Field rules.250.1608 Well casing and cementing.250.1609 Pressure testing of casing.250.1610 Blowout preventer systems and sys-

tem components.250.1611 Blowout preventer systems tests,

actuations, inspections, and mainte-nance.

250.1612 Well-control drills.250.1613 Diverter systems.

250.1614 Mud program.250.1615 Securing of wells.250.1616 Supervision, surveillance, and

training.250.1617 Application for permit to drill.250.1618 Sundry notices and reports on

wells.250.1619 Well records.250.1620 Well-completion and well-workover

requirements.250.1621 Crew instructions.250.1622 Approvals and reporting of well-

completion and well-workover oper-ations.

250.1623 Well-control fluids, equipment, andoperations.

250.1624 Blowout prevention equipment.250.1625 Blowout preventer system testing,

records, and drills.250.1626 Tubing and wellhead equipment.250.1627 Production requirements.250.1628 Design, installation, and operation

of production systems.250.1629 Additional production and fuel gas

system requirements.250.1630 Safety-system testing and records.250.1631 Safety device training.250.1632 Production rates.250.1633 Production measurement.250.1634 Site security.

AUTHORITY: 43 U.S.C. 1331, et seq.

SOURCE: 53 FR 10690, Apr. 1, 1988, unlessotherwise noted. Redesignated at 63 FR 29479,May 29, 1998.

Subpart A—General

SOURCE: At 64 FR 72775, Dec. 28, 1999, unlessotherwise noted.

AUTHORITY AND DEFINITION OF TERMS

§ 250.101 Authority and applicability.The Secretary of the Interior (Sec-

retary) authorized the Minerals Man-agement Service (MMS) to regulate oil,gas, and sulphur exploration, develop-ment, and production operations on theouter Continental Shelf (OCS). Underthe Secretary’s authority, the Directorrequires that all operations:

(a) Be conducted according to theOCS Lands Act (OCSLA), the regula-tions in this part, MMS orders, thelease or right-of-way, and other appli-cable laws, regulations, and amend-ments; and

(b) Conform to sound conservationpractice to preserve, protect, and de-velop mineral resources of the OCS to:

(1) Make resources available to meetthe Nation’s energy needs;


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Minerals Management Service, Interior § 250.105

(2) Balance orderly energy resourcedevelopment with protection of thehuman, marine, and coastal environ-ments;

(3) Ensure the public receives a fairand equitable return on the resourcesof the OCS;

(4) Preserve and maintain free enter-prise competition; and

(5) Minimize or eliminate conflictsbetween the exploration, development,and production of oil and natural gasand the recovery of other resources.

§ 250.102 What does this part do?(a) 30 CFR part 250 contains the regu-

lations of the MMS Offshore programthat govern oil, gas, and sulphur explo-ration, development, and productionoperations on the OCS. When you con-duct operations on the OCS, you mustsubmit requests, applications, and no-tices, or provide supplemental informa-tion for MMS approval.

(b) The following table of general ref-erences shows where to look for infor-mation about these processes.

TABLE—WHERE TO FIND INFORMATION FOR CONDUCTING OPERATIONS

For information about Refer to

(1) Abandoning wells ................................................................................................................................ § 250.701.(2) Applications for Permit to Drill ............................................................................................................ § 250.414.(3) Development and Production Plans (DPP) ........................................................................................ § 250.204.(4) Downhole commingling ....................................................................................................................... § 250.1106.(5) Exploration Plans (EP) ........................................................................................................................ § 250.203.(6) Flaring ................................................................................................................................................. § 250.1105.(7) Gas measurement .............................................................................................................................. § 250.1203.(8) Off-lease geological and geophysical permits .................................................................................... 30 CFR 251.(9) Oil spill financial responsibility coverage ............................................................................................ 30 CFR 253.

(10) Oil and gas production safety systems .............................................................................................. § 250.802.(11) Oil spill response plans ...................................................................................................................... 30 CFR 254.(12) Oil and gas well-completion operations .............................................................................................. § 250.513.(13) Oil and gas well-workover operations ................................................................................................ § 250.613.(14) Platforms and structures ..................................................................................................................... § 250.901.(15) Pipelines .............................................................................................................................................. § 250.1009.(16) Pipeline right-of-way ........................................................................................................................... § 250.1010.(17) Sulphur operations .............................................................................................................................. § 250.1604.(18) Training ............................................................................................................................................... § 250.1500.(19) Unitization ........................................................................................................................................... § 250.1300.

§ 250.103 Where can I find more infor-mation about the requirements inthis part?

MMS may issue Notices to Lesseesand Operators (NTLs) that clarify, sup-plement, or provide more detail aboutcertain requirements. NTLs may alsooutline what you must provide as re-quired information in your various sub-missions to MMS.

§ 250.104 How may I appeal a decisionmade under MMS regulations?

To appeal orders or decisions issuedunder MMS regulations in 30 CFR parts250 to 282, follow the procedures in 30CFR part 290.

§ 250.105 Definitions.Terms used in this part will have the

meanings given in the Act and as de-fined in this section:

Act means the OCS Lands Act, asamended (43 U.S.C. 1331 et seq.).

Affected State means with respect toany program, plan, lease sale, or otheractivity proposed, conducted, or ap-proved under the provisions of the Act,any State:

(1) The laws of which are declared,under section 4(a)(2) of the Act, to bethe law of the United States for theportion of the OCS on which such ac-tivity is, or is proposed to be, con-ducted;

(2) Which is, or is proposed to be, di-rectly connected by transportation fa-cilities to any artificial island or in-stallation or other device permanentlyor temporarily attached to the seabed;

(3) Which is receiving, or accordingto the proposed activity, will receiveoil for processing, refining, or trans-shipment that was extracted from theOCS and transported directly to suchState by means of vessels or by a com-bination of means including vessels;


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30 CFR Ch. II (7–1–01 Edition)§ 250.105

(4) Which is designated by the Sec-retary as a State in which there is asubstantial probability of significantimpact on or damage to the coastal,marine, or human environment, or aState in which there will be significantchanges in the social, governmental, oreconomic infrastructure, resultingfrom the exploration, development, andproduction of oil and gas anywhere onthe OCS; or

(5) In which the Secretary finds thatbecause of such activity there is, orwill be, a significant risk of seriousdamage, due to factors such as pre-vailing winds and currents to the ma-rine or coastal environment in theevent of any oil spill, blowout, or re-lease of oil or gas from vessels, pipe-lines, or other transshipment facilities.

Air pollutant means any airborneagent or combination of agents forwhich the Environmental ProtectionAgency (EPA) has established, undersection 109 of the Clean Air Act, na-tional primary or secondary ambientair quality standards.

Analyzed geological information meansdata collected under a permit or a leasethat have been analyzed. Analysis mayinclude, but is not limited to, identi-fication of lithologic and fossil con-tent, core analysis, laboratory analysesof physical and chemical properties,well logs or charts, results from forma-tion fluid tests, and descriptions of hy-drocarbon occurrences or hazardousconditions.

Archaeological interest means capableof providing scientific or humanisticunderstanding of past human behavior,cultural adaptation, and related topicsthrough the application of scientific orscholarly techniques, such as con-trolled observation, contextual meas-urement, controlled collection, anal-ysis, interpretation, and explanation.

Archaeological resource means anymaterial remains of human life or ac-tivities that are at least 50 years of ageand that are of archaeological interest.

Attainment area means, for any airpollutant, an area that is shown bymonitored data or that is calculated byair quality modeling (or other methodsdetermined by the Administrator ofEPA to be reliable) not to exceed anyprimary or secondary ambient air qual-ity standards established by EPA.

Best available and safest technology(BAST) means the best available andsafest technologies that the Directordetermines to be economically feasiblewherever failure of equipment wouldhave a significant effect on safety,health, or the environment.

Best available control technology(BACT) means an emission limitationbased on the maximum degree of reduc-tion for each air pollutant subject toregulation, taking into account energy,environmental and economic impacts,and other costs. The Regional Directorwill verify the BACT on a case-by-casebasis, and it may include reductionsachieved through the application ofprocesses, systems, and techniques forthe control of each air pollutant.

Coastal environment means the phys-ical, atmospheric, and biological com-ponents, conditions, and factors thatinteractively determine the produc-tivity, state, condition, and quality ofthe terrestrial ecosystem from theshoreline inward to the boundaries ofthe coastal zone.

Coastal zone means the coastal waters(including the lands therein and there-under) and the adjacent shorelands (in-cluding the waters therein and there-under) strongly influenced by eachother and in proximity to theshorelands of the several coastalStates. The coastal zone includes is-lands, transition and intertidal areas,salt marshes, wetlands, and beaches.The coastal zone extends seaward tothe outer limit of the U.S. territorialsea and extends inland from the shore-lines to the extent necessary to controlshorelands, the uses of which have a di-rect and significant impact on thecoastal waters, and the inward bound-aries of which may be identified by theseveral coastal States, under the au-thority in section 305(b)(1) of the Coast-al Zone Management Act (CZMA) of1972.

Competitive reservoir means a res-ervoir in which there are one or moreproducible or producing well comple-tions on each of two or more leases orportions of leases, with different leaseoperating interests, from which the les-sees plan future production.

Correlative rights when used with re-spect to lessees of adjacent leases,


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means the right of each lessee to be af-forded an equal opportunity to explorefor, develop, and produce, withoutwaste, minerals from a common source.

Data means facts and statistics,measurements, or samples that havenot been analyzed, processed, or inter-preted.

Departures means approvals grantedby the appropriate MMS representativefor operating requirements/proceduresother than those specified in the regu-lations found in this part. These re-quirements/procedures may be nec-essary to control a well; properly de-velop a lease; conserve natural re-sources, or protect life, property, orthe marine, coastal, or human environ-ment.

Development means those activitiesthat take place following discovery ofminerals in paying quantities, includ-ing but not limited to geophysical ac-tivity, drilling, platform construction,and operation of all directly related on-shore support facilities, and which arefor the purpose of producing the min-erals discovered.

Director means the Director of MMSof the U.S. Department of the Interior,or an official authorized to act on theDirector’s behalf.

District Supervisor means the MMS of-ficer with authority and responsibilityfor operations or other designated pro-gram functions for a district within anMMS Region.

Easement means an authorization fora nonpossessory, nonexclusive interestin a portion of the OCS, whether leasedor unleased, which specifies the rightsof the holder to use the area embracedin the easement in a manner consistentwith the terms and conditions of thegranting authority.

Eastern Gulf of Mexico means all OCSareas of the Gulf of Mexico the Direc-tor decides are adjacent to the State ofFlorida. The Eastern Gulf of Mexico isnot the same as the Eastern PlanningArea, an area established for OCS leasesales.

Emission offsets means emission re-ductions obtained from facilities, ei-ther onshore or offshore, other thanthe facility or facilities covered by theproposed Exploration Plan (EP) or De-velopment and Production Plan (DPP).

Enhanced recovery operations meanspressure maintenance operations, sec-ondary and tertiary recovery, cycling,and similar recovery operations thatalter the natural forces in a reservoirto increase the ultimate recovery of oilor gas.

Existing facility, as used in § 250.303,means an OCS facility described in anExploration Plan or a Development andProduction Plan approved before June2, 1980.

Exploration means the commercialsearch for oil, gas, or sulphur. Activi-ties classified as exploration includebut are not limited to:

(1) Geophysical and geological (G&G)surveys using magnetic, gravity, seis-mic reflection, seismic refraction, gassniffers, coring, or other systems to de-tect or imply the presence of oil, gas,or sulphur; and

(2) Any drilling conducted for thepurpose of searching for commercialquantities of oil, gas, and sulphur, in-cluding the drilling of any additionalwell needed to delineate any reservoirto enable the lessee to decide whetherto proceed with development and pro-duction.

Facility means:(1) As used in § 250.130, any installa-

tion permanently or temporarily at-tached to the seabed on the OCS (in-cluding manmade islands and bottom-sitting structures). It includes mobileoffshore drilling units (MODUs) orother vessels engaged in drilling ordownhole operations, used for oil, gas,or sulphur drilling, production, or re-lated activities. It also includes facili-ties for product measurement and roy-alty determination (e.g., Lease Auto-matic Custody Transfer units, gas me-ters) of OCS production on installa-tions not on the OCS. Any group ofOCS installations interconnected withwalkways, or any group of installa-tions that includes a central or pri-mary installation with processingequipment and one or more satellite orsecondary installations is a single fa-cility. The Regional Supervisor maydecide that the complexity of the indi-vidual installations justifies their clas-sification as separate facilities.

(2) As used in § 250.303, means any in-stallation or device permanently ortemporarily attached to the seabed. It


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30 CFR Ch. II (7–1–01 Edition)§ 250.105

includes mobile offshore drilling units(MODUs), even while operating in the‘‘tender assist’’ mode (i.e. with skid-offdrilling units) or other vessels engagedin drilling or downhole operations.They are used for exploration, develop-ment, and production activities for oil,gas, or sulphur and emit or have thepotential to emit any air pollutantfrom one or more sources. During pro-duction, multiple installations or de-vices are a single facility if the instal-lations or devices are at a single site.Any vessel used to transfer productionfrom an offshore facility is part of thefacility while it is physically attachedto the facility.

(3) As used in § 250.417(b), means avessel, a structure, or an artificial is-land used for drilling, well-completion,well-workover, and/or production oper-ations.

Gas reservoir means a reservoir thatcontains hydrocarbons predominantlyin a gaseous (single-phase) state.

Gas-well completion means a well com-pleted in a gas reservoir or in the asso-ciated gas-cap of an oil reservoir.

Governor means the Governor of aState, or the person or entity des-ignated by, or under, State law to exer-cise the powers granted to such Gov-ernor under the Act.

H2S absent means:(1) Drilling, logging, coring, testing,

or producing operations have con-firmed the absence of H2S in concentra-tions that could potentially result inatmospheric concentrations of 20 ppmor more of H2S; or

(2) Drilling in the surrounding areasand correlation of geological and seis-mic data with equivalent stratigraphicunits have confirmed an absence of H2Sthroughout the area to be drilled.

H2S present means drilling, logging,coring, testing, or producing oper-ations have confirmed the presence ofH2S in concentrations and volumesthat could potentially result in atmos-pheric concentrations of 20 ppm ormore of H2S.

H2S unknown means the designationof a zone or geologic formation whereneither the presence nor absence of H2Shas been confirmed.

Human environment means the phys-ical, social, and economic components,conditions, and factors that inter-

actively determine the state, condi-tion, and quality of living conditions,employment, and health of those af-fected, directly or indirectly, by activi-ties occurring on the OCS.

Interpreted geological informationmeans geological knowledge, often inthe form of schematic cross sections, 3-dimensional representations, and maps,developed by determining the geologi-cal significance of data and analyzedgeological information.

Interpreted geophysical informationmeans geophysical knowledge, often inthe form of schematic cross sections, 3-dimensional representations, and maps,developed by determining the geologi-cal significance of geophysical dataand analyzed geophysical information.

Lease means an agreement that isissued under section 8 or maintainedunder section 6 of the Act and that au-thorizes exploration for, and develop-ment and production of, minerals. Theterm also means the area covered bythat authorization, whichever the con-text requires.

Lease term pipelines means those pipe-lines owned and operated by a lessee oroperator that are completely containedwithin the boundaries of a single lease,unit, or contiguous (not cornering)leases of that lessee or operator.

Lessee means a person who has en-tered into a lease with the UnitedStates to explore for, develop, andproduce the leased minerals. The termlessee also includes the MMS-approvedassignee of the lease, and the owner orthe MMS-approved assignee of oper-ating rights for the lease.

Major Federal action means any ac-tion or proposal by the Secretary thatis subject to the provisions of section102(2)(C) of the National EnvironmentalPolicy Act of 1969, 42 U.S.C. (2)(C) (i.e.,an action that will have a significantimpact on the quality of the human en-vironment requiring preparation of anenvironmental impact statement undersection 102(2)(C) of the National Envi-ronmental Policy Act).

Marine environment means the phys-ical, atmospheric, and biological com-ponents, conditions, and factors thatinteractively determine the produc-tivity, state, condition, and quality ofthe marine ecosystem. These include


249


the waters of the high seas, the contig-uous zone, transitional and intertidalareas, salt marshes, and wetlands with-in the coastal zone and on the OCS.

Material remains means physical evi-dence of human habitation, occupation,use, or activity, including the site, lo-cation, or context in which such evi-dence is situated.

Maximum efficient rate (MER) meansthe maximum sustainable daily oil orgas withdrawal rate from a reservoirthat will permit economic developmentand depletion of that reservoir withoutdetriment to ultimate recovery.

Maximum production rate (MPR)means the approved maximum dailyrate at which oil or gas may be pro-duced from a specified oil-well or gas-well completion.

Minerals includes oil, gas, sulphur,geopressured-geothermal and associ-ated resources, and all other mineralsthat are authorized by an Act of Con-gress to be produced.

Natural resources includes, withoutlimiting the generality thereof, oil,gas, and all other minerals, and fish,shrimp, oysters, clams, crabs, lobsters,sponges, kelp, and other marine animaland plant life but does not includewater power or the use of water for theproduction of power.

Nonattainment area means, for any airpollutant, an area that is shown bymonitored data or that is calculated byair quality modeling (or other methodsdetermined by the Administrator ofEPA to be reliable) to exceed any pri-mary or secondary ambient air qualitystandard established by EPA.

Nonsensitive reservoir means a res-ervoir in which ultimate recovery isnot decreased by high reservoir produc-tion rates.

Oil reservoir means a reservoir thatcontains hydrocarbons predominantlyin a liquid (single-phase) state.

Oil reservoir with an associated gas capmeans a reservoir that contains hydro-carbons in both a liquid and gaseous(two-phase) state.

Oil-well completion means a well com-pleted in an oil reservoir or in the oilaccumulation of an oil reservoir withan associated gas cap.

Operating rights means any interestheld in a lease with the right to explore

for, develop, and produce leased sub-stances.

Operator means the person the les-see(s) designates as having control ormanagement of operations on theleased area or a portion thereof. An op-erator may be a lessee, the MMS-ap-proved designated agent of the les-see(s), or the holder of operating rightsunder an MMS-approved operatingrights assignment.

Outer Continental Shelf (OCS) meansall submerged lands lying seaward andoutside of the area of lands beneathnavigable waters as defined in section 2of the Submerged Lands Act (43 U.S.C.1301) whose subsoil and seabed apper-tain to the United States and are sub-ject to its jurisdiction and control.

Person includes, in addition to a nat-ural person, an association (includingpartnerships and trusts), a State, a po-litical subdivision of a State, or a pri-vate, public, or municipal corporation.

Pipelines are the piping, risers, andappurtenances installed for trans-porting oil, gas, sulphur, and producedwaters.

Processed geological or geophysical in-formation means data collected under apermit or a lease that have been proc-essed or reprocessed. Processing in-volves changing the form of data to fa-cilitate interpretation. Processing op-erations may include, but are not lim-ited to, applying corrections for knownperturbing causes, rearranging or fil-tering data, and combining or trans-forming data elements. Reprocessing isthe additional processing other thanordinary processing used in the generalcourse of evaluation. Reprocessing op-erations may include varying identi-fied parameters for the detailed studyof a specific problem area.

Production means those activitiesthat take place after the successfulcompletion of any means for the re-moval of minerals, including such re-moval, field operations, transfer ofminerals to shore, operation moni-toring, maintenance, and workover op-erations.

Production areas are those areaswhere flammable petroleum gas, vola-tile liquids or sulphur are produced,processed (e.g., compressed), stored,transferred (e.g., pumped), or otherwise


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30 CFR Ch. II (7–1–01 Edition)§ 250.105

handled before entering the transpor-tation process.

Projected emissions means emissions,either controlled or uncontrolled, froma source or sources.

Regional Director means the MMS of-ficer with responsibility and authorityfor a Region within MMS.

Regional Supervisor means the MMSofficer with responsibility and author-ity for operations or other designatedprogram functions within an MMS Re-gion.

Right-of-use means any authorizationissued under this part to use OCSlands.

Right-of-way pipelines are those pipe-lines that are contained within:

(1) The boundaries of a single lease orunit, but are not owned and operatedby a lessee or operator of that lease orunit;

(2) The boundaries of contiguous (notcornering) leases that do not have acommon lessee or operator;

(3) The boundaries of contiguous (notcornering) leases that have a commonlessee or operator but are not ownedand operated by that common lessee oroperator; or

(4) An unleased block(s).Routine operations, for the purposes of

subpart F, means any of the followingoperations conducted on a well withthe tree installed:

(1) Cutting paraffin;(2) Removing and setting pump-

through-type tubing plugs, gas-liftvalves, and subsurface safety valvesthat can be removed by wireline oper-ations;

(3) Bailing sand;(4) Pressure surveys;(5) Swabbing;(6) Scale or corrosion treatment;(7) Caliper and gauge surveys;(8) Corrosion inhibitor treatment;(9) Removing or replacing subsurface

pumps;(10) Through-tubing logging

(diagnostics);(11) Wireline fishing;(12) Setting and retrieving other sub-

surface flow-control devices; and(13) Acid treatments.Sensitive reservoir means a reservoir

in which high reservoir productionrates will decrease ultimate recovery.For submitting the first MER, all oil

reservoirs with an associated gas capare classified as sensitive.

Significant archaeological resourcemeans those archaeological resourcesthat meet the criteria of significancefor eligibility to the National Registerof Historic Places as defined in 36 CFR60.4, or its successor.

Suspension means a granted or di-rected deferral of the requirement toproduce (Suspension of Production(SOP)) or to conduct leaseholding oper-ations (Suspension of Operations(SOO)).

Waste of oil, gas, or sulphur means:(1) The physical waste of oil, gas, or

sulphur;(2) The inefficient, excessive, or im-

proper use, or the unnecessary dissipa-tion of reservoir energy;

(3) The locating, spacing, drilling,equipping, operating, or producing ofany oil, gas, or sulphur well(s) in amanner that causes or tends to cause areduction in the quantity of oil, gas, orsulphur ultimately recoverable underprudent and proper operations or thatcauses or tends to cause unnecessary orexcessive surface loss or destruction ofoil or gas; or

(4) The inefficient storage of oil.Welding means all activities con-

nected with welding, including hot tap-ping and burning.

Wellbay is the area on a facility with-in the perimeter of the outermostwellheads.

Well-completion operations means thework conducted to establish productionfrom a well after the production-casingstring has been set, cemented, andpressure-tested.

Well-control fluid means drilling mud,completion fluid, or workover fluid asappropriate to the particular operationbeing conducted.

Western Gulf of Mexico means all OCSareas of the Gulf of Mexico exceptthose the Director decides are adjacentto the State of Florida. The WesternGulf of Mexico is not the same as theWestern Planning Area, an area estab-lished for OCS lease sales.

Workover operations means the workconducted on wells after the initialwell-completion operation for the pur-pose of maintaining or restoring theproductivity of a well.


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You means a lessee, the owner orholder of operating rights, a designatedagent of the lessee(s), a pipeline right-of-way holder, or a State lessee granteda right-of-use and easement.

PERFORMANCE STANDARDS

§ 250.106 What standards will the Di-rector use to regulate lease oper-ations?

The Director will regulate all oper-ations under a lease, right-of-use andeasement, or right-of-way to:

(a) Promote orderly exploration, de-velopment, and production of mineralresources;

(b) Prevent injury or loss of life;(c) Prevent damage to or waste of

any natural resource, property, or theenvironment; and

(d) Cooperate and consult with af-fected States, local governments, otherinterested parties, and relevant Fed-eral agencies.

§ 250.107 What must I do to protecthealth, safety, property, and the en-vironment?

(a) You must protect health, safety,property, and the environment by:

(1) Performing all operations in asafe and workmanlike manner; and

(2) Maintaining all equipment in asafe condition.

(b) You must immediately control,remove, or otherwise correct any haz-ardous oil and gas accumulation orother health, safety, or fire hazard.

(c) You must use the best availableand safest technology (BAST) when-ever practical on all exploration, devel-opment, and production operations. Ingeneral, we consider your compliancewith MMS regulations to be the use ofBAST.

(d) The Director may require addi-tional measures to ensure the use ofBAST:

(1) To avoid the failure of equipmentthat would have a significant effect onsafety, health, or the environment;

(2) If it is economically feasible; and(3) If the benefits outweigh the costs.

§ 250.108 What requirements must Ifollow for cranes and other mate-rial-handling equipment?

(a) If you operate a crane installed onfixed platforms you must:

(1) Follow the American PetroleumInstitute (API) Recommended Practice(RP) for Operation and Maintenance ofOffshore Cranes (API RP 2D);

(2) Keep inspection, testing, andmaintenance records at the OCS facil-ity for at least 2 years; and

(3) Keep crane operator qualificationsat the facility for at least 4 years.

(b) You must operate and maintainall other material-handling equipmentin a manner that ensures safe oper-ations and prevents pollution.

§ 250.109 What documents must I pre-pare and maintain related to weld-ing?

(a) You must submit a Welding Planto the District Supervisor before youbegin drilling or production activitieson a lease. You may not begin weldinguntil the District Supervisor has ap-proved your plan.

(b) You must keep the following atthe site where welding occurs:

(1) A copy of the plan and its ap-proval letter; and

(2) Drawings showing the designatedsafe-welding areas.

§ 250.110 What must I include in mywelding plan?

You must include all of the followingin the Welding Plan that you prepareunder § 250.109:

(a) Standards or requirements forwelders;

(b) How you will ensure that onlyqualified personnel weld;

(c) Practices and procedures for safewelding that address:

(1) Welding in designated safe areas;(2) Welding in undesignated areas, in-

cluding wellbay;(3) Fire watches;(4) Maintenance of welding equip-

ment; and(5) Plans showing all designated safe-

welding areas.(d) How you will prevent spark-pro-

ducing activities (i.e., grinding, abra-sive blasting/cutting and arc-welding)in hazardous locations.

§ 250.111 Who oversees operationsunder my welding plan?

A welding supervisor or a designatedperson in charge must be thoroughlyfamiliar with your welding plan. This


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person must ensure that each welder isproperly qualified according to thewelding plan. This person also must in-spect all welding equipment beforewelding.

§ 250.112 What standards must mywelding equipment meet?

Your welding equipment must meetthe following requirements:

(a) All engine-driven welding equip-ment must be equipped with spark ar-restors and drip pans;

(b) Welding leads must be completelyinsulated and in good condition;

(c) Hoses must be leak-free andequipped with proper fittings, gauges,and regulators; and

(d) Oxygen and fuel gas bottles mustbe secured in a safe place.

§ 250.113 What procedures must I fol-low when welding?

(a) Before you weld, you must moveany equipment containing hydro-carbons or other flammable substancesat least 35 feet horizontally from thewelding area. You must move similarequipment on lower decks at least 35feet from the point of impact whereslag, sparks, or other burning mate-rials could fall. If moving this equip-ment is impractical, you must protectthat equipment with flame-proofedcovers, shield it with metal or fire-re-sistant guards or curtains, or renderthe flammable substances inert.

(b) While you weld, you must mon-itor all water-discharge-point sourcesfrom hydrocarbon-handling vessels. If adischarge of flammable fluids occurs,you must stop welding.

(c) If you cannot weld in one of thedesignated safe-welding areas that youlisted in your safe welding plan, youmust meet the following requirements:

(1) You may not begin welding until:(i) The welding supervisor or des-

ignated person in charge advises inwriting that it is safe to weld.

(ii) You and the designated person incharge inspect the work area and areasbelow it for potential fire and explosionhazards.

(2) During welding, the person incharge must designate one or more per-sons as a fire watch. The fire watchmust:

(i) Have no other duties while actualwelding is in progress;

(ii) Have usable firefighting equip-ment;

(iii) Remain on duty for 30 minutesafter welding activities end; and

(iv) Maintain a continuous surveil-lance with a portable gas detector dur-ing the welding and burning operationif welding occurs in an area notequipped with a gas detector.

(3) You may not weld piping, con-tainers, tanks, or other vessels thathave contained a flammable substanceunless you have rendered the contentsinert and the designated person incharge has determined it is safe toweld. This does not apply to approvedhot taps.

(4) You may not weld within 10 feetof a wellbay unless you have shut in allproducing wells in that wellbay.

(5) You may not weld within 10 feetof a production area, unless you haveshut in that production area.

(6) You may not weld while you drill,complete, workover, or conductwireline operations unless:

(i) The fluids in the well (beingdrilled, completed, worked over, orhaving wireline operations conducted)are noncombustible; and

(ii) You have precluded the entry offormation hydrocarbons into thewellbore by either mechanical meansor a positive overbalance toward theformation.

§ 250.114 How must I install and oper-ate electrical equipment?

The requirements in this sectionapply to all electrical equipment on allplatforms, artificial islands, fixedstructures, and their facilities.

(a) You must classify all areas ac-cording to API RP 500, RecommendedPractice for Classification of Locationsfor Electrical Installations at Petro-leum Facilities Classified as Class I,Division 1 and Division 2, or API RP505, Recommended Practice for Classi-fication of Locations for Electrical In-stallations at Petroleum FacilitiesClassified as Class I, Zone 0, Zone 1,and Zone 2.

(b) Employees who maintain yourelectrical systems must have expertise


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in area classification and the perform-ance, operation and hazards of elec-trical equipment.

(c) You must install all electricalsystems according to API RP 14F, Rec-ommended Practice for Design and In-stallation of Electrical Systems forOffshore Production Platforms. You donot have to comply with Sections 7.4,Emergency Lighting, and 9.4, Aids toNavigation Equipment.

(d) On each engine that has an elec-tric ignition system, you must use anignition system designed and main-tained to reduce the release of elec-trical energy.

[64 FR 72775, Dec. 28, 1999, as amended at 65FR 219, Jan. 4, 2000]

§ 250.115 How do I determine wellproducibility?

You must follow the procedures inthis section to determine wellproducibility if your well is not in theGOM. If your well is in the GOM youmust follow the procedures in eitherthis section or in § 250.116 of this sub-part.

(a) You must write to the RegionalSupervisor asking for permission to de-termine producibility.

(b) You must either:(1) Allow the District Supervisor to

witness each test that you conductunder this section; or

(2) Receive the District Supervisor’sprior approval so that you can submiteither test data with your affidavit orthird party test data.

(c) If the well is an oil well, you mustconduct a production test that lasts atleast 2 hours after flow stabilizes.

(d) If the well is a gas well, you mustconduct a deliverability test that lastsat least 2 hours after flow stabilizes, ora four-point back pressure test.

§ 250.116 How do I determineproducibility if my well is in theGulf of Mexico?

If your well is in the GOM, you mustfollow either the procedures in § 250.115of this subpart or the procedures inthis section to determine producibility.

(a) You must write to the RegionalSupervisor asking for permission to de-termine producibility.

(b) You must provide or make avail-able to the Regional Supervisor, as re-

quested, the following log, core, anal-yses, and test criteria that MMS willconsider collectively:

(1) A log showing sufficient porosityin the producible section.

(2) Sidewall cores and core analysesthat show that the section is capable ofproducing oil or gas.

(3) Wireline formation test and/ormud-logging analyses that show thatthe section is capable of producing oilor gas.

(4) A resistivity or induction electriclog of the well showing a minimum of15 feet (true vertical thickness exceptfor horizontal wells) of producible sandin one section.

(c) No section that you count as pro-ducible under paragraph (b)(4) of thissection may include any interval thatappears to be water saturated.

(d) Each section you count as produc-ible under paragraph (b)(4) of this sec-tion must exhibit:

(1) A minimum true resistivity ratioof the producible section to the nearestclean or water-bearing sand of at least5:1; and

(2) One of the following:(i) Electrical spontaneous potential

exceeding 20-negative millivolts be-yond the shale baseline; or

(ii) Gamma ray log deflection of atleast 70 percent of the maximumgamma ray deflection in the nearestclean water-bearing sand—if mud con-ditions prevent a 20-negative millivoltreading beyond the shale baseline.

§ 250.117 How does a determination ofwell producibility affect royalty sta-tus?

A determination of well producibilityinvokes minimum royalty status onthe lease as provided in 30 CFR 202.53.

§ 250.118 Will MMS approve gas injec-tion?

The Regional Supervisor may author-ize you to inject gas on the OCS, onand off-lease, to promote conservationof natural resources and to preventwaste.

(a) To receive MMS approval for in-jection, you must:

(1) Show that the injection will notresult in undue interference with oper-ations under existing leases; and


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30 CFR Ch. II (7–1–01 Edition)§ 250.119

(2) Submit a written application tothe Regional Supervisor for injectionof gas.

(b) The Regional Supervisor will ap-prove gas injection applications that:

(1) Enhance recovery;(2) Prevent flaring of casinghead gas;

or(3) Implement other conservation

measures approved by the Regional Su-pervisor.

§ 250.119 Will MMS approve subsurfacegas storage?

The Regional Supervisor may author-ize subsurface storage of gas on theOCS, on and off-lease, for later com-mercial benefit. To receive MMS ap-proval you must:

(a) Show that the subsurface storageof gas will not result in undue inter-ference with operations under existingleases; and

(b) Sign a storage agreement that in-cludes the required payment of a stor-age fee or rental.

§ 250.120 How does injecting, storing,or treating gas affect my royaltypayments?

(a) If you produce gas from an OCSlease and inject it into a reservoir onthe lease or unit for the purposes citedin § 250.118(b), you are not required topay royalties until you remove or sellthe gas from the reservoir.

(b) If you produce gas from an OCSlease and store it according to § 250.119,you must pay royalty before injectingit into the storage reservoir.

(c) If you produce gas from an OCSlease and treat it at an off-lease or off-unit location, you must pay royaltieswhen the gas is first produced.

§ 250.121 What happens when the res-ervoir contains both original gas inplace and injected gas?

If the reservoir contains both origi-nal gas in place and injected gas, whenyou produce gas from the reservoir youmust use an MMS-approved formula todetermine the amounts of injected orstored gas and gas original to the res-ervoir.

§ 250.122 What effect does subsurfacestorage have on the lease term?

If you use a lease area for subsurfacestorage of gas, it does not affect thecontinuance or expiration of the lease.

§ 250.123 Will MMS allow gas storageon unleased lands?

You may not store gas on unleasedlands unless the Regional Supervisorapproves a right-of-use and easementfor that purpose, under §§ 250.160through 250.166 of this subpart.

§ 250.124 Will MMS approve gas injec-tion into the cap rock containing asulphur deposit?

To receive the Regional Supervisor’sapproval to inject gas into the cap rockof a salt dome containing a sulphur de-posit, you must show that the injec-tion:

(a) Is necessary to recover oil and gascontained in the cap rock; and

(b) Will not significantly increase po-tential hazards to present or futuresulphur mining operations.

INSPECTION OF OPERATIONS

§ 250.130 Why does MMS conduct in-spections?

MMS will inspect OCS facilities andany vessels engaged in drilling or otherdownhole operations. These include fa-cilities under jurisdiction of other Fed-eral agencies that we inspect by agree-ment. We conduct these inspections:

(a) To verify that you are conductingoperations according to the Act, theregulations, the lease, right-of-way,the approved Exploration Plan or De-velopment and Production Plans; orright-of-use and easement, and otherapplicable laws and regulations; and

(b) To determine whether equipmentdesigned to prevent or ameliorateblowouts, fires, spillages, or othermajor accidents has been installed andis operating properly according to therequirements of this part.

§ 250.131 Will MMS notify me beforeconducting an inspection?

MMS conducts both scheduled andunscheduled inspections.


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§ 250.132 What must I do when MMSconducts an inspection?

(a) When MMS conducts an inspec-tion, you must provide:

(1) Access to all platforms, artificialislands, and other installations on yourleases or associated with your lease,right-of-use and easement, or right-of-way; and

(2) Helicopter landing sites and re-fueling facilities for any helicopters weuse to regulate offshore operations.

(b) You must make the followingavailable for us to inspect:

(1) The area covered under a lease,right-of-use and easement, right-of-way, or permit;

(2) All improvements, structures, andfixtures on these areas; and

(3) All records of design, construc-tion, operation, maintenance, repairs,or investigations on or related to thearea.

§ 250.133 Will MMS reimburse me formy expenses related to inspections?

Upon request, MMS will reimburseyou for food, quarters, and transpor-tation that you provide for MMS rep-resentatives while they inspect leasefacilities and operations. You mustsend us your reimbursement requestwithin 90 days of the inspection.

DISQUALIFICATION

§ 250.135 What will MMS do if my oper-ating performance is unacceptable?

If your operating performance is un-acceptable, MMS may disapprove or re-voke your designation as operator on asingle facility or multiple facilities. Wewill give you adequate notice and op-portunity for a review by MMS officialsbefore imposing a disqualification.

§ 250.136 How will MMS determine ifmy operating performance is unac-ceptable?

In determining if your operating per-formance is unacceptable, MMS willconsider, individually or collectively:

(a) Accidents and their nature;(b) Pollution events, environmental

damages and their nature;(c) Incidents of noncompliance;(d) Civil penalties;(e) Failure to adhere to OCS lease ob-

ligations; or(f) Any other relevant factors.

SPECIAL TYPES OF APPROVALS

§ 250.140 When will I receive an oralapproval?

When you apply for MMS approval ofany activity, we normally give you awritten decision. The following tableshows circumstances under which wemay give an oral approval.

When you We may And

(a) Request approvalorally.

Give you an oral ap-proval.

You must then confirm the oral request by sending us a written requestwithin 72 hours.

(b) Request approval inwriting.

Give you an oral ap-proval if quick actionis needed.

We will send you a written approval afterward. It will include any condi-tions that we place on the oral approval.

(c) Request approvalorally for gas flaring.

Give you an oral ap-proval.

You don’t have to follow up with a written request unless the RegionalSupervisor requires it. When you stop the approved flaring, you mustpromptly send a letter summarizing the location, dates and hours, andvolumes of liquid hydrocarbons produced and gas flared by the ap-proved flaring. (See 30 CFR 250, subpart K.)

§ 250.141 May I ever use alternate pro-cedures or equipment?

You may use alternate procedures orequipment after receiving approval asdescribed in this section.

(a) Any alternate procedures orequipment that you propose to usemust provide a level of safety and envi-ronmental protection that equals orsurpasses current MMS requirements.

(b) You must receive the District orRegional Supervisor’s written approvalbefore you can use alternate proce-dures or equipment.

(c) To receive approval, you must ei-ther submit information or give an oralpresentation to the appropriate Super-visor. Your presentation must describethe site-specific application(s), per-formance characteristics, and safety


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30 CFR Ch. II (7–1–01 Edition)§ 250.142

features of the proposed procedure orequipment.

§ 250.142 How do I receive approvalfor departures?

We may approve departures to theoperating requirements. You mayapply for a departure by writing to theDistrict or Regional Supervisor.

[65 FR 6536, Feb. 10, 2000]

§ 250.143 How do I designate an oper-ator?

(a) You must provide the RegionalSupervisor an executed Designation ofOperator form unless you are the onlylessee and are the only person con-ducting lease operations. When there ismore than one lessee, each lessee mustsubmit the Designation of Operatorform and the Regional Supervisor mustapprove the designation before the des-ignated operator may begin operationson the leasehold.

(b) This designation is authority forthe designated operator to act on yourbehalf and to fulfill your obligationsunder the Act, the lease, and the regu-lations in this part.

(c) You, or your designated operator,must immediately provide the Re-gional Supervisor a written notifica-tion of any change of address.

§ 250.144 How do I designate a new op-erator when a designation of oper-ator terminates?

(a) When a Designation of Operatorterminates, the Regional Supervisormust approve a new designated oper-ator before you may continue oper-ations. Each lessee must submit a newexecuted Designation of Operator form.

(b) If your Designation of Operator isterminated, or a controversy developsbetween you and your designated oper-ator, you and your designated operatormust protect the lessor’s interests.

§ 250.145 How do I designate an agentor a local agent?

(a) You or your designated operatormay designate for the Regional Super-visor’s approval, or the Regional Direc-tor may require you to designate anagent empowered to fulfill your obliga-tions under the Act, the lease, or theregulations in this part.

(b) You or your designated operatormay designate for the Regional Super-visor’s approval a local agent empow-ered to receive notices and submit re-quests, applications, notices, or supple-mental information.

§ 250.146 Who is responsible for ful-filling leasehold obligations?

(a) When you are not the sole lessee,you and your co-lessee(s) are jointlyand severally responsible for fulfillingyour obligations under the provisionsof 30 CFR parts 250 through 282, unlessotherwise provided in these regula-tions.

(b) If your designated operator failsto fulfill any of your obligations under30 CFR parts 250 through 282, the Re-gional Supervisor may require you orany or all of your co-lessees to fulfillthose obligations or other operationalobligations under the Act, the lease, orthe regulations.

(c) Whenever the regulations in 30CFR parts 250 through 282 require thelessee to meet a requirement or per-form an action, the lessee, operator (ifone has been designated), and the per-son actually performing the activity towhich the requirement applies arejointly and severally responsible forcomplying with the regulation.

NAMING AND IDENTIFYING FACILITIESAND WELLS (DOES NOT INCLUDE MODUS)

§ 250.150 How do I name facilities andwells in the Gulf of Mexico Region?

(a) Assign each facility a letter des-ignation except for those types of fa-cilities identified in paragraph (c)(1) ofthis section. For example, A, B, CA, orCB.

(1) After a facility is installed, re-name each predrilled well that was as-signed only a number and was sus-pended temporarily at the mudline orat the surface. Use a letter and numberdesignation. The letter used must bethe same as that of the production fa-cility, and the number used must cor-respond to the order in which the wellwas completed, not necessarily thenumber assigned when it was drilled.For example, the first well completedfor production on Facility A would berenamed Well A–1, the second would beWell A–2, and so on; and


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(2) When you have more than one fa-cility on a block, each facility in-stalled, and not bridge-connected toanother facility, must be named usinga different letter in sequential order.For example, EC 222A, EC 222B, EC222C.

(3) When you have more than one fa-cility on multiple blocks in a localarea being co-developed, each facilityinstalled and not connected with awalkway to another facility should benamed using a different letter in se-quential order with the block numbercorresponding to the block on whichthe platform is located. For example,EC 221A, EC 222B and EC 223C.

(b) In naming multiple well caissons,you must assign a letter designation.

(c) In naming single well caissons,you must use certain criteria as fol-lows:

(1) For single well caissons not at-tached to a facility with a walkway,use the well designation. For example,Well No. 1;

(2) For single well caissons attachedto a facility with a walkway, use thesame designation as the facility. Forexample, rename Well No.10 as A–10;and

(3) For single well caissons with pro-duction equipment, use a letter des-ignation for the facility name and aletter plus number designation for thewell. For example, the Well No. 1 cais-son would be designated as Facility A,and the well would be Well A–1.

§ 250.151 How do I name facilities inthe Pacific Region?

The operator assigns a name to thefacility.

§ 250.152 How do I name facilities inthe Alaska Region?

Facilities will be named and identi-fied according to the Regional Direc-tor’s directions.

§ 250.153 Do I have to rename an exist-ing facility or well?

You do not have to rename facilitiesinstalled and wells drilled before Janu-ary 27, 2000, unless the Regional Direc-tor requires it.

§ 250.154 What identification signsmust I display?

(a) You must identify all facilities,artificial islands, and mobile offshoredrilling units with a sign maintained ina legible condition.

(1) You must display an identifica-tion sign that can be viewed from thewaterline on at least one side of theplatform. The sign must use at least 3-inch letters and figures.

(2) When helicopter landing facilitiesare present, you must display an addi-tional identification sign that is visiblefrom the air. The sign must use atleast 12-inch letters and figures andmust also display the weight capacityof the helipad unless noted on the topof the helipad. If this sign is visible toboth helicopter and boat traffic, thenthe sign in paragraph (a)(1) of this sec-tion is not required.

(3) Your identification sign must:(i) List the name of the lessee or des-

ignated operator;(ii) In the GOM OCS Region, list the

area designation or abbreviation andthe block number of the facility loca-tion as depicted on OCS Official Pro-traction Diagrams or leasing maps;

(iii) In the Pacific OCS Region, listthe lease number on which the facilityis located; and

(iv) List the name of the platform,structure, artificial island, or mobileoffshore drilling unit.

(b) You must identify singly com-pleted wells and multiple completionsas follows:

(1) For each singly completed well,list the lease number and well numberon the wellhead or on a sign affixed tothe wellhead;

(2) For wells with multiple comple-tions, downhole splitter wells, and mul-tilateral wells, identify each comple-tion in addition to the well name andlease number individually on the wellflowline at the wellhead; and

(3) For subsea wells that flow individ-ually into separate pipelines, affix therequired sign on the pipeline or surfaceflowline dedicated to that subsea wellat a convenient location on the receiv-ing platform. For multiple subsea wellsthat flow into a common pipeline orpipelines, no sign is required.


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30 CFR Ch. II (7–1–01 Edition)§ 250.160

RIGHT-OF-USE AND EASEMENT

§ 250.160 When will MMS grant me aright-of-use and easement, andwhat requirements must I meet?

MMS may grant you a right-of-useand easement on leased and unleasedlands on the OCS, if you meet these re-quirements:

(a) You must need the right-of-useand easement to construct and main-tain platforms, artificial islands, andinstallations and other devices at anOCS site other than an OCS lease youown, that are:

(1) Permanently or temporarily at-tached to the seabed; and

(2) Used for conducting exploration,development, and production activitiesor other operations on or off lease; or

(3) Used for other purposes approvedby MMS.

(b) You must exercise the right-of-use and easement according to the reg-ulations of this part;

(c) You must meet the requirementsat 30 CFR 256.35 (Qualification of les-sees); establish a regional CompanyFile as required by MMS; and mustmeet bonding requirements;

(d) If you apply for a right-of-use andeasement on a leased area, you mustnotify the lessee and give her/him anopportunity to comment on your appli-cation; and

(e) You must receive MMS approvalfor all platforms, artificial islands, andinstallations and other devices perma-nently or temporarily attached to theseabed.

§ 250.161 What else must I submit withmy application?

With your application, you must de-scribe the proposed use giving:

(a) Details of the proposed uses andactivities including access needs andspecial rights of use that you mayneed;

(b) A description of all facilities forwhich you are seeking authorization;

(c) A map or plat describing primaryand alternate project locations; and

(d) A schedule for constructing anynew facilities, drilling or completingany wells, anticipated productionrates, and productive life of existingproduction facilities.

§ 250.162 May I continue my right-of-use and easement after the termi-nation of any lease on which it issituated?

If your right-of-use and easement ison a lease, you may continue to exer-cise the right-of-use and easementafter the lease on which it is situatedterminates. You must only use theright-of-use and easement for the pur-pose that the grant specifies. All futurelessees of that portion of the OCS onwhich your right-of-use and easementis situated must continue to recognizethe right-of-use and easement for thepurpose that the grant specifies.

§ 250.163 If I have a State lease, willMMS grant me a right-of-use andeasement?

(a) MMS may grant a lessee of aState lease located adjacent to or ac-cessible from the OCS a right-of-useand easement on the OCS.

(b) MMS will only grant a right-of-use and easement under this paragraphto enable a State lessee to conduct andmaintain a device that is permanentlyor temporarily attached to the seabed(i.e., a platform, artificial island, or in-stallation). The lessee must use the de-vice to explore for, develop, andproduce oil and gas from the adjacentor accessible State lease and for otheroperations related to these activities.

§ 250.164 If I have a State lease, whatconditions apply for a right-of-useand easement?

(a) A right-of-use and easementgranted under the heading of ‘‘Right-of-use and easement’’ in this subpart issubject to MMS regulations, 30 CFRparts 250 through 282, and any termsand conditions that the Regional Di-rector prescribes.

(b) For the whole or fraction of thefirst calendar year, and annually afterthat, you must pay to MMS, in ad-vance, an annual rental payment.

§ 250.165 If I have a State lease, whatfees do I have to pay for a right-of-use and easement?

When you apply for a right-of-use andeasement, you must pay:

(a) A nonrefundable filing fee as spec-ified in § 250.1010(a); and


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(b) The first year’s rental as specifiedin § 250.1009(c)(2).

§ 250.166 If I have a State lease, whatsurety bond must I have for a right-of-use and easement?

(a) Before MMS issues you a right-of-use and easement on the OCS, youmust furnish the Regional Director asurety bond for $500,000.

(b) The Regional Director may re-quire additional security from you (i.e.,security above the prescribed $500,000)to cover additional costs and liabilitiesfor regulatory compliance. This addi-tional surety:

(1) Must be in the form of a supple-mental bond or bonds meeting the re-quirements of § 256.54 (General require-ments for bonds) or an increase in thecoverage of an existing surety bond.

(2) Covers additional costs and liabil-ities for regulatory compliance, includ-ing well abandonment, platform andstructure removal, and site clearancefrom the seafloor of the right-of-useand easement.

SUSPENSIONS

§ 250.168 May operations or produc-tion be suspended?

(a) You may request approval of asuspension, or the Regional Supervisormay direct a suspension (Directed Sus-pension), for all or any part of a leaseor unit area.

(b) Depending on the nature of thesuspended activity, suspensions are la-beled either Suspensions of Operations(SOO) or Suspensions of Production(SOP).

§ 250.169 What effect does suspensionhave on my lease?

(a) A suspension may extend theterm of a lease (see § 250.180(b)). The ex-tension is equal to the length of timethe suspension is in effect, except asprovided in paragraph (b) of this sec-tion.

(b) A Directed Suspension does notextend the term of a lease when the Re-gional Supervisor directs a suspensionbecause of:

(1) Gross negligence; or(2) A willful violation of a provision

of the lease or governing statutes andregulations.

§ 250.170 How long does a suspensionlast?

(a) MMS may issue suspensions forup to 5 years per suspension. The Re-gional Supervisor will set the length ofthe suspension based on the conditionsof the individual case involved. MMSmay grant consecutive suspension peri-ods.

(b) An SOO ends automatically whenthe suspended operation commences.

(c) An SOP ends automatically whenproduction begins.

(d) A Directed Suspension normallyends as specified in the letter directingthe suspension.

(e) MMS may terminate any suspen-sion when the Regional Supervisor de-termines the circumstances that justi-fied the suspension no longer exist orthat other lease conditions warranttermination. The Regional Supervisorwill notify you of the reasons for ter-mination and the effective date.

§ 250.171 How do I request a suspen-sion?

You must submit your request for asuspension to the Regional Supervisor,and MMS must receive the request be-fore the end of the lease term (i.e., endof primary term, end of the 180-day pe-riod following the last leaseholding op-eration, and end of a current suspen-sion).

(a) The justification for the suspen-sion including the length of suspensionrequested;

(b) A reasonable schedule of workleading to the commencement or res-toration of the suspended activity;

(c) A statement that a well has beendrilled on the lease and determined tobe producible according to §§ 250.115,250.116, or 250.1603 (SOP only); and

(d) A commitment to production(SOP only).

§ 250.172 When may the Regional Su-pervisor grant or direct an SOO orSOP?

The Regional Supervisor may grantor direct an SOO or SOP under any ofthe following circumstances:


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30 CFR Ch. II (7–1–01 Edition)§ 250.173

(a) When necessary to comply withjudicial decrees prohibiting any activi-ties or the permitting of those activi-ties. The effective date of the suspen-sion will be the effective date requiredby the action of the court;

(b) When activities pose a threat ofserious, irreparable, or immediateharm or damage. This would include athreat to life (including fish and otheraquatic life), property, any mineral de-posit, or the marine, coastal, or humanenvironment. MMS may require you todo a site-specific study. (See§ 250.177(a).)

(c) When necessary for the installa-tion of safety or environmental protec-tion equipment;

(d) When necessary to carry out therequirements of NEPA or to conduct anenvironmental analysis; or

(e) When necessary to allow for inor-dinate delays encountered in obtainingrequired permits or consents, includingadministrative or judicial challengesor appeals.

§ 250.173 When may the Regional Su-pervisor direct an SOO or SOP?

The Regional Supervisor may directa suspension when:

(a) You failed to comply with an ap-plicable law, regulation, order, or pro-vision of a lease or permit; or

(b) The suspension is in the interestof national security or defense.

§ 250.174 When may the Regional Su-pervisor grant or direct an SOP?

The Regional Supervisor may grantor direct an SOP when the suspensionis in the national interest, and it isnecessary because the suspension willmeet one of the following criteria:

(a) It will allow you to properly de-velop a lease, including time to con-struct and install production facilities;

(b) It will allow you time to obtainadequate transportation facilities;

(c) It will allow you time to enter asales contract for oil, gas, or sulphur.You must show that you are making aneffort to enter into the contract(s); or

(d) It will avoid continued operationsthat would result in premature aban-donment of a producing well(s).

§ 250.175 When may the Regional Su-pervisor grant an SOO?

The Regional Supervisor may grantan SOO when necessary to allow youtime to begin drilling or other oper-ations when you are prevented by rea-sons beyond your control, such as un-expected weather, unavoidable acci-dents, or drilling rig delays.

§ 250.176 Does a suspension affect myroyalty payment?

A directed suspension may affect thepayment of rental or royalties for thelease as provided in § 218.154.

§ 250.177 What additional require-ments may the Regional Supervisororder for a suspension?

If MMS grants or directs a suspen-sion under paragraph § 250.172(b), theRegional Supervisor may require youto:

(a) Conduct a site-specific study.(1) The Regional Supervisor must ap-

prove or prescribe the scope for anysite-specific study that you perform.

(2) The study must evaluate thecause of the hazard, the potential dam-age, and the available mitigationmeasures.

(3) You must pay for the study unlessyou request, and the Regional Super-visor agrees to arrange, payment byanother party.

(4) You must furnish copies and re-sults of the study to the Regional Su-pervisor.

(5) MMS will make the results avail-able to other interested parties and tothe public.

(6) The Regional Supervisor will usethe results of the study and any otherinformation that becomes available:

(i) To decide if the suspension can belifted; and

(ii) To determine any actions thatyou must take to mitigate or avoid anydamage to the environment, life, orproperty.

(b) Submit a revised ExplorationPlan (including any required miti-gating measures);

(c) Submit a revised Developmentand Production Plan (including any re-quired mitigating measures); or

(d) Submit a revised DevelopmentOperations Coordination Document ac-cording to 30 CFR Part 250, subpart B.


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PRIMARY LEASE REQUIREMENTS, LEASETERM EXTENSIONS, AND LEASE CAN-CELLATIONS

§ 250.180 What am I required to do tokeep my lease term in effect?

(a) If your lease is in its primaryterm:

(1) You must submit a report to theDistrict Supervisor according to para-graphs (h) and (i) of this section when-ever production begins initially, when-ever production ceases during the last180 days of the primary term, andwhenever production resumes duringthe last 180 days of the primary term.

(2) Your lease expires at the end ofits primary term unless you are con-ducting operations on your lease (see 30CFR part 256). For purposes of this sec-tion, the term operations means, drill-ing, well-reworking, or production inpaying quantities. The objective of thedrilling or well-reworking must be toestablish production in paying quan-tities on the lease.

(b) If you stop conducting operationsduring the last 180 days of your pri-mary lease term, your lease will expireunless you either resume operations orreceive an SOO or an SOP from the Re-gional Supervisor under §§ 250.172,250.173, 250.174, or 250.175 before the endof the 180th day after you stop oper-ations.

(c) If you extend your lease termunder paragraph (b) of this section, youmust pay rental or minimum royalty,as appropriate, for each year or part ofthe year during which your lease con-tinues in force beyond the end of theprimary lease term.

(d) If you stop conducting operationson a lease that has continued beyondits primary term, your lease will expireunless you resume operations or re-ceive an SOO or an SOP from the Re-gional Supervisor under § 250.172,250.173, 250.174, or 250.175 before the endof the 180th day after you stop oper-ations.

(e) You may ask the Regional Super-visor to allow you more than 180 daysto resume operations on a lease contin-ued beyond its primary term when op-erating conditions warrant. The re-quest must be in writing and explainthe operating conditions that warranta longer period. In allowing additional

time, the Regional Supervisor must de-termine that the longer period is in thenational interest, and it conserves re-sources, prevents waste, or protectscorrelative rights.

(f) When you begin conducting oper-ations on a lease that has continuedbeyond its primary term, you must im-mediately notify the District Super-visor either orally or by fax or e-mailand follow up with a written report ac-cording to paragraph (g) of this sec-tion.

(g) If your lease is continued beyondits primary term, you must submit areport to the District Supervisor underparagraphs (h) and (i) of this sectionwhenever production begins initially,whenever production ceases, wheneverproduction resumes before the end ofthe 180-day period after having ceased,or whenever drilling or well-reworkingoperations begin before the end of the180-day period.

(h) The reports required by para-graphs (a) and (g) of this section mustcontain:

(1) Name of lessee or operator;(2) The well number, lease number,

area, and block;(3) As appropriate, the unit agree-

ment name and number; and(4) A description of the operation and

pertinent dates.(i) You must submit the reports re-

quired by paragraphs (a) and (g) of thissection within the following time-frames:

(1) Initialization of production—with-in 5 days of initial production.

(2) Cessation of production—within 15days after the first full month of zeroproduction.

(3) Resumption of production—within5 days of resuming production afterceasing production under paragraph(i)(2) of this section.

(4) Drilling or well reworking oper-ations—within 5 days of beginning andcompleting the leaseholding oper-ations.

(j) For leases continued beyond theprimary term, you must immediatelyreport to the District Supervisor if op-erations do not begin before the end ofthe 180-day period.


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30 CFR Ch. II (7–1–01 Edition)§ 250.181

§ 250.181 When may the Secretary can-cel my lease and when am I com-pensated for cancellation?

If the Secretary cancels your leaseunder this part or under 30 CFR part256, you are entitled to compensationunder § 250.184. Section 250.185 statesconditions under which you will re-ceive no compensation. The Secretarymay cancel a lease after notice and op-portunity for a hearing when:

(a) Continued activity on the leasewould probably cause harm or damageto life (including fish and other aquaticlife), property, any mineral deposits (inareas leased or not leased), or the ma-rine, coastal, or human environment;

(b) The threat of harm or damagewill not disappear or decrease to an ac-ceptable extent within a reasonable pe-riod of time;

(c) The advantages of cancellationoutweigh the advantages of continuingthe lease in force; and

(d) A suspension has been in effect forat least 5 years or you request termi-nation of the suspension and lease can-cellation.

§ 250.182 When may the Secretary can-cel a lease at the exploration stage?

MMS may not approve an explorationplan (EP) under 30 CFR part 250, sub-part B, if the Regional Supervisor de-termines that the proposed activitiesmay cause serious harm or damage tolife (including fish and other aquaticlife), property, any mineral deposits,the national security or defense, or tothe marine, coastal, or human environ-ment, and that the proposed activitycannot be modified to avoid the condi-tion(s). The Secretary may cancel thelease if:

(a) The primary lease term has notexpired (or if the lease term has beenextended) and exploration has beenprohibited for 5 years following the dis-approval; or

(b) You request cancellation at anearlier time.

§ 250.183 When may MMS or the Sec-retary extend or cancel a lease atthe development and productionstage?

(a) MMS may extend your lease ifyou submit a DPP and the RegionalSupervisor disapproves the plan ac-

cording to the regulations in 30 CFRpart 250, subpart B. Following the dis-approval:

(1) MMS will allow you to hold thelease for 5 years, or less time at yourrequest;

(2) Any time within 5 years after thedisapproval, you may reapply for ap-proval of the same or a modified plan;and

(3) The Regional Supervisor will ap-prove, disapprove, or require modifica-tion of the plan under 30 CFR part 250,subpart B.

(b) If the Regional Supervisor has notapproved a DPP or required you to sub-mit a DPP for approval or modifica-tion, the Secretary will cancel thelease:

(1) When the 5-year period in para-graph (a)(1) of this section expires; or

(2) If you request cancellation at anearlier time.

§ 250.184 What is the amount of com-pensation for lease cancellation?

When the Secretary cancels a leaseunder §§ 250.181, 250.182 or 250.183 of thissubpart, you are entitled to receivecompensation under 43 U.S.C. 1334(a)(2)(C). You must show the Directorthat the amount of compensationclaimed is the lesser of paragraph (a) or(b) of this section:

(a) The fair value of the cancelledrights as of the date of cancellation,taking into account both:

(1) Anticipated revenues from thelease; and

(2) Costs reasonably anticipated onthe lease, including:

(i) Costs of compliance with all appli-cable regulations and operating orders;and

(ii) Liability for cleanup costs ordamages, or both, in the case of an oilspill.

(b) The excess, if any, over your reve-nues from the lease (plus interestthereon from the date of receipt todate of reimbursement) of:

(1) All consideration paid for thelease (plus interest from the date ofpayment to the date of reimburse-ment); and

(2) All your direct expenditures (plusinterest from the date of payment tothe date of reimbursement):


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(i) After the issue date of the lease;and

(ii) For exploration or development,or both.

(c) Compensation for leases issued be-fore September 18, 1978, will be equal tothe amount specified in paragraph (a)of this section.

§ 250.185 When is there no compensa-tion for a lease cancellation?

You will not receive compensationfrom MMS for lease cancellation if:

(a) MMS disapproves a DPP becauseyou do not receive concurrence by theState under section 307(c)(3)(B) (i) or(ii) of the CZMA, and the Secretary ofCommerce does not make the findingauthorized by section 307(c)(3)(B)(iii) ofthe CZMA;

(b) You do not submit a DPP under 30CFR part 250, subpart B or do not com-ply with the approved DPP;

(c) As the lessee of a nonproducinglease, you fail to comply with the Act,the lease, or the regulations issuedunder the Act, and the default con-tinues for 30 days after MMS mails youa notice by overnight mail;

(d) The Regional Supervisor dis-approves a DPP because you fail tocomply with the requirements of appli-cable Federal law; or

(e) The Secretary forfeits and cancelsa producing lease under section 5(d) ofthe Act (43 U.S.C. 1334(d)).

INFORMATION AND REPORTINGREQUIREMENTS

§ 250.190 What reporting informationand report forms must I submit?

(a) You must submit information andreports as MMS requires.

(1) You may obtain copies of formsfrom, and submit completed forms to,the Regional or District Supervisor.

(2) Instead of paper copies of formsavailable from the Regional or DistrictSupervisor, you may use your owncomputer-generated forms that areequal in size to MMS’s forms. Youmust arrange the data on your formidentical to the MMS form. If you gen-erate your own form and it omitsterms and conditions contained on theofficial MMS form, we will consider itto contain the omitted terms and con-ditions.

(3) You may submit digital data whenthe Region/District is equipped to ac-cept it.

(b) When MMS specifies, you must in-clude, for public information, an addi-tional copy of such reports.

(1) You must mark it Public Informa-tion.

(2) You must include all required in-formation, except information exemptfrom public disclosure under § 250.196 orotherwise exempt from public disclo-sure under law or regulation.

§ 250.191 What accident reports must Isubmit?

(a) You must notify the District Su-pervisor of all serious accidents, anydeath or serious injury, and all fires,explosions, and blowouts connectedwith any activities or operations onthe lease. You must report all spills ofoil or other liquid pollutants accordingto 30 CFR part 254.

(b) If you hold an easement, right-of-way, or other permit, and your oper-ation is related to the exercise of theeasement, right-of-way, or other per-mit, you must comply with paragraph(a) by notifying and reporting to theRegional Supervisor any accidents oc-curring on the area covered by theeasement, right-of-way, or other per-mit.

(c) Any investigation that the Sec-retary or the U.S. Coast Guard (USCG)conducts under the authority of sec-tions 22(d)(1) and (2) of the Act (43U.S.C. 1348 d(1) and (2)), is a fact-find-ing proceeding with no civil or crimi-nal issues and no adverse parties. Thepurpose of the investigation is to pre-pare a public report that determinesthe cause or causes of the accident.The investigation may involve panelmeetings conducted by a chairpersonappointed by MMS. The following re-quirements must be met for any panelmeetings involving persons giving tes-timony:

(1) A person giving testimony mayhave legal and/or other representa-tive(s) present to provide advice orcounsel while the person is giving tes-timony. The chairperson may require averbatim transcript to be made of alloral testimony. The chairperson alsomay accept a sworn written statementin lieu of oral testimony.


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30 CFR Ch. II (7–1–01 Edition)§ 250.192

(2) Only panel members, panel’s legaladvisors, and any experts the paneldeems necessary may address questionsto any person giving testimony.

(3) The chairperson may issue sub-poenas to persons to appear and pro-vide testimony and/or documents at apanel meeting. A subpoena may not re-quire a person to attend a panel meet-ing held at a location more than 100miles from where a subpoena is served.

(4) Any person giving testimony mayrequest compensation for mileage andfees for service within 90 days after thepanel meeting. The compensated ex-penses must be similar to mileage andfees the U.S. District Courts allow.

§ 250.192 What evacuation statisticsmust I submit?

You must submit evacuation statis-tics to the Regional Supervisor for anatural occurrence such as an earth-quake or hurricane. MMS will notifylocal and national authorities and thepublic, as appropriate. Statistics in-clude facilities and rigs evacuated andamount of production shut-in for gasand oil. You must:

(a) Submit the statistics by fax or e-mail as soon as possible when evacu-ation occurs;

(b) Submit statistics on a daily basisby 11:00 a.m., as conditions allow, dur-ing the period of shut-in and evacu-ation;

(c) Inform MMS when you resumeproduction; and

(d) Submit statistics either by MMSdistrict or the total figures for your op-erations in the Region.

§ 250.193 Reports and investigations ofapparent violations.

Any person may report to MMS anapparent violation or failure to complywith any provision of the Act, any pro-vision of a lease, license, or permitissued under the Act, or any provisionof any regulation or order issued underthe Act. When MMS receives a reportof an apparent violation, or when anMMS employee detects an apparentviolation after making an initial deter-mination of the validity, MMS will in-vestigate according to MMS proce-dures.

§ 250.194 What archaeological reportsand surveys must I submit?

(a) If it is likely that an archae-ological resource exists in the leasearea, the Regional Director will notifyyou in writing. You must include anarchaeological report in the EP orDPP. If the archaeological report sug-gests that an archaeological resourcemay be present, you must either:

(1) Locate the site of any operationso as not to adversely affect the areawhere the archaeological resource maybe; or

(2) Establish to the satisfaction ofthe Regional Director that an archae-ological resource does not exist or willnot be adversely affected by oper-ations. This requires further archae-ological investigation, conducted by anarchaeologist and a geophysicist, usingsurvey equipment and techniques theRegional Director considers appro-priate. You must submit the investiga-tion report to the Regional Director forreview.

(b) If the Regional Director deter-mines that an archaeological resourceis likely to be present in the lease areaand may be adversely affected by oper-ations, the Regional Director will no-tify you immediately. You must nottake any action that may adversely af-fect the archaeological resource untilthe Regional Director has told you howto protect the resource.

(c) If you discover any archaeologicalresource while conducting operationsin the lease area, you must imme-diately halt operations within the areaof the discovery and report the dis-covery to the Regional Director. If in-vestigations determine that the re-source is significant, the Regional Di-rector will tell you how to protect it.

§ 250.195 Reimbursements for repro-duction and processing costs.

(a) MMS will reimburse you for costsof reproducing data and informationthat the Regional Director requests if:

(1) You deliver geophysical and geo-logical (G&G) data and information toMMS for the Regional Director to in-spect or select and retain;

(2) MMS receives your request for re-imbursement and the Regional Direc-tor determines that the requested re-imbursement is proper; and


265


(3) The cost is at your lowest rate orat the lowest commercial rate estab-lished in the area, whichever is less.

(b) MMS will reimburse you for thecosts of processing geophysical infor-mation (that does not include cost ofdata acquisition):

(1) If, at the request of the RegionalDirector, you processed the geo-physical data or information in a formor manner other than that used in thenormal conduct of business; or

(2) If you collected the informationunder a permit that MMS issued to youbefore October 1, 1985, and the RegionalDirector requests and retains the infor-mation.

(c) When you request reimbursement,you must identify reproduction andprocessing costs separately from acqui-sition costs.

(d) MMS will not reimburse you fordata acquisition costs or for the costsof analyzing or processing geologicalinformation or interpreting geologicalor geophysical information.

§ 250.196 Data and information to bemade available to the public.

MMS will protect data and informa-tion you submit under this part, as de-scribed in this section. The tables inparagraphs (a) and (b) of this sectiondescribe what data and informationwill be made available to the publicwithout the consent of the lessee andunder what circumstances and in whattime period.

(a) MMS will disclose data and infor-mation you submit on MMS forms ac-cording to the following table:

Data and informationthat you submit on form In the following items Will be released And

(1) MMS–123, Applica-tion for Permit to Drill.

All entries except items17, 24, and 25.

At any time ................... The data and information in items 17, 24, and25 will be released according to the table inparagraph (b) of this section or when the wellgoes on production, whichever is earlier.

(2) MMS–124, SundryNotices and Reportson Wells.

All entries except item36.

At any time ................... The data and information in item 36 will be re-leased according to the table in paragraph (b)or when the well goes on production, which-ever is earlier.

(3) MMS–125, WellSummary Report.

All entries except items17, 24, 34, 37, and46 through 87.

At any time ................... The data and information in the excepted itemswill be released according to the table inparagraph (b) of this section or when the wellgoes on production, whichever is earlier.However, items 78 through 87 will not be re-leased when the well goes on production un-less the period of time in the table in para-graph (b) has expired

(4) MMS–126, Well Po-tential Test Report.

All entries except item101.

When the well goes onproduction.

The data and information in item 101 will be re-leased 2 years after you submit it.

(5) MMS–127, Requestfor Reservoir Max-imum Efficient Rate(MER).

All entries except items124 through 168.

At any time ................... The data and information in items 124 through168 will be released according to the time pe-riods in the table in paragraph (b) of this sec-tion.

(6) MMS–128, Semi-annual Well Test Re-port.

All entries ...................... At any time.

(b) MMS will disclose lease data andinformation that you submit, but that

are not usually submitted on MMSforms, according to the following table:

If MMS will release At this time Special provisions

(1) The Director determines that dataand information are needed to unitizeoperations on two or more leases, todetermine whether a reservoir is com-petitive to ensure proper plans of de-velopment for competitive reservoirs,or to promote operational safety orprotect the environment.

Geophysical data,Geological data,Interpreted (G&G)information, Proc-essed G&G infor-mation, Analyzedgeological infor-mation.

At any time ............. Data and information will be shown onlyto persons with an interest in theissue.


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30 CFR Ch. II (7–1–01 Edition)§ 250.198

If MMS will release At this time Special provisions

(2) The Director determines that dataand information are needed for spe-cific scientific or research purposes forthe Government.

Geophysical data,Geological dataInterpreted G&Ginformation, Proc-essed G&G infor-mation, Analyzedgeological infor-mation.

At any time ............. MMS will release data and informationonly if release would further the na-tional interest without unduly dam-aging the competitive position of thelessee.

(3) Data or information is collected withhigh-resolution systems (e.g., bathym-etry, side-scan sonar, subbottom pro-filer, and magnetometer) to complywith safety or environmental protectionrequirements.

Geophysical data,Geological data,Interpreted G&Ginformation, Proc-essed geologicalinformation, Ana-lyzed geologicalinformation.

60 days after MMSreceives the dataor information, ifthe Regional Su-pervisor deems itnecessary.

MMS will release the data and informa-tion earlier than 60 days if the Re-gional Supervisor determines it isneeded by affected States to makedecisions under subpart B. The Re-gional Supervisor will reconsider ear-lier release if you satisfy him/her thatit would unduly damage your com-petitive position.

(4) Your lease is no longer in effect ........ Geophysical data,Geological data,Processed G&Ginformation Inter-preted G&G infor-mation, Analyzedgeological infor-mation.

When your leaseterminates.

This release time applies only if the pro-visions in this table governing high-resolution systems and the provisionsin § 252.7 do not apply. The releasetime applies to the geophysical dataand information only if acquiredpostlease for a lessee’s exclusiveuse.

(5) Your lease is still in effect .................. Geophysical dataProcessed geo-physical informa-tion, InterpretedG&G information.

10 years after yousubmit the dataand information.

This release time applies only if the pro-visions in this table governing high-resolution systems and the provisionsin § 252.7 do not apply. This releasetime applies to the geophysical dataand information only if acquiredpostlease for a lessee’s exclusiveuse.

(6) Your lease is still in effect and withinthe primary term specified in the lease.

Geological data,Analyzed geologi-cal information.

2 years after the re-quired submittaldate or 60 daysafter a lease saleif any portion ofan offered leaseis within 50 milesof a well, which-ever is later.

These release times apply only if theprovisions in this table governinghigh-resolution systems and the pro-visions in § 252.7 do not apply. If theprimary term specified in the lease isextended under the heading of ‘‘Sus-pensions’’ in this subpart, the exten-sion applies to this provision.

(7) Your lease is in effect and beyondthe primary term specified in the lease.

Geological data,Analyzed geologi-cal information.

2 years after the re-quired submittaldate.

None.

(8) Data is released to the owner of anadjacent lease under subpart D of part250.

Directional surveydata.

If the lessee fromwhose lease thedirectional surveywas taken con-sents.

None.

(9) Data and information are obtainedfrom beneath unleased land as a re-sult of a well deviation that has notbeen approved by the Regional or Dis-trict Supervisor.

Any data or infor-mation obtained.

At any time ............. None.

(10) Data and information acquired by apermit under part 251 is submitted bya lessee under part 250.

Geophysical data,Processed geo-physical informa-tion, Interpretedgeophysical infor-mation.

Geophysical data:50 years, Geo-physical informa-tion: 25 yearsafter you submit it.

None.

REFERENCES

§ 250.198 Documents incorporated byreference.

(a) MMS is incorporating by ref-erence the documents listed in thetable in paragraph (e) of this section.

The Director of the Federal Registerhas approved this incorporation by ref-erence according to 5 U.S.C. 552(a) and1 CFR part 51.

(1) MMS will publish any changes tothese documents in the FEDERAL REG-ISTER.


267


(2) MMS may make the rule amend-ing the document effective withoutprior opportunity for public commentwhen MMS determines:

(i) That the revisions to a documentresult in safety improvements or rep-resent new industry standard tech-nology and do not impose undue costson the affected parties; and

(ii) MMS meets the requirements formaking a rule immediately effectiveunder 5 U.S.C. 553.

(b) MMS incorporated each documentor specific portion by reference in thesections noted. The entire document isincorporated by reference, unless thetext of the corresponding sections inthis part calls for compliance with spe-cific portions of the listed documents.In each instance, the applicable docu-ment is the specific edition or specificedition and supplement or addendumcited in this section.

(c) Under §§ 250.141 and 250.142, youmay comply with a later edition of aspecific document incorporated by ref-erence, provided:

(1) You show that complying with thelater edition provides a degree of pro-tection, safety, or performance equalto or better than would be achieved bycompliance with the listed edition; and

(2) You obtain the prior written ap-proval for alternative compliance fromthe authorized MMS official.

(d) You may inspect these documentsat the Minerals Management Service,381 Elden Street, Room 3313, Herndon,Virginia; or at the Office of the FederalRegister, 800 North Capitol Street,NW., Suite 700, Washington, DC. Youmay obtain the documents from thepublishing organizations at the ad-dresses given in the following table:

For Write to

ACI Standards ............................................ American Concrete Institute, P. O. Box 19150, Detroit, MI 48219.AISC Standards .......................................... American Institute of Steel Construction, Inc., P.O. Box 4588, Chicago, IL 60680.ANSI/ASME Codes ..................................... American National Standards Institute, Attention Sales Department, 1430 Broad-

way, New York, NY 10018; and/or American Society of Mechanical Engineers,United Engineering Center, 345 East 47th Street, New York, NY 10017.

API Recommended Practices, Specs,Standards, Manual of Petroleum Meas-urement Standards (MPMS) chapters.

American Petroleum Institute, 1220 L Street, NW., Washington, DC 20005–4070.

ASTM Standards ........................................ American Society for Testing and Materials, 100 Barr Harbor Drive, WestConshohocken, PA 19428–2959.

AWS Codes ................................................ American Welding Society, 550 NW, LeJeune Road, P.O. Box 351040, Miami, FL33135.

NACE Standards ........................................ National Association of Corrosion Engineers, P.O. Box 218340, Houston, TX77218.

(e) This paragraph lists documentsincorporated by reference. To easilyreference text of the corresponding sec-tions with the list of documents incor-

porated by reference, the list is inalphanumerical order by organizationand document.

Title of documents Incorporated by reference at

ACI Standard 318–95, Building Code Requirements for Reinforced Concrete, plus Com-mentary on Building Code Requirements for Reinforced Concrete (ACI 318R–95).

§ 250.908(b)(4)(i), (b)(6)(i), (b)(7),(b)(8)(i), (b)(9), (b)(10), (c)(3),(d)(1)(v), (d)(5), (d)(6), (d)(7),(d)(8), (d)(9), (e)(1)(i), (e)(2)(i).

ACI Standard 357R–84, Guide for the Design and Construction of Fixed Offshore Con-crete Structures, 1984.

§ 250.900(g); § 250.908(c)(2), (c)(3).

AISC Standard Specification for Structural Steel Buildings, Allowable Stress Design andPlastic Design, June 1, 1989, with Commentary.

§ 250.907(b)(1)(ii), (c)(4)(ii), (c)(4)(vii).

ANSI/ASME Boiler and Pressure Vessel Code, Section I, Rules for Construction ofPower Boilers, including Appendices, 1998 Edition; July 1, 1999 Addenda, Rules forConstruction of Power Boilers, by ASME Boiler and Pressure Vessel Committee Sub-committee on Power Boilers; and all Section I Interpretations Volume 43.

§ 250.803(b)(1), (b)(1)(i);§ 250.1629(b)(1), (b)(1)(i).

ANSI/ASME Boiler and Pressure Vessel Code, Section IV, Rules for Construction ofHeating Boilers, including Nonmandatory Appendices A, B, C, D, E, F, H, I, K, and L,and the Guide to Manufacturers Data Report Forms, 1998 Edition; July 1, 1999 Ad-denda, Rules for Construction of Heating Boilers, by ASME Boiler and Pressure Ves-sel Committee Subcommittee on Heating Boilers; and all Section IV InterpretationsVolumes 43 and 44.

§ 250.803(b)(1), (b)(1)(i);§ 250.1629(b)(1), (b)(1)(i).


268

30 CFR Ch. II (7–1–01 Edition)§ 250.198


ANSI/ASME Boiler and Pressure Vessel Code, Section VIII, Rules for Construction ofPressure Vessels, Divisions 1 and 2, including Nonmandatory Appendices, 1998 Edi-tion; July 1, 1999 Addenda, Rules for Construction of Pressure Vessels, by ASMEBoiler and Pressure Vessel Committee Subcommittee on Pressure Vessels; and allSection VIII Interpretations, Divisions 1 and 2, Volumes 43 and 44.

§ 250.803(b)(1), (b)(1)(i);§ 250.1629(b)(1), (b)(1)(i).

ANSI/ASME B 16.5–1988 (including Errata) and B 16.5a–1992 Addenda, Pipe Flangesand Flanged Fittings.

§ 250.1002(b)(2).

ANSI/ASME B 31.8–1995, Gas Transmission and Distribution Piping Systems ................ § 250.1002(a).ANSI/ASME SPPE–1–1994 and SPPE–1d–1996 ADDENDA, Quality Assurance and

Certification of Safety and Pollution Prevention Equipment Used in Offshore Oil andGas Operations.

§ 250.806(a)(2)(i).

ANSI Z88.2–1992, American National Standard for Respiratory Protection ....................... § 250.417(g)(4)(iv), (j)(13)(ii).API MPMS, Chapter 1, Vocabulary, Second Edition, July 1994, API Stock No., H01002. § 250.1201.API MPMS, Chapter 2, Tank Calibration, Section 2A, Measurement and Calibration of

Upright Cylindrical Tanks by the Manual Strapping Method, First Edition, February1995, API Stock No. H022A1.

§ 250.1202(l)(4).

API MPMS, Chapter 2, Section 2B, Calibration of Upright Cylindrical Tanks Using theOptical Reference Line Method, First Edition, March 1989, reaffirmed May 1996, APIStock No. H30023; also available as ANSI/ASTM D 4738–88.

250.1202(l)(4).

API MPMS, Chapter 3, Tank Gauging, Section 1A, Standard Practice for the ManualGauging of Petroleum and Petroleum Products, First Edition, December 1994, APIStock No. H031A1.

§ 250.1202(l)(4).

API MPMS, Chapter 3, Section 1B, Standard Practice for Level Measurement of LiquidHydrocarbons in Stationary Tanks by Automatic Tank Gauging, First Edition, April1992, reaffirmed January 1997, API Stock No. H30060.

§ 250.1202(l)(4).

API MPMS, Chapter 4, Proving Systems, Section 1, Introduction, First Edition, July1988, reaffirmed October 1993, API Stock No. H30081.

§ 250.1202(a)(3), (f)(1).

API MPMS, Chapter 4, Section 2, Conventional Pipe Provers, First Edition, October1988, reaffirmed October 1993, API Stock No. H30082.

§ 250.1202(a)(3), (f)(1).

API MPMS, Chapter 4, Section 3, Small Volume Provers, First Edition, July 1988, re-affirmed October 1993, API Stock No. H30083.

§ 250.1202(a)(3), (f)(1).

API MPMS, Chapter 4, Section 4, Tank Provers, First Edition, October 1988, reaffirmedOctober 1993, API Stock No. H30084.

§ 250.1202(a)(3), (f)(1).

API MPMS, Chapter 4, Section 5, Master-Meter Provers, First Edition, October 1988, re-affirmed October 1993, API Stock No. H30085.

§ 250.1202(a)(3), (f)(1).

API MPMS, Chapter 4, Section 6, Pulse Interpolation, Second Edition, May 1999, APIStock No. H04062.

§ 250.1202(a)(3) and (f)(1).

API MPMS, Chapter 4, Section 7, Field Standard Test Measures, Second Edition, De-cember 1998, API Stock No. H04072.

§ 250.1202(a)(3) and (f)(1).

API MPMS, Chapter 5, Metering, Section 1, General Considerations for Measurementby Meters, Third Edition, September 1995, API Stock No. H05013.

§ 250.1202(a)(3).

API MPMS, Chapter 5, Section 2, Measurement of Liquid Hydrocarbons by Displace-ment Meters, Second Edition, November 1987, reaffirmed January 1997, API StockNo. H30102.

§ 250.1202(a)(3).

API MPMS, Chapter 5, Section 3, Measurement of Liquid Hydrocarbons by Turbine Me-ters, Third Edition, September 1995, API Stock No. H05033.

§ 250.1202(a)(3).

API MPMS, Chapter 5, Section 4, Accessory Equipment for Liquid Meters, Third Edition,September 1995, with Errata, March 1996, API Stock No. H05043.

§ 250.1202(a)(3).

API MPMS, Chapter 5, Section 5, Fidelity and Security of Flow Measurement Pulsed-Data Transmission Systems, First Edition, June 1982, reaffirmed January 1997, APIStock No. H30105.

§ 250.1202(a)(3).

API MPMS, Chapter 6, Metering Assemblies, Section 1, Lease Automatic CustodyTransfer (LACT) Systems, Second Edition, May 1991, reaffirmed July 1996, API StockNo. H30121.

§ 250.1202(a)(3).

API MPMS, Chapter 6, Section 6, Pipeline Metering Systems, Second Edition, May1991, reaffirmed July 1996, API Stock No. H30126.

§ 250.1202(a)(3).

API MPMS, Chapter 6, Section 7, Metering Viscous Hydrocarbons, Second Edition, May1991, reaffirmed July 1996, API Stock No. H30127.

§ 250.1202(a)(3).

API MPMS, Chapter 7, Temperature Determination, Section 2, Dynamic TemperatureDetermination, Second Edition, March 1995, API Stock No. H07022.

§ 250.1202(a)(3), (l)(4).

API MPMS, Chapter 7, Section 3, Static Temperature Determination Using PortableElectronic Thermometers, First Edition, July 1985, reaffirmed May 1996, API StockNo. H30143.

§ 250.1202(a)(3), (l)(4).

API MPMS, Chapter 8, Sampling, Section 1, Standard Practice for Manual Sampling ofPetroleum and Petroleum Products, Third Edition, October 1995; also available asANSI/ASTM D 4057–88, API Stock No. H30161.

§ 250.1202(b)(4)(i), (l)(4).

API MPMS, Chapter 8, Section 2, Standard Practice for Automatic Sampling of LiquidPetroleum and Petroleum Products, Second Edition, October 1995; also available asANSI/ASTM D 4177, API Stock No. H30162.

§ 250.1202(a)(3), (l)(4).

API MPMS, Chapter 9, Density Determination, Section 1, Hydrometer Test Method forDensity, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum andLiquid Petroleum Products, First Edition, June 1981, reaffirmed December 1998, APIStock No. H30181; also available as ANSI/ASTM D 1298.

§ 250.1202(a)(3) and (l)(4).


269



API MPMS, Chapter 9, Section 2, Pressure Hydrometer Test Method for Density or Rel-ative Density, First Edition, April 1982, reaffirmed December 1998, API Stock No.H30182.

§ 250.1202(a)(3) and (l)(4).

API MPMS, Chapter 10, Sediment and Water, Section 1, Determination of Sediment inCrude Oils and Fuel Oils by the Extraction Method, First Edition, April 1981, re-affirmed December 1993; also available as ANSI/ASTM D 473, API Stock No. H30201.

§ 250.1202(a)(3), (l)(4).

API MPMS, Chapter 10, Section 2, Determination of Water in Crude Oil by DistillationMethod, First Edition, April 1981, reaffirmed December 1993; also available as ANSI/ASTM D 4006, API Stock No. H30202.

§ 250.1202(a)(3), (l)(4).

API MPMS, Chapter 10, Section 3, Determination of Water and Sediment in Crude Oilby the Centrifuge Method (Laboratory Procedure), First Edition, April 1981, reaffirmedDecember 1993; also available as ANSI/ASTM D 4007, API Stock No. H30203.

§ 250.1202(a)(3), (l)(4).

API MPMS, Chapter 10, Section 4, Determination of Sediment and Water in Crude Oilby the Centrifuge Method (Field Procedure), Second Edition, May 1988, reaffirmedMay 1998; also available as ANSI/ASTM D 96, API Stock No. H30204.

§ 250.1202(a)(3), (l)(4).

API MPMS, Chapter 10, Section 9, Standard Test Method for Water in Crude Oils byCoulometric Karl Fischer Titration, First Edition, November 1993, API Stock No. 852–30210.

§ 250.1202(a)(3), (l)(4).

API MPMS, Chapter 11.1, Volume Correction Factors, Volume 1, Table 5A—General-ized Crude Oils and JP-4, Correction of Observed API Gravity to API Gravity at 60°F,and Table 6A—Generalized Crude Oils and JP–4, Correction of Volume to 60°F,against API Gravity 60°F, First Edition, August 1980, reaffirmed March 1997, APIStock No. H27000; also available as ANSI/ASTM D 1250.

§ 250.1202(a)(3), (g)(3) and (l)(4).

API MPMS, Chapter 11.2.1, Compressibility Factors for Hydrocarbons: 0–90° API Grav-ity Range, First Edition, August 1984, reaffirmed May 1996, API Stock No. H27300.

§ 250.1202(a)(3), (g)(4).

API MPMS, Chapter 11.2.2, Compressibility Factors for Hydrocarbons: 0.350–0.637 Rel-ative Density (60°F/60°F) and ¥50°F to 140°F Metering Temperature, Second Edi-tion, October 1986, reaffirmed March 1997, API Stock No. H27307; also available asGas Processors Association (GPA) 8286.

§ 250.1202(a)(3) and (g)(4).

API MPMS, Chapter 11, Physical Properties Data, Addendum to Section 2.2, Compress-ibility Factors for Hydrocarbons, Correlation of Vapor Pressure for Commercial NaturalGas Liquids, First Edition, December 1994, reaffirmed March 1997; also available asGPA TP–15, API Stock No. H27308.

§ 250.1202(a)(3).

API MPMS, Chapter 11.2.3, Water Calibration of Volumetric Provers, First Edition, Au-gust 1984, reaffirmed, May 1996, API Stock No. H27310.

§ 250.1202(f)(1).

API MPMS, Chapter 12, Calculation of Petroleum Quantities, Section 2, Calculation ofPetroleum Quantities Using Dynamic Measurement Methods and Volumetric Correc-tion Factors, Including Parts 1 and 2, Second Edition, May 1995; also available asANSI/API MPMS 12.2–1981, API Stock No. H30302.

§ 250.1202(a)(3), (g)(1), (g)(2).

API MPMS, Chapter 14, Natural Gas Fluids Measurement, Section 3, ConcentricSquare-Edged Orifice Meters, Part 1, General Equations and Uncertainty Guidelines,Third Edition, September 1990, reaffirmed August 1995; also available as ANSI/API2530, Part 1, 1991, API Stock No. H30350.

§ 250.1203(b)(2).

API MPMS, Chapter 14, Section 3, Part 2, Specification and Installation Requirements,Third Edition, February 1991, reaffirmed May 1996, API Stock No. H30351; also avail-able as ANSI/API 2530, 1991.

§ 250.1203(b)(2).

API MPMS, Chapter 14, Section 3, Part 3, Natural Gas Applications, Third Edition, Au-gust 1992, reaffirmed December 1998, API Stock No. H30353; also available as ANS/API 2530, Part 3.

§ 250.1203(b)(2).

API MPMS, Chapter 14, Section 5, Calculation of Gross Heating Value, Relative Den-sity, and Compressibility Factor for Natural Gas Mixtures from Compositional Analysis,Revised 1996; order from Gas Processors Association, 6526 East 60th Street, Tulsa,Oklahoma 74145.

§ 250.1203(b)(2).

API MPMS, Chapter 14, Section 6, Continuous Density Measurement, Second Edition,April 1991, reaffirmed May 1998, API Stock No. H30346.

§ 250.1203(b)(2).

API MPMS, Chapter 14, Section 8, Liquefied Petroleum Gas Measurement, Second Edi-tion, July 1997; reaffirmed May 1996, API Stock No. H14082.

§ 250.1203(b)(2).

API MPMS, Chapter 20, Section 1, Allocation Measurement, First Edition, September1993, API Stock No. H30730.

§ 250.1202(k)(1).

API MPMS, Chapter 21, Section 1, Electronic Gas Measurement, First Edition, Sep-tember 1993, API Stock No. H30730.

§ 250.1203(b)(4).

API RP 2A, Recommended Practice for Planning, Designing and Constructing Fixed Off-shore Platforms Working Stress Design, Nineteenth Edition, August 1, 1991, APIStock No. 811–00200.

§ 250.900(g); § 250.912(a).

API RP 2A–WSD, Recommended Practice for Planning, Designing and ConstructingFixed Offshore Platforms-Working Stress Design; Twentieth Edition, July 1, 1993, APIStock No. G00200.

§ 250.900(g); § 250.912(a).

API RP 2A–WSD, Recommended Practice for Planning, Designing and ConstructingFixed Offshore Platforms-Working Stress Design; Twentieth Edition, July 1, 1993,Supplement 1, December 1996, Effective Date, February 1, 1997, API Stock No.G00205.

§ 250.900(g); § 250.912(a).

API RP 2D, Recommended practice for Operation and Maintenance of Offshore Cranes,Fourth Edition, August 1, 1999. API Stock No. G02D04.

§ 250.108(a)(1).


270

30 CFR Ch. II (7–1–01 Edition)§ 250.198


API RP 14B, Recommended Practice for Design, Installation, Repair and Operation ofSubsurface Safety Valve Systems, Fourth Edition, July 1, 1994, with Errata datedJune 1996, API Stock No. G14B04.

§ 250.801(e)(4); § 250.804(a)(1)(i).

API RP 14C, Recommended Practice for Analysis, Design, Installation and Testing ofBasic Surface Safety Systems for Offshore Production Platforms, Sixth Edition, March1998, API Stock No. G14C06.

§ 250.802(b), (e)(2); § 250.803(a),(b)(2)(i), (b)(4), (b)(5)(i), (b)(7),(b)(9)(v), (c)(2); § 250.804(a),(a)(5); § 250.1002(d);§ 250.1004(b)(9); § 250.1628(c),(d)(2); § 250.1629(b)(2), (b)(4)(v);§ 250.1630(a).

API RP 14E, Recommended Practice for Design and Installation of Offshore ProductionPlatform Piping Systems, Fifth Edition, October 1, 1991, API Stock No. G07185.

§ 250.802(e)(3); § 250.1628(b)(2),(d)(3).

API RP 14F, Recommended Practice for Design and Installation of Electrical Systemsfor Offshore Production Platforms, Third Edition, September 1, 1991, API Stock No.G07190.

§ 250.114(c); § 250.803(b)(9)(v);§ 250.1629(b)(4)(v).

API RP 14G, Recommended Practice for Fire Prevention and Control on Open TypeOffshore Production Platforms, Third Edition, December 1, 1993, API Stock No.G07194.

§ 250.803(b)(8), (b)(9)(v);§ 250.1629(b)(3), (b)(4)(v).

API RP 14H, Recommended Practice for the Installation, Maintenance and Repair ofSurface Safety Valves and Underwater Safety Valves Offshore, Fourth Edition, July 1,1994, API Stock No. G14H04.

§ 250.802(d); 250.804(a)(4).

API RP 500, Recommended Practice for Classification of Locations for Electrical Instal-lations at Petroleum Facilities Classified as Class I, Division 1 and Division 2, SecondEdition, November 1997, API Stock No. C50002.

§ 250.114(a); § 250.410(e);§ 250.802(e)(4)(i);§ 250.803(b)(9)(i); § 250.1628(b)(3);(d)(4)(i); § 250.1629(b)(4)(i).

API RP 505, Recommended Practice for Classification of Locations for Electrical Instal-lations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2, FirstEdition, November 1997, API Stock No. C50501.

§ 250.114(a); § 250.410(e);§ 250.802(e)(4)(i);§ 250.803(b)(9)(i); § 250.1628(b)(3);(d)(4)(i); § 250.1629(b)(4)(i).

API RP 2556, Recommended Practice for Correcting Gauge Tables for Incrustation,Second Edition, August 1993, API Stock No. H25560; also available under the um-brella of the MPMS.

§ 250.1202(l)(4).

API Spec Q1, Specification for Quality Programs for the Petroleum and Natural Gas In-dustry, Sixth Edition, March 1, 1999. API Stock No. GQ1006.

§ 250.806(a)(2)(ii).

API Spec 6A, Specification for Wellhead and Christmas Tree Equipment, SeventeenthEdition, February 1, 1996, API Stock No. G06A17.

§ 250.806(a)(3); § 250.1002 (b)(1),(b)(2).

API Spec 6AV1, Specification for Verification Test of Wellhead Surface Safety Valvesand Underwater Safety Valves for Offshore Service, First Edition, February 1, 1996,API Stock No. G06AV1.

§ 250.806(a)(3).

API Spec 6D, Specification for Pipeline Valves (Gate, Plug, Ball, and Check Valves),Twenty-first Edition, March 31, 1994, including Supplement 2, December 1, 1997, APIStock No. G03200.

§ 250.1002(b)(1).

API Spec 14A, Tenth Edition, November 2000, ISO10432:1999, Petroleum and NaturalGas Industries—Downhole Equipment—Subsurface Safety Valve Equipment, APIStock No. G14A09.

§ 250.806(a)(3).

API Standard 2551, Standard Method for Measurement and Calibration of HorizontalTanks, First Edition, 1965, reaffirmed January 1997; API Stock No. H25510; alsoavailable under the umbrella of the MPMS.

§ 250.1202(l)(4).

API Standard 2552, Measurement and Calibration of Spheres and Spheroids, First Edi-tion, 1966, reaffirmed January 1997, API Stock No. H25520; also available under theumbrella of the MPMS.

§ 250.1202(l)(4).

API Standard 2555, Method for Liquid Calibration of Tanks, September 1966, reaffirmedJanuary 1997, API Stock No. H25550; also available under the umbrella of the MPMS.

§ 250.1202(l)(4).

ASTM Standard C 33–99a. Standard Specification for Concrete Aggregates .................... § 250.908(b)(4)(i).ASTM Standard C 94/C 94M–99, Standard Specification for Ready-Mixed Concrete ....... § 250.908(e)(2)(i).ASTM Standard C 150–99, Standard Specification for Portland Cement ........................... § 250.908(b)(2)(i).ASTM Standard C 330–99, Standard Specification for Lightweight Aggregates for Struc-

tural Concrete.§ 250.908(b)(4)(i).

ASTM Standard C 595–98, Standard Specification for Blended Hydraulic Cements ......... § 250.908(b)(2)(i).AWS D1.1–96, Structural Welding Code—Steel, 1996, including Commentary ................. § 250.907(b)(1)(i)AWS D1.4–79, Structural Welding Code—Reinforcing Steel, 1979 .................................... § 250.908(e)(3)(ii)NACE Standard MR0175–99, Sulfide Stress Cracking Resistant Metallic Materials for

Oilfield Equipment, Revised January 1999, NACE Item No. 21302.§ 250.417(p)(2).

NACE Standard RP 01–76–94, Standard Recommended Practice, Corrosion Control ofSteel Fixed Offshore Platforms Associated with Petroleum Production.

§ 250.907(d).

[64 FR 72775, Dec. 28, 1999, as amended at 65 FR 218, 219, Jan. 4, 2000; 65 FR 3127, Jan. 20, 2000;65 FR 14470, Mar. 17, 2000; 65 FR 15863, Mar. 24, 2000; 65 FR 18432, Apr. 7, 2000; 65 FR 25285, May1, 2000; 65 FR 36328, June 8, 2000; 65 FR 40052, June 29, 2000; 65 FR 41002, July 3, 2000; 65 FR76935, Dec. 8, 2000]


271


§ 250.199 Paperwork Reduction Actstatements—information collection.

(a) OMB has approved the informa-tion collection requirements in part 250under 44 U.S.C. 3501 et seq. The table inparagraph (e) of this section lists thesubpart in the rule requiring the infor-mation and its title, provides the OMBcontrol number, and summarizes thereasons for collecting the informationand how MMS uses the information.The associated MMS forms required bythis part are listed at the end of thistable with the relevant information.

(b) Respondents are OCS oil, gas, andsulphur lessees and operators. The re-quirement to respond to the informa-tion collections in this part is man-dated under the Act (43 U.S.C. 1331 etseq.) and the Act’s Amendments of 1978(43 U.S.C. 1801 et seq.). Some responsesare also required to obtain or retain abenefit or may be voluntary. Propri-etary information will be protected

under § 250.196, Data and information tobe made available to the public; parts251 and 252; and the Freedom of Infor-mation Act (5 U.S.C. 552) and its imple-menting regulations at 43 CFR part 2.

(c) The Paperwork Reduction Act of1995 requires us to inform the publicthat an agency may not conduct orsponsor, and you are not required to re-spond to, a collection of informationunless it displays a currently validOMB control number.

(d) Send comments regarding any as-pect of the collections of informationunder this part, including suggestionsfor reducing the burden, to the Infor-mation Collection Clearance Officer,Minerals Management Service, MailStop 4230, 1849 C Street, NW., Wash-ington, DC 20240.

(e) MMS is collecting this informa-tion for the reasons given in the fol-lowing table:

30 CFR 250 subpart/title (OMB control No.) Reasons for collecting information and how used

(1) Subpart A, General (1010–0114) .......................................... To inform MMS of actions taken to comply with general oper-ational requirements on the OCS. To ensure that operationson the OCS meet statutory and regulatory requirements, aresafe and protect the environment, and result in diligent ex-ploration, development, and production on OCS leases. Tosupport the unproved and proved reserve estimation, re-source assessment, and fair market value determinations.

(2) Subpart B, Exploration and Development and ProductionPlans (1010–0049).

To inform MMS, States, and the public of planned exploration,development, and production operations on the OCS. To en-sure that operations on the OCS are planned to comply withstatutory and regulatory requirements, will be safe and pro-tect the human, marine, and coastal environment, and willresult in diligent exploration, development, and production ofleases.

(3) Subpart C, Pollution Prevention and Control (1010–0057) ... To inform MMS of measures to be taken to prevent water andair pollution. To ensure that appropriate measures are takento prevent water and air pollution.

(4) Subpart D, Oil and Gas Drilling Operations (1010–0053) ..... To inform MMS of the equipment and procedures to be used indrilling operations on the OCS. To ensure that drilling oper-ations are safe and protect the human, marine, and coastalenvironment.

(5) Subpart E, Oil and Gas Well-Completion Operations (1010–0067).

To inform MMS of the equipment and procedures to be used inwell-completion operations on the OCS. To ensure that well-completion operations are safe and protect the human, ma-rine, and coastal environment.

(6) Subpart F, Oil and Gas Well-Workover Operations (1010–0043).

To inform MMS of the equipment and procedures to be usedduring well-workover operations on the OCS. To ensure thatwell-workover operations are safe and protect the human,marine, and coastal environment.

(7) Subpart G, Abandonment of Wells (1010–0079) .................. To inform MMS of procedures to be used during the temporaryand permanent abandonment of wells. To ensure that wellsare abandoned in a manner that is safe and minimizes con-flicts with other uses of the OCS.

(8) Subpart H, Oil and Gas Production Safety Systems (1010–0059).

To inform MMS of the equipment and procedures to be usedduring production operations on the OCS. To ensure thatproduction operations are safe and protect the human, ma-rine, and coastal environment.

(9) Subpart I, Platforms and Structures (1010–0058) ................. To provide MMS with information regarding the design, fabrica-tion, and installation of platforms on the OCS. To ensure thestructural integrity of platforms installed on the OCS.


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30 CFR 250 subpart/title (OMB control No.) Reasons for collecting information and how used

(10) Subpart J, Pipelines and Pipeline Rights-of-Way (1010–0050).

To provide MMS with information regarding the design, instal-lation, and operation of pipelines on the OCS. To ensurethat pipeline operations are safe and protect the human, ma-rine, and coastal environment.

(11) Subpart K, Oil and Gas Production Rates (1010–0041) ..... To inform MMS of production rates for hydrocarbons producedon the OCS. To ensure economic maximization of ultimatehydrocarbon recovery.

(12) Subpart L, Oil and Gas Production Measurement, SurfaceCommingling, and Security (1010–0051).

To inform MMS of the measurement of production, commin-gling of hydrocarbons, and site security plans. To ensurethat produced hydrocarbons are measured and commingledto provide for accurate royalty payments and security ismaintained.

(13) Subpart M, Unitization (1010–0068) .................................... To inform MMS of the unitization of leases. To ensure thatunitization prevents waste, conserves natural resources, andprotects correlative rights.

(14) Subpart N, Remedies and Penalties (1010–0121) .............. The requirements in subpart N are exempt from the PaperworkReduction Act of 1995 according to 5 CFR 1320.4.

(15) Subpart O, Training (1010–0078) ........................................ To inform MMS of training program curricula, course sched-ules, and attendance. To ensure that training programs aretechnically accurate and sufficient to meet safety and envi-ronmental requirements, and that workers are properlytrained to operate on the OCS.

(16) Subpart P, Sulphur Operations (1010–0086) ...................... To inform MMS of sulphur exploration and development oper-ations on the OCS. To ensure that OCS sulphur operationsare safe; protect the human, marine, and coastal environ-ment; and will result in diligent exploration, development,and production of sulphur leases.

(17) Forms MMS–123, Application for Permit to Drill, andMMS–123S, Supplemental APD Information Sheet, SubpartsD, E, P (1010–0044 and 1010–0131).

To inform MMS of the procedures and equipment to be used indrilling operations. To ensure that drilling and well-comple-tion are safe and protect the environment, use adequateequipment, conform with provisions of the lease, and thepublic is informed.

(18) Form MMS–124, Sundry Notices & Reports on Wells,Subparts D, E, F, G, P (1010–0045).

To inform MMS of well-completion and well-workover oper-ations, changes to any ongoing well operations, and wellabandonment operations. To ensure that MMS has up-to-date and accurate information on OCS drilling and otherlease operations; operations are safe and protect thehuman, marine, and coastal environment; abandoned sitesare cleared of obstructions; and the public is informed.

(19) Form MMS–125, Well Summary Report, Subparts D, E, F,P (1010–0046).

To inform MMS of the results of well-completion or well-workover operations or changes in well status or condition.To ensure that MMS has up-to-date and accurate informa-tion on the status and condition of wells.

(20) Form MMS–126, Well Potential Test Report, Subpart K(1010–0039).

To inform MMS of the production potential of an oil or gas welland to verify a requested production rate. To ensure thatproduction results in ultimate full recovery of hydrocarbons,and energy resources are produced at a prudent rate.

(21) Form MMS–127, Request for Reservoir Maximum Effi-ciency Rate (MER), Subpart K (1010–0018).

To inform MMS of data concerning oil and gas well-completionin a rate-sensitive reservoir and to verify requested efficiencyrate. To ensure that reservoirs are classified correctly andthe requested production rate will not waste oil or gas.

(22) Form MMS–128, Semiannual Well Test Report, Subpart K(1010–0017).

To inform MMS of the status and capacity of gas wells andverify production capacity. To ensure that depletion of res-ervoirs results in greatest ultimate recovery of hydrocarbons.

(23) Form MMS–131, Performance Measures Data (Voluntary)(1010–0112).

To collect data related to a set of performance measures. Toevaluate the effectiveness of industry’s continued improve-ment of safety and environmental management in the OCS.

(24) Form MMS–132, Evacuation Statistics (used in the GOMRegion), Subpart A (1010–0114).

To inform MMS in the event of a major disruption in the avail-ability and supply of natural gas and oil due to natural occur-rences/hurricanes. To advise the USCG of rescue needs,and to alert the news media and interested public entitieswhen production is shut in and when resumed.

(25) Form MMS–133, Weekly Activity Report (used in the GOMRegion), Subpart D (1010–0132).

To inform MMS of well status, well and casing tests, and wellcasing configuration data. To have accurate data and infor-mation on the wells under MMS jurisdiction to ensure com-pliance with approved plans.


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Subpart B—Exploration and Devel-opment and Production Plans

§ 250.200 General requirements.All exploration, development, and

production activities except for pre-liminary activities shall be conductedin accordance with an ExplorationPlan or a Development and ProductionPlan approved by the Regional Super-visor. A proposed plan may apply toone or more leases held by an indi-vidual lessee or may be submitted by agroup of lessees. The Regional Super-visor may authorize lessees to jointlysubmit environmental information forleases that are in the same planningarea and have similar environmentalconditions. Any reference in this partto a Development and Production Planshall be considered to include the De-velopment Operations CoordinationDocument used in the western Gulf ofMexico (GOM) (see § 250.204(d)).

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11,1988. Redesignated and amended at 63 FR29479, 29485, May 29, 1998]

§ 250.201 Preliminary activities.Preliminary activities are geological,

geophysical, and other surveys nec-essary to develop a comprehensive Ex-ploration Plan or Development andProduction Plan. Such preliminary ac-tivities are those which do not resultin any physical penetration of the sea-bed of greater than 500 feet and whichdo not result in any significant adverseimpact on the natural resources of theOuter Continental Shelf (OCS). The Re-gional Supervisor may require priornotification of the type, scope, andtiming of any survey.

§ 250.202 Well location and spacing.(a) The Regional Supervisor is au-

thorized to approve well location andspacing programs necessary for explo-ration and development of a leased sul-phur deposit or fluid hydrocarbon res-ervoir giving consideration to, amongother factors, the location of drillingunits and platforms, extent and thick-ness of the sulphur deposit, geologicaland other reservoir characteristics,number of wells that can be economi-cally drilled, protection of correlativerights, optimum recovery of resources,

minimization of risk to the environ-ment, and prevention of any unreason-able interference with other uses of theOCS. Well location and spacing pro-grams shall be determined independ-ently for each leased sulphur deposit orhydrocarbon-bearing reservoir in amanner that will locate wells in the op-timum position for the most effectiveproduction of sulphur and/or reservoirfluids and avoid the drilling of unnec-essary wells.

(b) For wells which could intersect ordrain an offset property, the RegionalSupervisor may require special meas-ures to protect the rights of the lessorand objecting offset lessees.

(c) The lessee shall drill and producethe wells the Regional Supervisor de-termines are necessary to protect thelessor from loss by reason of produc-tion on other properties or in lieuthereof, with the approval of the Re-gional Supervisor, pay a sum deter-mined by the Regional Supervisor asadequate to compensate the lessor forthe lessee’s failure to drill and produceany well. Payment of that sum shall beconsidered as the equivalent of produc-tion in paying quantities for the pur-pose of extending the lease term.

[53 FR 10690, Apr. 1, 1988, as amended at 55FR 47752, Nov. 15, 1990; 56 FR 32099, July 15,1991. Redesignated at 63 FR 29749, May 29,1998]

§ 250.203 Exploration Plan.

(a) The leasee shall submit for ap-proval an Exploration Plan which in-cludes the following:

(1) The proposed type and sequence ofexploration activities to be undertakentogether with a timetable for their per-formance from commencement to com-pletion.

(2) A description of the type of mo-bile drilling unit, platform, or artifi-cial island to be used including a dis-cussion of the drilling program and im-portant safety and pollution-preven-tion features. In the Alaska OCS Re-gion, lessees shall include provisionsfor—

(i) Drilling a relief well should ablowout occur,

(ii) Loss or disablement of a drillingunit, and

(iii) Loss or damage to support craft.


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(3) A table indicating the approxi-mate location of each proposed explor-atory well, including surface locations,proposed well depths, and water depthat well sites.

(b) The lessee shall submit the fol-lowing supporting information to ac-company the Exploration Plan:

(1) Data and information describedbelow which the Regional Supervisordeems necessary to evaluate geologicconditions:

(i) Current structure contour mapsdrawn to the top of each prospectivehydrocarbon accumulation showing theapproximate surface and bottomholelocation of each proposed well.

(ii) Full-scale interpreted, and if ap-propriate, migrated Common DepthPoint seismic lines intersecting at ornear the primary well locations.

(iii) A time versus depth chart basedon the appropriate velocity analysis inthe area of interpretation.

(iv) Interpreted structure sectionscorresponding to each seismic line sub-mitted in paragraph (b)(1)(ii) of thissection showing the location and pro-posed depth of each well.

(v) A generalized stratigraphic col-umn from the surface to total depth.

(vi) A description of the geology ofthe prospect.

(vii) A plat showing exploration seis-mic coverage of the lease.

(viii) A bathymetry map showing sur-face locations of proposed wells.

(ix) An analysis of seafloor and sub-surface geologic and manmade hazards.Unless the lessee can demonstrate tothe satisfaction of the Regional Super-visor that data sufficient to determinethe presence or absence of such condi-tions are available, the lessee shallconduct a shallow hazards survey in ac-cordance with the Regional Super-visor’s specifications. The Regional Su-pervisor may require the submission ofa shallow hazards report and the dataupon which the analysis is based.

(2) An oil-spill response plan as de-scribed in part 254 or reference to anapproved Regional Response Plan.

(3) A discussion of the measures thathave been or will be taken to satisfythe conditions of lease stipulations.

(4) A list of the proposed drillingfluids, including components and theirchemical compositions, information on

the projected amounts and rates ofdrilling fluid and cuttings discharges,and method of disposal.

(5) Information concerning the pres-ence of hydrogen sulfide (H2S) and thefollowing proposed precautionarymeasures:

(i) A classification of the lease areaas to whether it is within an areaknown to contain H2S, an area wherethe presence of H2S is unknown, or anarea where the absence of H2S has beenconfirmed as described in § 250.417 ofthis part and the documentation sup-porting the classification; and

(ii) If the classification is an areaknown to contain H2S or an area wherethe presence of H2S is unknown, an H2SContingency Plan as required in§ 250.417 of this part.

(6) A detailed discussion of new orunusual technology to be employed.The lessee shall indicate which por-tions of the supporting information thelessee believes are exempt from disclo-sure under the Freedom of InformationAct (FOIA) (5 U.S.C. 552) and the imple-menting regulations (43 CFR part 2).The lessee shall include a written dis-cussion of the general subject matterof the deleted portions for transmittalto the recipients of plan copies.

(7) A brief description of the onshorefacilities to be used to support the ex-ploration activities including informa-tion as to whether the facilities are ex-isting, proposed, or are to be expanded;a brief description of support vessels tobe used and information concerningtheir frequency of travel; and a mapshowing the lease relative to the shore-line and depicting proposed transpor-tation routes.

(8) For onshore support facilities, ex-cept in the western GOM, indicate thefollowing:

(i) The location, size, number, andland requirements (including rights-of-way and easements) of the onshore sup-port and storage facilities and, wherepossible, a timetable for the acquisi-tion of lands and the construction orexpansion of any facilities.

(ii) The estimated number of personsexpected to be employed in support ofoffshore, onshore, and transportationactivities and, where possible, the ap-proximate number of new employees


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and families likely to move into the af-fected area.

(iii) Major supplies, services, energy,water, or other resources within af-fected States necessary for carryingout the related plan.

(iv) The source, composition, fre-quency, and duration of emissions ofair pollutants.

(9) The quantity, composition, andmethod of disposal of solid and liquidwastes and pollutants likely to be gen-erated by offshore, onshore, and trans-portation operations.

(10) Historic weather patterns andother meteorological conditions of off-shore areas including temperature, skycover and visibility, precipitation,storm frequency and magnitude, winddirection and velocity, and freezing andicing conditions listing, where possible,the means and extremes of each.

(11) Physical oceanography includingonsite direction and velocity of cur-rents and tides, sea states, tempera-ture, and salinity, water quality, andicing conditions, where appropriate.

(12) Onsite flora and fauna includingboth pelagic and benthic communities,transitory birds and mammals thatmay breed or migrate through the areawhen proposed activities are being con-ducted, identification of endangeredand threatened species and their crit-ical habitats that could be affected byproposed activities, and typical fishingseasons and locations of fishing activi-ties. The results of any biological sur-veys required by the Regional Super-visor (including a copy of survey re-ports or references to previously sub-mitted reports) should be incorporatedinto this discussion.

(13) Environmentally sensitive areas(onshore as well as offshore), e.g., ref-uges, preserves, sanctuaries, rookeries,calving grounds, and areas of par-ticular concern identified by an af-fected State pursuant to the CoastalZone Management Act (CZMA) whichmay be affected by the proposed activi-ties.

(14) Onsite uses of the area based oninformation available, e.g., shipping,military use, recreation, boating, com-mercial fishing, subsistence huntingand fishing, and other mineral explo-ration in the area.

(15) If the Regional Director believesthat an archaeological resource mayexist in the lease area, the Regional Di-rector will notify the lessee in writing.Prior to commencing any operations,the lessee shall prepare a report, asspecified by the Regional Director, todetermine the potential existence ofany archaeological resource that maybe affected by operations. The reportshall be prepared by an archaeologistand geophysicist and shall be based onan assessment of data from remote-sensing surveys and of other pertinentarchaeological and environmental in-formation.

(16) Existing and planned monitoringsystems that are measuring or willmeasure environmental conditions andprovide data and information on theimpacts of activities in the geographicareas.

(17) An assessment of the direct andcumulative effects on the offshore andonshore environments expected tooccur as a result of implementation ofthe Exploration Plan, expressed interms of magnitude and duration, withspecial emphasis upon the identifica-tion and evaluation of unavoidable andirreversible impacts on the environ-ment. Measures to minimize or miti-gate impacts should be identified anddiscussed.

(18) Certificate(s) of coastal zone con-sistency as provided in 15 CFR part 930.

(19) For each OCS facility, the lesseeshall submit the information describedbelow when it is needed to make thefindings under § 250.303 or § 250.304 ofthis part:

(i)(A) Projected emissions from eachproposed or modified facility for eachyear of operation and the basis for allcalculations to include (if the drillingunit has not yet been determined, thelessee shall use worst-case estimatesfor the type of unit proposed):

(1) For each source, the amount ofthe emission by air pollutant expressedin tons per year and the frequency andduration of emissions.

(2) For each facility, the totalamount of emissions by air pollutantexpressed in tons per year and, in addi-tion for a modified facility only, theincremental amount of total emissionsby air pollutant resulting from the newor modified source(s).


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(3) A detailed description of all proc-esses, processing equipment, and stor-age units, including information onfuels to be burned.

(4) A schematic drawing which iden-tifies the location and elevation ofeach source.

(5) If projected emissions are basedon the use of emission-reduction con-trol technology, a description of thecontrols providing the information re-quired by paragraph (b)(19)(iv) of thissection.

(B) The distance of each proposed fa-cility from the mean high water mark(mean higher high water mark on thePacific coast) of any State.

(ii)(A) The model(s) used to deter-mine the effect on the onshore air qual-ity of emissions from each facility, orfrom other facilities when required bythe Regional Supervisor, and the re-sults obtained through the use of themodel(s). Only model(s) that has beenapproved by the Director may be used.

(B) The best available meteorologicalinformation and data consistent withthe model(s) used stating the basis forthe data and information selected.

(iii) The air quality status of any on-shore area where the air quality is sig-nificantly affected (within the meaningof § 250.303 of this part) by projectedemissions from each facility proposedin the plan. The area should be classi-fied as nonattainment, attainment, orunclassifiable to include the status ofeach area by air pollutant, the class ofattainment area, and the air-pollutioncontrol agency whose jurisdiction cov-ers the area identified.

(iv) The emission-reduction controlsavailable to reduce emissions, includ-ing the source, the emission-reductioncontrol technology, reductions to beachieved, and monitoring system thelessee proposes to use to measure emis-sions. The lessee shall indicate whichemission-reduction control technologythe lessee believes constitutes the bestavailable control technology and thebasis for that opinion.

(20) The name, address, and telephonenumber of an individual employee ofthe lessee to whom inquiries by the Re-gional Supervisor and the affectedState(s) may be made.

(21) Such other information and dataas the Regional Supervisor may re-quire.

(c) Information and data discussed inother documents previously submittedto MMS or otherwise readily availableto reviewers may be referenced. Thematerial being referenced shall becited, described briefly, and include astatement of where the material isavailable for inspection. Any materialbased on proprietary data which is notitself available for inspection shall notbe so referenced.

(d) The Regional Director, after con-sultation with the Governor of the af-fected State(s) or the Governor’s des-ignated representative, the CZM agen-cy of affected State(s), and the Officeof Ocean and Coastal Resource Manage-ment of the National Oceanic and At-mospheric Administration (NOAA) maylimit the amount of information re-quired to be included to that necessaryto assure conformance with the Act,other laws, applicable regulations, andlease provisions.

(e) The Regional Supervisor shall de-termine within 10 working days afterreceipt of the Exploration Plan wheth-er additional information is needed. Ifno deficiencies are identified and therequired number of copies have beenreceived, the plan will be deemed sub-mitted.

(f) Within 2 working days after wedeem the Exploration Plan submitted,the Regional Supervisor will send byreceipted mail a copy of the plan (ex-cept those portions exempt from dis-closure under the Freedom of Informa-tion Act and 43 CFR part 2) to the Gov-ernor or the Governor’s designated rep-resentative and the CZM agency ofeach affected State. Consistency re-view begins when the State’s CZMagency receives a copy of the deemedsubmitted plan, consistency certifi-cation, and required necessary dataand information as directed by 15 CFR930.78.

(g) In accordance with the NationalEnvironmental Policy Act (NEPA), theRegional Supervisor shall evaluate theenvironmental impacts of the activi-ties described in the Exploration Plan.

(h) In the evaluation of an Explo-ration Plan, the Regional Supervisorshall consider written comments from


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the Governor of an affected State orthe Governor’s designated representa-tive which are received prior to thedeadline specified by the Regional Su-pervisor. The Regional Supervisor mayconsult directly with affected Statesregarding matters contained in thecomments.

(i) Within 30 days of submission of aproposed Exploration Plan, the Re-gional Supervisor shall accomplish oneof the following:

(1) Approve the plan;(2) Require the lessee to modify any

plan which is inconsistent with theprovisions of the lease, the Act, or theregulations prescribed under the Actincluding air quality, environmental,safety, and health requirements; or

(3) Disapprove the plan if the Re-gional Supervisor determines that aproposed activity would probably causeserious harm or damage to life (includ-ing fish and other aquatic life), prop-erty, natural resources offshore includ-ing any mineral deposits (in areasleased or not leased), the national secu-rity or defense, or the marine, coastal,or human environment, and that theproposed activity cannot be modifiedto avoid the condition(s).

(j) The Regional Supervisor shall no-tify the lessee in writing of the rea-son(s) for disapproving an ExplorationPlan or for requiring modification of aplan. For plans requiring modification,the Regional Supervisor shall also no-tify the lessee in writing of the condi-tions that must be met for plan ap-proval.

(k)(1) The lessee may resubmit an Ex-ploration Plan, as modified, to the Re-gional Supervisor in the same manneras for a new plan. Only information re-lated to the proposed modificationsneed be submitted. The Regional Su-pervisor shall approve, disapprove, orrequire modification of the resub-mitted plan based upon the criteria inparagraph (i) of this section within 30days of the resubmission date.

(2) An Exploration Plan which hasbeen disapproved pursuant to para-graph (i)(3) of this section may be re-submitted if there is a change in theconditions which caused it to be dis-approved. The Regional Supervisorshall approve, require modification, or

disapprove such a plan within 30 daysof the resubmission date.

(l) When a State objects to a lessee’scoastal zone consistency certification,the lessee shall modify the plan to ac-commodate the State’s objection(s)and resubmit the plan to—

(1) The Regional Supervisor for re-view pursuant to the criteria in para-graphs (h), (i), and (j) of this section;and

(2) Through the Regional Supervisorto the State for review pursuant to theCZMA and the implementing regula-tions (15 CFR 930.83 and 930.84).

Alternatively, the lessee may appealthe State’s objection to the Secretaryof Commerce pursuant to the proce-dures described in section 307 of theCZMA and the implementing regula-tions (subpart H of 15 CFR part 930).The Regional Supervisor shall approveor disapprove a plan as resubmittedwithin 30 days of the resubmissiondate.

(m) If the Regional Supervisor dis-approves an Exploration Plan, the Sec-retary may, subject to the provisionsof section 5(a)(2)(B) of the Act and theimplementing regulations in § 250.182and 256.77 of this chapter II, cancel thelease(s), and the lessee shall be entitledto compensation in accordance withsection 5(a)(2)(c) of the Act.

(n)(1) The Regional Supervisor shallperiodically review the activities beingconducted under an approved Explo-ration Plan and may request updatedinformation on schedules and proce-dures. The frequency and extent of theRegional Supervisor’s review shall bebased upon the significance of anychanges in available information andin other onshore or offshore conditionsaffecting or affected by exploration ac-tivities being conducted pursuant tothe plan. If the review indicates thatthe plan should be revised to meet therequirements of this part, the RegionalSupervisor shall require the needed re-vision.

(2) Revisions to an approved or pend-ing Exploration Plan, whether initi-ated by the lessee or ordered by the Re-gional Supervisor, shall be submittedto the Regional Supervisor for ap-proval. Only information related to theproposed revisions need be submitted.


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When the Regional Supervisor deter-mines that a proposed revision couldresult in a significant change in theimpacts previously identified and eval-uated or requires additional permits,the revisions shall be subject to all ofthe procedures in this section.

(o) To ensure safety and protection ofthe environment and archaeological re-sources, the Regional Director may au-thorize or direct the lessee to conductgeological, geophysical, biological, ar-chaeological, or other surveys or moni-toring programs. The lessee shall pro-vide the Regional Director, upon re-quest, with copies of any data obtainedas a result of those surveys and moni-toring programs.

(p) The lessee may not drill any welluntil the District Supervisor’s approvalof an Application for Permit to Drill(APD), submitted in accordance withthe requirements of § 250.414 of thispart, has been received. The DistrictSupervisor shall not approve any APDuntil all affected States with approvedCZM programs have concurred or havebeen conclusively presumed to concurwith the applicant’s coastal zone con-sistency certification accompanying aplan, or the Secretary of Commerce hasmade the finding authorized by section307(c)(3)(B)(iii) of the CZMA. TheAPD’s must conform to the activitiesdescribed in detail in the approved Ex-ploration Plan and shall not be subjectto a separate State coastal zone con-sistency review.

(q) Nothing in this section or in anapproved plan shall limit the lessee’sresponsibility to take appropriatemeasures to meet emergency situa-tions. In such situations, the RegionalSupervisor may approve or require de-partures from an approved ExplorationPlan.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11,1988, as amended at 54 FR 50616, Dec. 8, 1989;59 FR 53093, Oct. 21, 1994; 62 FR 13996, Mar. 25,1997. Redesignated and amended at 63 FR29479, 29485, May 29, 1998; 64 FR 53200, Oct. 1,1999; 64 FR 72794, Dec. 28, 1999]

§ 250.204 Development and ProductionPlan.

(a) The lessee shall submit for ap-proval a Development and ProductionPlan which includes the following:

(1) A description of and schedule forthe development and production activi-ties to be performed including plancommencement date, date of first pro-duction, total time to complete all de-velopment and production activities,and dates and sequences for drillingwells and installing facilities andequipment.

(2) A description of any drilling ves-sels, platforms, pipelines, or other fa-cilities and operations located offshorewhich are proposed or known by thelessee (whether or not owned or oper-ated by the lessee) to be directly re-lated to the proposed development, in-cluding the location, size, design, andimportant safety, pollution prevention,and environmental monitoring featuresof the facilities and operations.

(b) The lessee shall submit the fol-lowing supporting information to ac-company the Development and Produc-tion Plan:

(1) Geological and geophysical (G&G)data and information, including thefollowing:

(i) A plat showing the surface loca-tion of any proposed fixed structure orwell.

(ii) A plat showing the surface andbottomhole locations and giving themeasured and true vertical depths foreach proposed well.

(iii) Current interpretations of rel-evant G&G data.

(iv) Current structure map(s) show-ing the surface and bottomhole loca-tion of each proposed well and thedepths of expected productive forma-tions.

(v) Interpreted structure sectionsshowing the depths of expected produc-tive formations.

(vi) A bathymetric map showing sur-face locations of fixed structures andwells or a table of water depths at eachproposed site.

(vii) A discussion of seafloor condi-tions including a shallow hazards anal-ysis for proposed drilling and platformsites and pipeline routes. This informa-tion shall be derived from the shallowhazards report required by § 250.909 ofthis part.

(2) Information concerning the pres-ence of H2S and proposed precautionarymeasures, including the following:


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(i) A classification of the lease areaas to whether it is within an areaknown to contain H2S, an area wherethe presence of H2S is unknown, or anarea where the absence of H2S has beenconfirmed as described in § 250.417 ofthis part and the documentation sup-porting the classification; or

(ii) If the classification is an areaknown to contain H2S or an area wherethe presence of H2S is unknown, an H2SContingency Plan as required in§ 250.417 of this part.

(3) A description of the environ-mental safeguards to be implemented,including an updated oil-spill responseplan as described in part 254 of thischapter or reference to an approvedplan.

(4) A discussion of the steps thathave been or will be taken to satisfythe conditions of lease stipulations.

(5)(i) A description of technology andreservoir engineering practices in-tended to increase the ultimate recov-ery of oil and gas, i.e., secondary, ter-tiary, or other enhanced recovery prac-tices;

(ii) A description of technology andrecovery practices and procedures in-tended to assure optimum recovery ofsulphur; or

(iii) A description of technology andrecovery practices and procedures in-tended to assure optimum recovery ofoil and gas and sulphur.

(6) A discussion of the proposed drill-ing and completion programs.

(7) A detailed description of new orunusual technology to be employed.The lessee shall indicate which por-tions of the information the lessee be-lieves are exempt from disclosureunder the FOIA (5 U.S.C. 552) and theimplementing regulations (43 CFR part2). The lessee shall include a writtendiscussion of the general subject mat-ter of the deleted portions for trans-mittal to recipients of plan copies.

(8) A brief description of the fol-lowing:

(i) The location, description, and sizeof any offshore, and to the maximumextent practicable, land-based oper-ations to be conducted or contractedfor as a result of the proposed activity,including the following:

(A) The acreage required within aState for facilities, rights-of-way, andeasements.

(B) The means proposed for transpor-tation of oil, gas, and sulphur to shore;the routes to be followed by each modeof transportation; and the estimatedquantities of oil, gas, and sulphur to bemoved along such routes.

(C) An estimate of the frequency ofboat and aircraft departures and arriv-als, the onshore location of terminals,and the normal routes for each mode oftransportation.

(ii) A list of the proposed drillingfluids including components and theirchemical compositions, information onthe projected amounts and rates ofdrilling fluid and cuttings discharges,and method of disposal. If the informa-tion is provided in an approved Envi-ronmental Protection Agency, Na-tional Pollutant Discharge EliminationSystem permit, or a pending permit ap-plication, the lessee may referencethese documents.

(iii) The quantities, types, and plansfor disposal of other solid and liquidwastes and pollutants likely to be gen-erated by offshore, onshore, and trans-port operations and, regarding anywastes which may require onshore dis-posal, the means of transportation tobe used to bring the wastes to shore,disposal methods to be utilized, and lo-cation of onshore waste disposal ortreatment facilities.

(iv) The following information on on-shore support facilities, except in thewestern GOM:

(A) The approximate number, timing,and duration of employment of personswho will be engaged in onshore devel-opment and production activities, anapproximate number of local personnelwho will be employed for or in supportof the development activities (classi-fied by the major skills or crafts thatwill be required from local sources andestimated number of each such skillneeded), and the approximate totalnumber of persons who will be em-ployed during the onshore constructionactivity and during all activities re-lated to offshore development and pro-duction.


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(B) The approximate number of peo-ple and families to be added to the pop-ulation of local nearshore areas as a re-sult of the planned development.

(C) An estimate of significant quan-tities of energy and resources to beused or consumed including electricity,water, oil and gas, diesel fuel, aggre-gate, or other supplies which may bepurchased within an affected State.

(D) The types of contractors or ven-dors which will be needed, although notspecifically identified, and which mayplace a demand on local goods andservices.

(E) The source, composition, fre-quency, and duration of emissions ofair pollutants.

(v) A narrative description of the ex-isting environment with an emphasisplaced on those environmental valuesthat may be affected by the proposedaction. This section shall contain a de-scription of the physical environmentof the area covered by the related plan.This portion of the plan shall includedata and information obtained or de-veloped by the lessee together withother pertinent information and dataavailable to the lessee from othersources. The environmental informa-tion and data shall include the fol-lowing, where appropriate:

(A) If the Regional Director believesthat an archaeological resource mayexist in the lease area, the Regional Di-rector will notify the lessee in writing.Prior to commencing any operations,the lessee shall prepare a report, asspecified by the Regional Director, todetermine the potential existence ofany archaeological resource that maybe affected by operations. The reportshall be prepared by an archaeologistand geophysicist and shall be based onan assessment of data from remote-sensing surveys and of other pertinentarchaeological and environmental in-formation.

(B) The aquatic biota, including a de-scription of fishery and marine mam-mal use of the lease and the signifi-cance of the lease, and a description ofany threatened and endangered speciesand their critical habitat. The resultsof any biological surveys required bythe Regional Supervisor (including acopy of survey reports or references to

previously submitted reports) shouldbe incorporated into these discussions.

(C) Environmentally sensitive areas(e.g., refuges, preserves, sanctuaries,rookeries, calving grounds, coastalhabitat, beaches, and areas of par-ticular environmental concern) whichmay be affected by the proposed activi-ties.

(D) The predevelopment, ambientwater-column quality and temperaturedata for incremental depths for theareas encompassed by the plan.

(E) The physical oceanography, in-cluding ocean currents described as toprevailing direction, seasonal vari-ations, and variations at differentwater depths in the lease.

(F) Historic weather patterns andother meteorological conditions, in-cluding storm frequency and mag-nitude, wave height and direction, winddirection and velocity, air tempera-ture, visibility, freezing and icing con-ditions, and ambient air quality list-ing, where possible, the means and ex-tremes of each.

(G) The other uses of the area knownto the lessee, including military use fornational security or defense, subsist-ence hunting and fishing, commercialfishing, recreation, shipping, and othermineral exploration or development.

(H) The existing or planned moni-toring systems that are measuring orwill measure impacts of activities onthe environment in the planning area.

(9) For sulphur operations, the degreeof subsidence that is expected at var-ious stages of production, and meas-ures that will be taken to assure safetyof operations and protection of the en-vironment. Special attention shall begiven to the effects of subsidence on ex-isting or potential oil and gas produc-tion, fixed bottom-founded structures,and pipelines.

(10) For sulphur operations, a discus-sion of the potential toxic or thermaleffects on the environment caused bythe discharge of bleedwater, includinga description of the measures that willbe taken into account to mitigatethese impacts.

(11) An assessment of the effects onthe environment expected to occur as aresult of implementation of the plan,identifying specific and cumulative im-pacts that may occur both onshore and


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offshore, and the measures proposed tomitigate these impacts. Such impactsshall be quantified to the fullest extentpossible including magnitude and dura-tion and shall be accumulated for allactivities for each of the major ele-ments of the environment (e.g., wateror biota).

(12) A discussion of alternatives tothe activities proposed that were con-sidered during the development of theplan including a comparison of the en-vironmental effects.

(13) Certificate(s) of coastal zone con-sistency as provided in 15 CFR part 930.

(14) For each OCS facility, such infor-mation described below needed tomake the findings under § 250.303 or§ 250.304 of this part:

(i)(A) Projected emissions from eachproposed or modified facility for eachyear of operation and basis for all cal-culations to include the following:

(1) For each source, the amount ofthe emission by air pollutant expressedin tons per year and frequency and du-ration of emissions;

(2) For each proposed facility, thetotal amount of emissions by air pol-lutant expressed in tons per year, thefrequency distribution of total emis-sions by air pollutant expressed inpounds per day and, in addition for amodified facility only, the incrementalamount of total emissions by air pol-lutant resulting from the new or modi-fied source(s);

(3) A detailed description of all proc-esses, processing equipment, and stor-age units, including information onfuels to be burned;

(4) A schematic drawing which iden-tifies the location and elevation ofeach source; and

(5) If projected emissions are basedon the use of emission-reduction con-trol technology, a description of thecontrols providing the information re-quired by paragraph (b)(12)(iv)(A) ofthis section.

(B) The distance of each proposed fa-cility from the mean high water mark(mean higher high water mark on thePacific coast) of any State.

(ii)(A) The model(s) used to deter-mine the effect on the onshore air qual-ity of emissions from each facility, orfrom other facilities when required bythe Regional Supervisor, and the result

obtained through the use of themodel(s). Only model(s) that has beenapproved by the Director may be used.

(B) The best available meteorologicalinformation and data consistent withthe model(s) used stating the basis forthe information and data selected.

(iii) The air quality status of any on-shore area where the air quality is sig-nificantly affected (within the meaningof § 250.303 of this part) by projectedemissions from each facility proposedin the plan. The area should be classi-fied as nonattainment, attainment, orunclassifiable listing the status of eacharea by air pollutant, the class of at-tainment areas, and the air pollutioncontrol agency whose jurisdiction cov-ers the area identified.

(iv)(A) The emission-reduction con-trols available to reduce emissions in-cluding the source, emission-reductioncontrol technology, reductions to beachieved, and monitoring system thelessee proposes to use to measure emis-sions. The lessee shall indicate whichemission-reduction control technologythe lessee believes constitutes the bestavailable control technology and thebasis for that opinion.

(B) The ownership of the offshore andonshore offsetting source(s) and the re-duction obtainable from each offset-ting source.

(15) A brief discussion of any ap-proved or anticipated suspensions ofproduction necessary to hold thelease(s) in an active status.

(16) The name, address, and telephonenumber of an individual employee ofthe lessee to whom inquiries by the Re-gional Supervisor and the affectedState(s) may be directed.

(17) Such other data and informationas the Regional Supervisor may re-quire.

(c) Data and information discussed inother documents previously submittedto MMS or otherwise readily availableto reviewers may be incorporated byreference. The material being incor-porated shall be cited and describedbriefly and include a statement ofwhere the material is available for in-spection. Any material based on propri-etary data which is not itself availablefor inspection shall not be incorporatedby reference.


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(d)(1) Development and ProductionPlans are not required for leases in thewestern GOM. For these leases, the les-see shall submit to the Regional Super-visor for approval a Development Oper-ations Coordination Document with allinformation necessary to assure con-formance with the Act, other laws, ap-plicable regulations, lease provisions,or as otherwise needed to carry out thefunctions and responsibilities of theRegional Supervisor.

(2) Any information required in para-graph (d)(1) of this section shall be con-sidered a Development and ProductionPlan for the purpose of references inany law, regulation, lease provision,agreement, or other document refer-ring to the preparation or submissionof a plan.

(e) The Regional Director, after con-sultation with the Governor(s) of theaffected State(s) or the Governor’s des-ignated representative, the CZM agen-cy of the affected State(s), and the Of-fice of Ocean and Coastal ResourceManagement of NOAA may limit theamount of information required to beincluded in a Development and Produc-tion Plan to that necessary to assureconformance with the Act, other laws,applicable regulations, and lease provi-sions. In determining the informationto be included in a plan, the RegionalDirector shall consider current and ex-pected operating conditions togetherwith experience gained during past op-erations of a similar nature in the areaof proposed activities.

(f) The Regional Supervisor shall de-termine within 20 working days afterreceipt whether additional material isneeded. If no deficiencies are identifiedand the requested number of copieshave been received, the plan shall bedeemed submitted.

(g) Within 5 working days after a De-velopment and Production Plan hasbeen deemed submitted, the RegionalSupervisor shall transmit a copy of theplan, except for those portions of theplan determined to be exempt from dis-closure under the FOIA and the imple-menting regulations (43 CFR part 2), tothe Governor or the Governor’s des-ignated representative and the CZMagency of each affected State and tothe executive of each affected localgovernment that requests a copy. The

Regional Supervisor shall make copiesavailable to appropriate Federal Agen-cies, interstate entities, and the public.The plan will be available for review atthe appropriate MMS Regional PublicInformation Office.

(h) The Governor or the Governor’sdesignated representative and the CZMagency of each affected State and theexecutive of each affected local govern-ment shall have 60 days from the dateof receipt of the Development and Pro-duction Plan to submit comments andrecommendations to the Regional Su-pervisor. The executive of any affectedlocal government must forward all rec-ommendations to the Governor of theState prior to submitting them to theRegional Supervisor. The Regional Su-pervisor shall accept those rec-ommendations from the Governor thatprovide for a reasonable balance be-tween the national interest and thewell-being of the citizens of the af-fected State. The Regional Supervisorshall explain in writing the reasons foraccepting or rejecting any rec-ommendations. In addition, any inter-ested Federal Agency or person maysubmit comments and recommenda-tions to the Regional Supervisor. Allcomments and recommendations shallbe made available to the public.

(i) We will process the plan accordingto this section and 15 CFR part 930. Ac-cordingly, consistency review beginswhen the State’s CZM agency receivesa copy of the deemed submitted plan,consistency certification, and requirednecessary data and information as di-rected by 15 CFR 930.78.

(j) The Regional Supervisor willevaluate the environmental impact ofthe activities described in the Develop-ment and Production Plan (DPP) andprepare the appropriate environmentaldocumentation required by the Na-tional Environmental Policy Act of1969. At least once in each planningarea (other than the western and cen-tral Gulf of Mexico planning areas), wewill prepare an environmental impactstatement (EIS) and send copies of thedraft EIS to the Governor of each af-fected State and the executive of eachaffected local government that re-quests a copy. Additionally, when weprepare a DPP EIS and when theState’s federally approved coastal


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management program requires a DPPNEPA document for use in determiningconsistency, we will forward a copy ofthe draft EIS to the State’s CZM Agen-cy. We will also make copies of thedraft EIS available to any appropriateFederal Agency, interstate entity, andthe public.

(k) Prior to or immediately after adetermination by the Director that ap-proval of a Development and Produc-tion Plan requires that the proceduresunder NEPA shall commence, the Re-gional Supervisor may require lesseesof tracts in the vicinity, for which De-velopment and Production Plans havenot been approved, to submit prelimi-nary or final plans for their leases.

(l) No later than 60 days after the lastday of the comment period provided inparagraph (h) of this section or within60 days of the release of the final EISdescribing the proposed activities, theRegional Supervisor shall accomplishthe following:

(1) Approve the plan;(2) Require modification of the plan

if it is determined that the lessee hasfailed to make adequate provisions forsafety, environmental protection, orconservation of resources includingcompliance with the regulations pre-scribed under the Act; or

(3) Disapprove the plan if one or moreof the following occurs:

(i) The lessee fails to demonstratethat compliance with the requirementsof the Act, provisions of the regula-tions prescribed under the Act, orother applicable Federal laws is pos-sible;

(ii) State concurrence with the appli-cant’s coastal zone consistency certifi-cation has not been received, theState’s concurrence has not been con-clusively presumed, or the State ob-jects to the consistency certification,and the Secretary of Commerce doesnot make the determination authorizedby section 307(c)(3)(B)(iii) of the CZMA;

(iii) Operations threaten national se-curity or defense; or

(iv) Exceptional geological condi-tions in the lease area, exceptional re-source value in the marine or coastalenvironment, or other exceptional cir-cumstances exist, and all of the fol-lowing:

(A) Implementation of the plan wouldprobably cause serious harm or damageto life (including fish and other aquaticlife), property, any mineral deposits (inareas leased or not leased), the na-tional security or defense, or to themarine, coastal, or human environ-ments.

(B) The threat of harm or damagewill not disappear or decrease to an ac-ceptable extent within a reasonable pe-riod of time.

(C) The advantages of disapprovingthe plan outweigh the advantages ofdevelopment and production.

(m) The Regional Supervisor shallnotify the lessee in writing of the rea-son(s) for disapproving a Developmentand Production Plan or for requiringmodification of a plan and the condi-tions which must be met for plan ap-proval.

(n) The lessee may resubmit a Devel-opment and Production Plan, as modi-fied, to the Regional Supervisor. Onlyinformation related to the proposedmodifications need be submitted. With-in 60 days following the 60-day com-ment period provided for in paragraph(h) of this section, the Regional Super-visor shall approve, disapprove, or re-quire modification of the modifiedplan.

(o)(1) If a Development and Produc-tion Plan is disapproved for the solereason that a State consistency certifi-cation has not been obtained, the Re-gional Supervisor shall approve theplan upon receipt of the concurrence,at the time when concurrence is con-clusively presumed, or when the Sec-retary of Commerce makes a findingauthorized by section 307(c)(3)(B)(iii) ofthe CZMA.

(2) If a Development and ProductionPlan is disapproved because a State ob-jects to the lessee’s coastal zone con-sistency certification, the lessee shallmodify the plan to accommodate theState’s objection(s) and resubmit theplan to (i) the Regional Supervisor forreview pursuant to the criteria in para-graph (l) of this section; and (ii)through the Regional Supervisor, tothe State for review pursuant to theCZMA and the implementing regula-tions (15 CFR 930.83 and 930.84). Alter-natively, the lessee may appeal theState’s objection to the Secretary of


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30 CFR Ch. II (7–1–01 Edition)§ 250.300

Commerce pursuant to the proceduresdescribed in section 307 of the CZMAand the implementing regulations (sub-part H of 15 CFR part 930). The Re-gional Supervisor shall approve, dis-approve, or require modification of aplan as revised within 60 days followingthe 60-day comment period provided forin paragraph (h) of this section.

(p) Development and ProductionPlans disapproved pursuant to para-graph (l)(3) of this section are subjectto the provisions of section 25(h)(2) ofthe Act and the implementing regula-tions in §§ 250.183 and 256.77 of thischapter.

(q)(1) The Regional Supervisor shallperiodically review the activities beingconducted under an approved Develop-ment and Production Plan. The fre-quency and extent of the Regional Su-pervisor’s review shall be based uponthe significance of any changes inavailable information and onshore oroffshore conditions affecting or im-pacted by development or productionactivities being conducted pursuant tothe plan. If the review indicates thatthe plan should be revised to meet therequirements of this part, the RegionalSupervisor shall require the needed re-visions.

(2) Revisions to an approved or pend-ing Development and Production Plan,whether initiated by the lessee or or-dered by the Regional Supervisor, shallbe submitted to the Regional Super-visor for approval. Only informationrelated to the proposed revisions needbe submitted. When the Regional Su-pervisor determines that a proposed re-vision could result in a significantchange in the impacts previously iden-tified and evaluated, requires addi-tional permits, or proposes activitiesnot previously identified and evalu-ated, the revision shall be subject to allof the procedures in this section.

(3) When any revision to an approvedDevelopment and Production Plan isproposed by the lessee, the RegionalSupervisor may approve the revision ifit is determined that the revision isconsistent with the protection of themarine, coastal, and human environ-ments and will lead to greater recoveryof oil and natural gas; will improve theefficiency, safety, and environmentalprotection of the recovery operation; is

the only means available to avoid sub-stantial economic hardship to the les-see; or is otherwise not inconsistentwith the provisions of the Act.

(r) Whenever the lessee fails to sub-mit a Development and ProductionPlan in accordance with provisions ofthis section or fails to comply with anapproved plan, the lease may be can-celled in accordance with sections 5 (c)and (d) of the Act and the imple-menting regulations in §§ 250.183 and256.77 of this chapter.

(s) To ensure safety and protection ofthe environment and archaeological re-sources, the Regional Director may au-thorize or direct the lessee to conductgeological, geophysical, biological, ar-chaeological, or other surveys or moni-toring programs. The lessee shall pro-vide the Regional Director, upon re-quest, copies of any data obtained as aresult of those surveys and monitoringprograms.

(t) The lessee may not drill any welluntil the District Supervisor’s approvalof an APD, filed in accordance with therequirements of § 250.414 of this part,has been received. All APD’s and appli-cations to install platforms and struc-tures, pipelines, and production equip-ment must conform to the activitiesdescribed in detail in the approved De-velopment and Production Plan andshall not be subject to a separate Statecoastal zone consistency review.

(u) Nothing in this section or ap-proved plans shall limit the lessee’s re-sponsibility to take appropriate meas-ures to meet emergency situations. Insuch situations, the Regional Super-visor may approve or require depar-tures from an approved Developmentand Production Plan.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11,1988, as amended at 54 FR 50616, Dec. 8, 1989;55 FR 47752, Nov. 15, 1990; 56 FR 32099, July 15,1991; 59 FR 53093, Oct. 21, 1994; 62 FR 13996,Mar. 25, 1997. Redesignated and amended at63 FR 29479, 29485, May 29, 1998; 64 FR 9065,Feb. 24, 1999; 64 FR 53200, Oct. 1, 1999; 64 FR72794, Dec. 28, 1999]

Subpart C—Pollution Preventionand Control

§ 250.300 Pollution prevention.(a) During the exploration, develop-

ment, production, and transportation


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of oil and gas or sulphur, the lesseeshall take measures to prevent unau-thorized discharge of pollutants intothe offshore waters. The lessee shallnot create conditions that will pose un-reasonable risk to public health, life,property, aquatic life, wildlife, recre-ation, navigation, commercial fishing,or other uses of the ocean.

(1) When pollution occurs as a resultof operations conducted by or on behalfof the lessee and the pollution damagesor threatens to damage life (includingfish and other aquatic life), property,any mineral deposits (in areas leased ornot leased), or the marine, coastal, orhuman environment, the control andremoval of the pollution to the satis-faction of the District Supervisor shallbe at the expense of the lessee. Imme-diate corrective action shall be takenin all cases where pollution has oc-curred. Corrective action shall be sub-ject to modification when directed bythe District Supervisor.

(2) If the lessee fails to control andremove the pollution, the Director, incooperation with other appropriateAgencies of Federal, State, and localgovernments, or in cooperation withthe lessee, or both, shall have the rightto control and remove the pollution atthe lessee’s expense. Such action shallnot relieve the lessee of any responsi-bility provided for by law.

(b)(1) The District Supervisor may re-strict the rate of drilling fluid dis-charges or prescribe alternative dis-charge methods. The District Super-visor may also restrict the use of com-ponents which could cause unreason-able degradation to the marine envi-ronment. No petroleum-based sub-stances, including diesel fuel, may beadded to the drilling mud system with-out prior approval of the District Su-pervisor.

(2) Approval of the method of dis-posal of drill cuttings, sand, and otherwell solids shall be obtained from theDistrict Supervisor.

(3) All hydrocarbon-handling equip-ment for testing and production suchas separators, tanks, and treaters shallbe designed, installed, and operated toprevent pollution. Maintenance or re-pairs which are necessary to preventpollution of offshore waters shall beundertaken immediately.

(4) Curbs, gutters, drip pans, anddrains shall be installed in deck areasin a manner necessary to collect allcontaminants not authorized for dis-charge. Oil drainage shall be piped to aproperly designed, operated, and main-tained sump system which will auto-matically maintain the oil at a levelsufficient to prevent discharge of oilinto offshore waters. All gravity drainsshall be equipped with a water trap orother means to prevent gas in the sumpsystem from escaping through thedrains. Sump piles shall not be used asprocessing devices to treat or skim liq-uids but may be used to collect treat-ed-produced water, treated-producedsand, or liquids from drip pans anddeck drains and as a final trap for hy-drocarbon liquids in the event of equip-ment upsets. Improperly designed, op-erated, or maintained sump piles whichdo not prevent the discharge of oil intooffshore waters shall be replaced or re-paired.

(5) On artificial islands, all vesselscontaining hydrocarbons shall beplaced inside an impervious berm orotherwise protected to contain spills.Drainage shall be directed away fromthe drilling rig to a sump. Drains andsumps shall be constructed to preventseepage.

(6) Disposal of equipment, cables,chains, containers, or other materialsinto offshore waters is prohibited.

(c) Materials, equipment, tools, con-tainers, and other items used in theOuter Continental Shelf (OCS) whichare of such shape or configuration thatthey are likely to snag or damage fish-ing devices shall be handled andmarked as follows:

(1) All loose material, small tools,and other small objects shall be kept ina suitable storage area or a markedcontainer when not in use and in amarked container before transport overoffshore waters;

(2) All cable, chain, or wire segmentsshall be recovered after use and se-curely stored until suitable disposal isaccomplished;

(3) Skid-mounted equipment, port-able containers, spools or reels, anddrums shall be marked with the own-er’s name prior to use or transport overoffshore waters; and


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30 CFR Ch. II (7–1–01 Edition)§ 250.301

(4) All markings must clearly iden-tify the owner and must be durableenough to resist the effects of the envi-ronmental conditions to which theymay be exposed.

(d) Any of the items described inparagraph (c) of this section that arelost overboard shall be recorded on thefacility’s daily operations report, asappropriate, and reported to the Dis-trict Supervisor.

[53 FR 10690, Apr. 1, 1988, as amended at 56FR 32099, July 15, 1991. Redesignated at 63 FR29479, May 29, 1998]

§ 250.301 Inspection of facilities.

(a) Drilling and production facilitiesshall be inspected daily or at intervalsapproved or prescribed by the DistrictSupervisor to determine if pollution isoccurring. Necessary maintenance orrepairs shall be made immediately.Records of such inspections and repairsshall be maintained at the facility orat a nearby manned facility for 2 years.

[53 FR 10690, Apr. 1, 1988, as amended at 62FR 13996, Mar. 25, 1997. Redesignated at 63 FR29479, May 29, 1998]

§ 250.302 Definitions concerning airquality.

For purposes of §§ 250.303 and 250.304of this part:

Air pollutant means any combinationof agents for which the EnvironmentalProtection Agency (EPA) has estab-lished, pursuant to section 109 of theClean Air Act, national primary or sec-ondary ambient air quality standards.

Attainment area means, for any airpollutant, an area which is shown bymonitored data or which is calculatedby air quality modeling (or other meth-ods determined by the Administratorof EPA to be reliable) not to exceedany primary or secondary ambient airquality standards established by EPA.

Best available control technology(BACT) means an emission limitationbased on the maximum degree of reduc-tion for each air pollutant subject toregulation, taking into account energy,environmental and economic impacts,and other costs. The BACT shall beverified on a case-by-case basis by theRegional Supervisor and may includereductions achieved through the appli-cation of processes, systems, and tech-

niques for the control of each air pol-lutant.

Emission offsets means emission re-ductions obtained from facilities, ei-ther onshore or offshore, other thanthe facility or facilities covered by theproposed Exploration Plan or Develop-ment and Production Plan.

Existing facility is an OCS facility de-scribed in an Exploration Plan or a De-velopment and Production Plan sub-mitted or approved prior to June 2,1980.

Facility means any installation or de-vice permanently or temporarily at-tached to the seabed which is used forexploration, development, and produc-tion activities for oil, gas, or sulphurand which emits or has the potential toemit any air pollutant from one ormore sources. All equipment directlyassociated with the installation or de-vice shall be considered part of a singlefacility if the equipment is dependenton, or affects the processes of, the in-stallation or device. During produc-tion, multiple installations or deviceswill be considered to be a single facil-ity if the installations or devices aredirectly related to the production ofoil, gas, or sulphur at a single site. Anyvessel used to transfer production froman offshore facility shall be consideredpart of the facility while physically at-tached to it.

Nonattainment area means, for any airpollutant, an area which is shown bymonitored data or which is calculatedby air quality modeling (or other meth-ods determined by the Administratorof EPA to be reliable) to exceed anyprimary or secondary ambient air qual-ity standard established by EPA.

Projected emissions means emissions,either controlled or uncontrolled, froma source(s).

Source means an emission point. Sev-eral sources may be included within asingle facility.

Temporary facility means activitiesassociated with the construction ofplatforms offshore or with facilities re-lated to exploration for or developmentof offshore oil and gas resources whichare conducted in one location for lessthan 3 years.

Volatile organic compound (VOC)means any organic compound which isemitted to the atmosphere as a vapor.


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The unreactive compounds are exemptfrom the above definition.

[53 FR 10690, Apr. 1, 1988, as amended at 56FR 32100, July 15, 1991. Redesignated andamended at 63 FR 29479, 29485, May 29, 1998]

§ 250.303 Facilities described in a newor revised Exploration Plan or De-velopment and Production Plan.

(a) New plans. All Exploration Plansand Development and Production Plansshall include the information requiredto make the necessary findings underparagraphs (d) through (i) of this sec-tion, and the lessee shall comply withthe requirements of this section as nec-essary.

(b) Applicability of § 250.303 to existingfacilities. (1) The Regional Supervisormay review any Exploration Plan orDevelopment and Production Plan todetermine whether any facility de-scribed in the plan should be subject toreview under this section and has thepotential to significantly affect the airquality of an onshore area. To makethese decisions, the Regional Super-visor shall consider the distance of thefacility from shore, the size of the fa-cility, the number of sources plannedfor the facility and their operationalstatus, and the air quality status of theonshore area.

(2) For a facility identified by the Re-gional Supervisor in paragraph (b)(1) ofthis section, the Regional Supervisorshall require the lessee to refer to theinformation required in § 250.203(b)(19)or § 250.204(b)(12) of this part and tosubmit only that information requiredto make the necessary findings underparagraphs (d) through (i) of this sec-tion. The lessee shall submit this infor-mation within 120 days of the RegionalSupervisor’s determination or within alonger period of time at the discretionof the Regional Supervisor. The lesseeshall comply with the requirements ofthis section as necessary.

(c) Revised facilities. All revised Ex-ploration Plans and Development andProduction Plans shall include the in-formation required to make the nec-essary findings under paragraphs (d)through (i) of this section. The lesseeshall comply with the requirements ofthis section as necessary.

(d) Exemption formulas. To determinewhether a facility described in a new,

modified, or revised Exploration Planor Development and Production Plan isexempt from further air quality review,the lessee shall use the highest annual-total amount of emissions from the fa-cility for each air pollutant calculatedin § 250.203(b)(19)(i)(A) or§ 250.204(b)(12)(i)(A) of this part andcompare these emissions to the emis-sion exemption amount ‘‘E’’ for eachair pollutant calculated using the fol-lowing formulas: E=3400D2/3 for carbonmonoxide (CO); and E=33.3D for totalsuspended particulates (TSP), sulphurdioxide (SO2), nitrogen oxides (NOx),and VOC (where E is the emission ex-emption amount expressed in tons peryear, and D is the distance of the pro-posed facility from the closest onshorearea of a State expressed in statutemiles). If the amount of these projectedemissions is less than or equal to theemission exemption amount ‘‘E’’ forthe air pollutant, the facility is exemptfrom further air quality review re-quired under paragraphs (e) through (i)of this section.

(e) Significance levels. For a facilitynot exempt under paragraph (d) of thissection for air pollutants other thanVOC, the lessee shall use an approvedair quality model to determine whetherthe projected emissions of those airpollutants from the facility result inan onshore ambient air concentrationabove the following significance levels:

SIGNIFICANCE LEVELS: AIR POLLUTANTCONCENTRATIONS (µG/M3)

Air pollutantAveraging time (hours)

Annual 24 8 3 1

SO2 .................................... 1 5 ...... 25 ..........TSP ................................... 1 5 ...... .... ..........NO2 .................................... 1 .... ...... .... ..........CO ..................................... ............ .... 500 .... 2,000

(f) Significance determinations. (1) Theprojected emissions of any air pollut-ant other than VOC from any facilitywhich result in an onshore ambient airconcentration above the significancelevel determined under paragraph (e) ofthis section for that air pollutant,shall be deemed to significantly affectthe air quality of the onshore area forthat air pollutant.

(2) The projected emissions of VOCfrom any facility which is not exemptunder paragraph (d) of this section for


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that air pollutant shall be deemed tosignificantly affect the air quality ofthe onshore area for VOC.

(g) Controls required. (1) The projectedemissions of any air pollutant otherthan VOC from any facility, except atemporary facility, which significantlyaffect the quality of a nonattainmentarea, shall be fully reduced. This shallbe done through the application ofBACT and, if additional reductions arenecessary, through the application ofadditional emission controls orthrough the acquisition of offshore oronshore offsets.

(2) The projected emissions of any airpollutant other than VOC from any fa-cility which significantly affect the airquality of an attainment orunclassifiable area shall be reducedthrough the application of BACT.

(i) Except for temporary facilities,the lessee also shall use an approvedair quality model to determine whetherthe emissions of TSP or SO2 that re-main after the application of BACTcause the following maximum allow-able increases over the baseline con-centrations established in 40 CFR 52.21to be exceeded in the attainment orunclassifiable area:

MAXIMUM ALLOWABLE CONCENTRATIONINCREASES (µG/M3)

Air pollutant

Averaging times

Annualmean 1

24-hourmax-imum

3-hourmax-imum

Class I:TSP ........................................ 5 10 ............SO2 ........................................ 2 5 25

Class II:TSP ........................................ 19 37 ............SO2 ........................................ 20 91 512

Class III:TSP ........................................ 37 75 ............SO2 ........................................ 40 182 700

1 For TSP—geometric; For SO2—arithmetric.

No concentration of an air pollutantshall exceed the concentration per-mitted under the national secondaryambient air quality standard or theconcentration permitted under the na-tional primary air quality standard,whichever concentration is lowest forthe air pollutant for the period of expo-sure. For any period other than the an-nual period, the applicable maximumallowable increase may be exceeded

during one such period per year at anyone onshore location.

(ii) If the maximum allowable in-creases are exceeded, the lessee shallapply whatever additional emissioncontrols are necessary to reduce or off-set the remaining emissions of TSP orSO2 so that concentrations in the on-shore ambient air of an attainment orunclassifiable area do not exceed themaximum allowable increases.

(3)(i) The projected emissions of VOCfrom any facility, except a temporaryfacility, which significantly affect theonshore air quality of a nonattainmentarea shall be fully reduced. This shallbe done through the application ofBACT and, if additional reductions arenecessary, through the application ofadditional emission controls orthrough the acquisition of offshore oronshore offsets.

(ii) The projected emissions of VOCfrom any facility which significantlyaffect the onshore air quality of an at-tainment area shall be reduced throughthe application of BACT.

(4)(i) If projected emissions from a fa-cility significantly affect the onshoreair quality of both a nonattainmentand an attainment or unclassifiablearea, the regulatory requirements ap-plicable to projected emissions signifi-cantly affecting a nonattainment areashall apply.

(ii) If projected emissions from a fa-cility significantly affect the onshoreair quality of more than one class ofattainment area, the lessee must re-duce projected emissions to meet themaximum allowable increases specifiedfor each class in paragraph (g)(2)(i) ofthis section.

(h) Controls required on temporary fa-cilities. The lessee shall apply BACT toreduce projected emissions of any airpollutant from a temporary facilitywhich significantly affect the air qual-ity of an onshore area of a State.

(i) Emission offsets. When emissionoffsets are to be obtained, the lesseemust demonstrate that the offsets areequivalent in nature and quantity tothe projected emissions that must bereduced after the application of BACT;a binding commitment exists betweenthe lessee and the owner or owners ofthe source or sources; the appropriateair quality control jurisdiction has


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been notified of the need to revise theState Implementation Plan to includethe information regarding the offsets;and the required offsets come fromsources which affect the air quality ofthe area significantly affected by thelessee’s offshore operations.

(j) Review of facilities with emissionsbelow the exemption amount. If, duringthe review of a new, modified, or re-vised Exploration Plan or Developmentand Production Plan, the Regional Su-pervisor determines or an affectedState submits information to the Re-gional Supervisor which demonstrates,in the judgment of the Regional Super-visor, that projected emissions from anotherwise exempt facility will, eitherindividually or in combination withother facilities in the area, signifi-cantly affect the air quality of an on-shore area, then the Regional Super-visor shall require the lessee to submitadditional information to determinewhether emission control measures arenecessary. The lessee shall be given theopportunity to present information tothe Regional Supervisor which dem-onstrates that the exempt facility isnot significantly affecting the air qual-ity of an onshore area of the State.

(k) Emission monitoring requirements.The lessee shall monitor, in a mannerapproved or prescribed by the RegionalSupervisor, emissions from the facil-ity. The lessee shall submit this infor-mation monthly in a manner and formapproved or prescribed by the RegionalSupervisor.

(l) Collection of meteorological data.The Regional Supervisor may requirethe lessee to collect, for a period oftime and in a manner approved or pre-scribed by the Regional Supervisor,and submit meteorological data from afacility.

[53 FR 10690, Apr. 1, 1988; 53 FR 19856, May 31,1988; 53 FR 26067, July 11, 1988. Redesignatedand amended at 63 FR 29479, 29485, May 29,1998]

§ 250.304 Existing facilities.(a) Process leading to review of an exist-

ing facility. (1) An affected State mayrequest that the Regional Supervisorsupply basic emission data from exist-ing facilities when such data are need-ed for the updating of the State’s emis-sion inventory. In submitting the re-

quest, the State must demonstratethat similar offshore and onshore fa-cilities in areas under the State’s juris-diction are also included in the emis-sion inventory.

(2) The Regional Supervisor may re-quire lessees of existing facilities tosubmit basic emission data to a Statesubmitting a request under paragraph(a)(1) of this section.

(3) The State submitting a requestunder paragraph (a)(1) of this sectionmay submit information from its emis-sion inventory which indicates thatemissions from existing facilities maybe significantly affecting the air qual-ity of the onshore area of the State.The lessee shall be given the oppor-tunity to present information to theRegional Supervisor which dem-onstrates that the facility is not sig-nificantly affecting the air quality ofthe State.

(4) The Regional Supervisor shallevaluate the information submittedunder paragraph (a)(3) of this sectionand shall determine, based on the basicemission data, available meteorolog-ical data, and the distance of the facil-ity or facilities from the onshore area,whether any existing facility has thepotential to significantly affect the airquality of the onshore area of theState.

(5) If the Regional Supervisor deter-mines that no existing facility has thepotential to significantly affect the airquality of the onshore area of the Statesubmitting information under para-graph (a)(3) of this section, the Re-gional Supervisor shall notify theState of and explain the reasons forthis finding.

(6) If the Regional Supervisor deter-mines that an existing facility has thepotential to significantly affect the airquality of an onshore area of the Statesubmitting information under para-graph (a)(3) of this section, the Re-gional Supervisor shall require the les-see to refer to the information require-ments under § 250.203(b)(19) or250.204(b)(12) of this part and submitonly that information required tomake the necessary findings underparagraphs (b) through (e) of this sec-tion. The lessee shall submit this infor-mation within 120 days of the RegionalSupervisor’s determination or within a


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longer period of time at the discretionof the Regional Supervisor. The lesseeshall comply with the requirements ofthis section as necessary.

(b) Exemption formulas. To determinewhether an existing facility is exemptfrom further air quality review, thelessee shall use the highest annualtotal amount of emissions from the fa-cility for each air pollutant calculatedin § 250.203(b)(19)(i)(A) or250.204(b)(12)(i)(A) of this part and com-pare these emissions to the emissionexemption amount ‘‘E’’ for each airpollutant calculated using the fol-lowing formulas: E=3400D2/3 for CO; andE=33.3D for TSP, SO2, NOX, and VOC(where E is the emission exemptionamount expressed in tons per year, andD is the distance of the facility fromthe closest onshore area of the Stateexpressed in statute miles). If theamount of projected emissions is lessthan or equal to the emission exemp-tion amount ‘‘E’’ for the air pollutant,the facility is exempt for that air pol-lutant from further air quality reviewrequired under paragraphs (c) through(e) of this section.

(c) Significance levels. For a facilitynot exempt under paragraph (b) of thissection for air pollutants other thanVOC, the lessee shall use an approvedair quality model to determine whetherprojected emissions of those air pollut-ants from the facility result in an on-shore ambient air concentration abovethe following significance levels:

SIGNIFICANCE LEVELS: AIR POLLUTANTCONCENTRATIONS (µG/M3)

Air pollutantAveraging time (hours)

Annual 24 8 3 1

SO2 .................................... 1 5 ...... 25 ..........TSP ................................... 1 5 ...... .... ..........NO2 .................................... 1 .... ...... .... ..........CO ..................................... ............ .... 500 .... 2,000

(d) Significance determinations. (1) Theprojected emissions of any air pollut-ant other than VOC from any facilitywhich result in an onshore ambient airconcentration above the significancelevels determined under paragraph (c)of this section for that air pollutantshall be deemed to significantly affectthe air quality of the onshore area forthat air pollutant.

(2) The projected emissions of VOCfrom any facility which is not exemptunder paragraph (b) of this section forthat air pollutant shall be deemed tosignificantly affect the air quality ofthe onshore area for VOC.

(e) Controls required. (1) The projectedemissions of any air pollutant whichsignificantly affect the air quality ofan onshore area shall be reducedthrough the application of BACT.

(2) The lessee shall submit a compli-ance schedule for the application ofBACT. If it is necessary to cease oper-ations to allow for the installation ofemission controls, the lessee may applyfor a suspension of operations underthe provisions of § 250.174 of this part.

(f) Review of facilities with emissionsbelow the exemption amount. If, duringthe review of the information requiredunder paragraph (a)(6) of this section,the Regional Supervisor determines oran affected State submits informationto the Regional Supervisor which dem-onstrates, in the judgment of the Re-gional Supervisor, that projected emis-sions from an otherwise exempt facil-ity will, either individually or in com-bination with other facilities in thearea, significantly affect the air qual-ity of an onshore area, then the Re-gional Supervisor shall require the les-see to submit additional information todetermine whether control measuresare necessary. The lessee shall be giventhe opportunity to present informationto the Regional Supervisor which dem-onstrates that the exempt facility isnot significantly affecting the air qual-ity of an onshore area of the State.

(g) Emission monitoring requirements.The lessee shall monitor, in a mannerapproved or prescribed by the RegionalSupervisor, emissions from the facilityfollowing the installation of emissioncontrols. The lessee shall submit thisinformation monthly in a manner andform approved or prescribed by the Re-gional Supervisor.

(h) Collection of meteorological data.The Regional Supervisor may requirethe lessee to collect, for a period oftime and in a manner approved or pre-scribed by the Regional Supervisor,


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and submit meteorological data from afacility.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11,1988. Redesignated and amended at 63 FR29479, 29485, May 29, 1998; 64 FR 72794, Dec. 28,1999]

Subpart D—Oil and Gas DrillingOperations

§ 250.400 Control of wells.The lessee shall take necessary pre-

cautions to keep its wells under con-trol at all times. The lessee shall uti-lize the best available and safest drill-ing technology in order to enhance theevaluation of conditions of abnormalpressure and to minimize the potentialfor the well to flow or kick. The lesseeshall utilize personnel who are trainedand competent and shall utilize andmaintain equipment and materials nec-essary to assure the safety and protec-tion of personnel, equipment, naturalresources, and the environment.

§ 250.401 General requirements.(a) Fitness of drilling unit. (1) Drilling

units shall be capable of withstandingthe oceanographic, meteorological, andice conditions for the proposed seasonand location of operations.

(2) Prior to commencing operation,drilling units shall be available forcomplete inspection by the District Su-pervisor.

(3) The lessee shall provide informa-tion and data on the fitness of thedrilling unit to perform the proposeddrilling operation. The informationshall be submitted with or prior to thesubmission of Form MMS–123, Applica-tion for Permit to Drill (APD), in ac-cordance with § 250.414. The DistrictSupervisor may require the submissionof a third-party review of the design ofdrilling units which are of a unique de-sign and/or not proven for use in theproposed environment if the DistrictSupervisor believes that the informa-tion submitted by the lessee is insuffi-cient to demonstrate suitability of theunit for use at the proposed drill site.A design Certified Verification Agentapproved in accordance with § 250.903 ofthis part shall be used for any requiredthird-party review.

(b) Drilling unit safety devices. (1) Nolater than May 31, 1989, all drilling

units shall be equipped with a safetydevice which is designed to prevent thetraveling block from striking thecrown block. The device shall bechecked for proper operation weeklyand after each drill-line slipping oper-ation. The results of the operationalcheck shall be entered in the driller’sreport.

(2) No later than May 31, 1989, diesel-engine air intakes shall be equippedwith a device to shut down the dieselengine in the event of runaway. Dieselengines which are continuously at-tended shall be equipped with either re-mote operated manual or automaticshutdown devices. Diesel engines whichare not continuously attended shall beequipped with automatic shutdown de-vices.

(c) Oceanographic, meteorological, anddrilling unit performance data. Wheresuch information is not otherwise read-ily available, upon request of the Dis-trict Supervisor, lessees shall collectand report oceanographic, meteorolog-ical, and drilling unit performancedata, and monitor ice conditions, if ap-plicable, during the period of oper-ations. The type of information to becollected and reported will be deter-mined by the District Supervisor in theinterests of safe conduct of operationsand the structural integrity of thedrilling unit.

(d) Foundation requirements. When thelessee fails to provide sufficient infor-mation pursuant to §§ 250.203 and 250.204of this part to support a determinationthat the seafloor is capable of sup-porting a specific bottom-founded drill-ing unit under the site-specific soil andoceanographic conditions, the DistrictSupervisor may require that additionalsurveys and soil borings be performedand the results be submitted for reviewand evaluation by the District Super-visor before approval is granted forcommencing drilling operations.

(e) Tests, surveys, and samples. (1) Thelessee shall conduct tests, obtain welland mud logs or surveys, and take sam-ples to determine the reservoir energy;the presence, quantity, and quality ofoil, gas, sulphur, and water; and theamount of pressure in the formationspenetrated. The lessee shall take for-mation samples or cores to determine


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30 CFR Ch. II (7–1–01 Edition)§§ 250.402–250.403

the identity, fluid content, and charac-teristics of any penetrated formationin accordance with requirements ap-proved or prescribed by the DistrictSupervisor.

(2) Inclinational surveys shall be ob-tained on all vertical wells at intervalsnot exceeding 1,000 feet during the nor-mal course of drilling. Directional sur-veys giving both inclination and azi-muth shall be obtained on all direc-tional wells at intervals not exceeding500 feet during the normal course ofdrilling and at intervals not exceeding100 feet in all portions of the hole whenangle-changes are planned.

(3) On both vertical and directionallydrilled wells, directional surveys givingboth inclination and azimuth shall beobtained at intervals not exceeding 500feet prior to or upon setting surface orintermediate casing, liners, and attotal depth. Composite directional sur-veys shall be prepared with the inter-val shown from the bottom of the con-ductor casing or, in the absence of con-ductor casing, from the bottom of thedrive or structural casing to totaldepth. In calculating all surveys, a cor-rection from the true north to Uni-versal-Transverse-Mercator-Grid-northor Lambert-Grid-north shall be madeafter making the magnetic-to-true-north correction. A compositedipmeter directional survey or a com-posite measurement-while-drilling(MWD) directional survey including alisting of the directionally computedinclinations and azimuths on a wellclassified as vertical will be acceptableas fulfilling the applicable require-ments of this paragraph. In the event acomposite MWD survey is run, amultishot survey shall be obtained ateach casing point in order to confirmthe MWD results.

(4) Wells are classified as vertical ifthe calculated average of inclinationreadings weighted by the respective in-terval lengths between readings fromsurface to drilled depth does not exceed3 degrees from the vertical. When thecalculated average inclination readingsweighted by the length of the respec-tive interval between readings from thesurface to drilled depth exceeds 3 de-grees, the well is classified as direc-tional.

(5) The Regional Supervisor at the re-quest of a holder of an adjoining leasemay, for the protection of correlativerights, furnish a copy of the directionalsurvey for a well drilled within 500 feetof the adjacent lease to that lease-holder.

(f) Fixed drilling platforms. Applica-tions for installation of fixed drillingplatforms or structures, including arti-ficial islands, shall be submitted in ac-cordance with the provisions of subpartI, Platforms and Structures, of thispart. Mobile drilling units which havetheir jacking equipment removed orhave been otherwise immobilized areclassified as fixed drilling platforms.

(g) Equipment movement. The move-ment of drilling rigs and related equip-ment on and off an offshore platform orfrom well to well on the same offshoreplatform, including rigging up and rig-ging down, shall be conducted in a safemanner. All wells in the same well-baywhich are capable of producing hydro-carbons shall be shut in below the sur-face with a pump-through-type tubingplug and at the surface with a closedmaster valve prior to moving such rigsand related equipment, unless other-wise approved by the District Super-visor. A closed surface-controlled sub-surface safety valve of the pump-through-type may be used in lieu of thepump-through-type tubing plug, pro-vided that the surface control has beenlocked out.

(h) Emergency shutdown system. Whendrilling operations are conducted on aplatform where there are other hydro-carbon-producing wells or other hydro-carbon flow, an Emergency ShutdownSystem (ESD) manually controlled sta-tion shall be installed near the driller’sconsole.

[53 FR 10690, Apr. 1, 1988; 53 FR 12227, Apr. 13,1988, as amended at 54 FR 50616, Dec. 8, 1989;55 FR 47752, Nov. 15, 1990; 58 FR 49928, Sept.24, 1993. Redesignated and amended at 63 FR29479, 29485, May 29, 1998]

§§ 250.402–250.403 [Reserved]

§ 250.404 Well casing and cementing.(a) General requirements. (1) For the

purpose of this subpart, the casingstrings in order of normal installationare as follows:

(i) Drive or structural,


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(ii) Conductor,(iii) Surface,(iv) Intermediate, and(v) Production casing.(2) The lessee shall case and cement

all wells with a sufficient number ofstrings of casing and quantity andquality of cement in a manner nec-essary to prevent release of fluids fromany stratum through the wellbore (di-rectly or indirectly) into offshore wa-ters, prevent communication betweenseparate hydrocarbon-bearing strata,protect freshwater aquifers from con-tamination, support unconsolidatedsediments, and otherwise provide ameans of control of the formation pres-sures and fluids. Cement composition,placement techniques, and waitingtime shall be designed and conductedso that the cement in place behind thebottom 500 feet of casing or totallength of annular cement fill, if less,attains a minimum compressivestrength of 500 pounds per square inch(psi). Cement placed across permafrostzones shall be designed to set beforefreezing and have a low heat of hydra-tion.

(3) The lessee shall install casing de-signed to withstand the anticipatedstresses imposed by tensile, compres-sive, and buckling loads; burst and col-lapse pressures; thermal effects; andcombinations thereof. Safety factors inthe casing program design shall be ofsufficient magnitude to provide wellcontrol during drilling and to assuresafe operations for the life of the well.Any portion of an annulus opposite apermafrost zone which is not protectedby cement shall be filled with a liquidwhich has a freezing point below theminimum permafrost temperature toprevent internal freezeback and whichis treated to minimize corrosion.

(4) In cases where cement has filledthe annular space back to the mudline, the cement may be washed out ordisplaced to a depth not exceeding thedepth of the structural casing shoe tofacilitate casing removal upon wellabandonment if the District Supervisordetermines that subsurface protectionagainst damage to freshwater aquifersand permafrost zones and against dam-age caused by adverse loads, pressures,and fluid flows is not jeopardized.

(5) If there are indications of inad-equate cementing (such as lost returns,cement channeling, or mechanical fail-ure of equipment), the lessee shallevaluate the adequacy of the cement-ing operations by pressure testing thecasing shoe, running a cement bondlog, running a temperature survey, or acombination thereof before continuingoperations. If the evaluation indicatesinadequate cementing, the lessee shallre-cement or take other remedial ac-tions as approved by the District Su-pervisor.

(6) A pressure-integrity test shall berun below the surface casing, the inter-mediate casing(s), and liner(s) used asintermediate casing(s). The DistrictSupervisor may require a pressure-in-tegrity test to be run at the conductorcasing shoe due to local geologic condi-tions or planned casing setting depths.Pressure-integrity tests shall be madeafter drilling new hole below the casingshoe and before drilling more than 50feet of new hole below a respective cas-ing string. These tests shall be con-ducted either by testing to formationleak-off or by testing to a predeter-mined equivalent mud weight as speci-fied in the approved APD. A safe mar-gin, as approved by the District Super-visor, shall be maintained between themud weight in use and the equivalentmud weight at the casing shoe as deter-mined in the pressure-integrity test.Drilling operations shall be suspendedwhen the safe margin is not main-tained. Pressure-integrity and pore-pressure test results and related hole-behavior observations, such as gas-cutmud and well kicks made during thecourse of drilling, shall be used in ad-justing the drilling mud program andthe approved setting depth of the nextcasing string. The results of all testsand of hole-behavior observations madeduring the course of drilling related toformation integrity and pore pressureshall be recorded in the driller’s report.

(b) Drive or structural casing. This cas-ing shall be set by driving, jetting, ordrilling to a minimum depth as may beprescribed or approved by the DistrictSupervisor, in order to support uncon-solidated deposits and to provide holestability for initial drilling operations.If this portion of the hole is drilled, aquantity of cement sufficient to fill the


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30 CFR Ch. II (7–1–01 Edition)§ 250.404

annular space back to the mud lineshall be used.

(c) Conductor and surface casing re-quirements. (1) Conductor and surfacecasing setting depths. Conductor andsurface casing design and settingdepths shall be based upon relevant en-gineering and geologic factors includ-ing the presence or absence of hydro-carbons, potential hazards, and waterdepths. The approved casing settingdepths may be adjusted when thechange is approved by the District Su-pervisor to permit the casing shoe tobe set in a competent formation orbelow formations which should be iso-lated from the wellbore by casing forsafer drilling operations. However, theconductor casing shall be set imme-diately prior to drilling into forma-tions known to contain oil or gas or, ifthe presence of oil or gas is unknown,upon encountering a formation con-taining oil or gas. Upon encounteringunexpected formation pressures, thelessee shall submit a revised casingprogram to the District Supervisor forapproval. The District Supervisor maypermit a lessee to drill a well withoutsetting conductor casing provided theinformation from approved logging andmud-monitoring programs for wellspreviously drilled in the immediatevacinity combined with other availablegeologic data are sufficient to dem-onstrate the absence of shallow hydro-carbons or hazards.

(2) Conductor casing cementing require-ments. Conductor casing shall be ce-mented with a quantity of cement thatfills the calculated annular space backto the mud line except as applicable tothe bottom of an excavation (gloryhole) or to the surface of an artificialisland. Cement fill in annular spacesshall be verified by the observation ofcement returns. In the event that ob-servation of cement returns is not fea-sible, additional quantities of cementshall be used to assure fill to the mudline.

(3) Surface casing cementing require-ments. (i) Surface casing shall be ce-mented with a quantity of cement thatfills the calculated annular space to atleast 200 feet inside the conductor cas-ing. When geologic conditions such asnear-surface fractures and faultingexist, surface casing shall be cemented

with a quantity of cement that fills thecalculated annular space to the mudline, or as approved or prescribed bythe District Supervisor.

(ii) For floating drilling operations, alesser volume of cement may be used toprevent sealing the annular space be-tween the conductor casing and surfacecasing if the District Supervisor deter-mines that the uncemented space isnecessary to provide protection fromburst and collapse pressures which maybe applied inadvertently to the annulusbetween casings during blowout pre-venter (BOP) testing operations. Anyannular space open to the drilled holeshall be sealed in accordance with therequirements for abandonment in sub-part G, Abandonment of Wells, of thispart.

(d) Intermediate casing requirements.(1) Intermediate casing string(s) shallbe set for protection when geologiccharacteristics or wellbore conditions,as anticipated or as encountered, so in-dicate.

(2) Quantities of cement that coverand isolate all hydrocarbon-bearingzones in the well and isolate abnormalpressure intervals from normal pres-sure intervals shall be used. This re-quirement for isolation may be satis-fied by squeeze cementing prior tocompletion, suspension of operations,or abandonment, whichever occursfirst. Sufficient cement shall be used toprovide annular fill-up to a minimumof 500 feet above the zones to be iso-lated or 500 feet above the casing shoein wells where zonal coverage is not re-quired.

(3) If a liner is to be used as an inter-mediate string below a surface casingstring, it shall be lapped a minimum of100 feet into the previous casing stringand cemented as required for inter-mediate casing. When a liner is to beused as production casing below a sur-face casing string, it shall be extendedto the surface and cemented to avoidsurface casing being used as productioncasing.

(e) Production casing requirements. (1)Production casing shall be cemented tocover or isolate all zones above theshoe which contain hydrocarbons; butin any case, a volume sufficient to fillthe annular space at least 500 feet


295


above the uppermost hydrocarbon-bearing zone shall be used.

(2) When a liner is to be used as pro-duction casing below intermediate cas-ing, it shall be lapped a minimum of 100feet into the previous casing string andcemented as required for the produc-tion casing.

§ 250.405 Pressure testing of casing.(a) Prior to drilling the plug after ce-

menting and in the cases of plugs inproduction casing strings and linersnot planned to be subsequently drilledout, all casings, except the drive orstructural casing, shall be pressuretested to 70 percent of the minimum in-ternal-yield pressure of the casing or asotherwise approved or required by theDistrict Supervisor. If the pressure de-clines more than 10 percent in 30 min-utes or if there is another indication ofa leak, the casing shall be recemented,repaired, or an additional casing stringrun and the casing pressure testedagain. Additional remedial actionsshall be taken until a satisfactory pres-sure test is obtained. The results of allcasing pressure tests shall be recordedin the driller’s report.

(b) Each production liner lap shall betested to a minimum of 500 psi aboveformation fracture pressure at the shoeof the casing into which the liner islapped, or as otherwise approved or re-quired by the District Supervisor. Thedrilling liner-lap test pressure shall beequal to or exceed the pressure thatwill be encountered at the liner lapwhen conducting the planned pressure-integrity test below the liner shoe. Thetest results shall be recorded on thedriller’s report. If the test indicates animproper seal, remedial action shall betaken which provides a proper seal asdemonstrated by a satisfactory pres-sure test.

(c) In the event of prolonged drill-pipe rotation within a casing stringrun to the surface or extended oper-ations such as milling, fishing, jarring,washing over, and other operationswhich could damage the casing, thecasing shall be pressure tested or eval-uated by a logging technique such as acaliper log every 30 days. The evalua-tion results shall be submitted to theDistrict Supervisor with a determina-tion of effects of operations on the in-

tegrity of the casing for continuedservice during drilling operations andover the producing life of the well. Ifthe integrity of the casing in the wellhas deteriorated to an unsafe level, re-medial operations shall be conductedor additional casing set in accordancewith a plan approved by the DistrictSupervisor prior to continuing drillingoperations.

(d) After cementing any string of cas-ing other than the structural casingstring, drilling shall not be resumeduntil there has been a time lapse of 8hours under pressure for the conductorcasing string and 12 hours under pres-sure for all other casing strings. Ce-ment is considered under pressure ifone or more float valves are shown tobe holding the cement in place or whenother means of holding pressure areused.

§ 250.406 Blowout preventer systemsand system components.

(a) General. The BOP systems andsystem components shall be designed,installed, used, maintained, and testedto assure well control.

(b) BOP stacks. The BOP stacks shallconsist of an annular preventer and thenumber of ram-type preventers as spec-ified under paragraphs (e)(1), (f), and(g) of this section. The pipe rams shallbe of a proper size(s) to fit the drillpipe in use.

(c) Working pressure. The working-pressure rating of any BOP componentshall exceed the anticipated surfacepressure to which it may be subjected.The District Supervisor may approve alower working pressure rating for theannular preventer if the lessee dem-onstrates that the anticipated or ac-tual well conditions will not place de-mands above its rated working pres-sure. (Refer to related requirements in§ 250.414(f)(3)(ii) of this part.)

(d) BOP equipment. All BOP systemsshall be equipped and provided with thefollowing:

(1) An accumulator system whichshall provide sufficient capacity tosupply 1.5 times the volume of fluidnecessary to close and hold closed allBOP equipment units with a minimumpressure of 200 psi above the prechargepressure without assistance from a


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charging system. No later than Decem-ber 1, 1988, accumulator regulators sup-plied by rig air and without a sec-ondary source of pneumatic supply,shall be equipped with manual over-rides or alternately, other devices pro-vided to ensure capability of hydraulicoperations if rig air is lost.

(2) A backup to the primary accumu-lator-charging system which shall beautomatic, supplied by a power sourceindependent from the power source tothe primary accumulator-charging sys-tem, and possess sufficient capabilityto close all BOP components and holdthem closed.

(3) At least one operable remote BOPcontrol station in addition to the oneon the drilling floor. This control sta-tion shall be in a readily accessible lo-cation away from the drilling floor.

(4) A drilling spool with side outletsif side outlets are not provided in thebody of the BOP stack to provide forseparate kill and choke lines.

(5) For surface BOP systems, a chokeand a kill line each equipped with twofull-opening valves. At least one of thevalves on the choke line shall be re-motely controlled. At least one of thevalves on the kill line shall be re-motely controlled except that a checkvalve may be installed on the kill linein lieu of the remotely controlled valveprovided two readily accessible manualvalves are in place and the check valveis placed between the manual valvesand the pump. For subsea BOP sys-tems, a choke and a kill line eachequipped with two full-opening valves.At least one of the valves on the chokeline and at least one of the valves onthe kill line shall be remotely con-trolled.

(6) A fill-up line above the uppermostpreventer.

(7) A choke manifold suitable for theanticipated pressures to which it maybe subjected, method of well control tobe employed, surrounding environ-ment, and corrosiveness, volume, andabrasiveness of fluids. The choke mani-fold shall also meet the following re-quirements:

(i) Manifold and choke equipmentsubject to well and/or pump pressureshall have a rated working pressure atleast as great as the rated workingpressure of the ram-type BOP’s or as

otherwise approved by the District Su-pervisor;

(ii) All components of the chokemanifold system shall be protectedfrom the danger, if any, of freezing byheating, draining, or filling with properfluids; and

(iii) When buffer tanks are installeddownstream of the choke assembliesfor the purpose of manifolding thebleed lines together, isolation valvesshall be installed on each line.

(8) Valves, pipes, flexible steel hoses,and other fittings upstream of, and in-cluding, the choke manifold with pres-sure ratings at least as great as therated working pressure of the ram-typeBOP’s or as otherwise approved by theDistrict Supervisor.

(9) A wellhead assembly with a ratedworking pressure that exceeds the an-ticipated surface pressure to which itmay be subjected.

(10) The following system compo-nents:

(i) On a conventional drilling rig, akelly cock installed below the swivel(upper kelly cock), essentially full-opening, and a similar valve of such de-sign that it can be run through theBOP stack (strippable) installed at thebottom of the kelly (lower kelly cock).With a mud motor in service and whileusing drill pipe in lieu of a kelly, onekelly cock located above and onestrippable kelly cock located below thejoint of drill pipe employed in lieu of akelly. On a top-drive system equippedwith a remote controlled valve, a sec-ond and lower strippable valve of a con-ventional kelly cock or comparabletype either manually or remotely con-trolled. All required manual and re-motely controlled valves of a kellycock or comparable type in a top-drivesystem must be essentially full-open-ing and tested according to the testpressure and test frequency as statedin § 250.407 of this part. A wrench to fiteach manually operable valve in a con-ventional drilling rig, mud motor, andtop-drive system shall be stored in a lo-cation readily accessible to the drillingcrew.

(ii) An inside BOP and an essentiallyfull-opening drill-string safety valve inthe open position on the rig floor at alltimes while drilling operations arebeing conducted. These valves shall be


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maintained on the rig floor to fit allconnections that are in the drill string.A wrench to fit the drill-string safetyvalve shall be stored in a location read-ily accessible to the drilling crew.

(iii) A safety valve available on therig floor assembled with the properconnection to fit the casing stringbeing run in the hole.

(11) Locking devices installed on theram-type preventers.

(e) Subsea BOP requirements. (1) Priorto drilling below surface and inter-mediate casing, a BOP system shall beinstalled consisting of at least four re-mote controlled, hydraulically oper-ated BOP’s including at least twoequipped with pipe rams, one withblind-shear rams, and one annulartype. A subsea accumulator closingunit or a suitable alternate approvedby the District Supervisor is requiredto provide fast closure of the BOP com-ponents and to operate all criticalfunctions in case of a loss of the powerfluid connection to the surface. Whenproposed casing setting depths or localgeology indicate the need for a BOP toprovide safety during the drilling ofthe surface hole, the District Super-visor may require that a subsea BOPsystem be installed prior to drillingbelow the conductor casing.

(2) The BOP system shall include op-erable dual-pod control systems nec-essary to ensure proper and inde-pendent operation of the BOP systemfunctions when drilling below the sur-face casing.

(3) Prior to the removal of the ma-rine riser, the riser shall be displacedwith seawater. Sufficient hydrostaticpressure or other suitable precautions,such as mechanical or cement plugs orclosing the BOP, shall be maintainedwithin the wellbore to compensate forthe reduction in pressure and to main-tain a safe controlled well condition.

(4) Any necessary repair or replace-ment of the BOP system or a systemcomponent after installation shall beaccomplished under safe controlledconditions, (e.g., after casing has beencemented but prior to drilling out thecasing shoe or by setting a cementplug, bridge plug, or a packer).

(5) When a subsea BOP system is tobe used in an area which is subject toice scour, the BOP stack shall be

placed in an excavation (glory hole) ofsufficient depth to assure that the topof the stack is below the deepest prob-able ice-scour depth.

(f) Surface BOP requirements. Prior todrilling below surface or intermediatecasing, a BOP system shall be installedconsisting of at least four remote con-trolled, hydraulically operated BOP’sincluding at least two equipped withpipe rams, one with blind rams, andone annular type.

(g) Tapered drill-string operations. (1)Prior to commencing tapered drill-pipeoperations, the BOP stack shall beequipped with conventional and/orvariable-bore pipe rams installed intwo or more ram cavities to providethe following:

(i) Two sets of pipe rams capable ofsealing around the larger size drillstring, and

(ii) One set of pipe rams capable ofsealing around the smaller size drillstring.

(2) Subsea BOP systems shall haveblind-shear ram capability. SurfaceBOP systems shall have blind ram ca-pability.

[53 FR 10690, Apr. 1, 1988. Redesignated andamended at 63 FR 29479, 29485, May 29, 1998; 63FR 29607, June 1, 1998]

§ 250.407 Blowout preventer (BOP) sys-tem tests, inspections, and mainte-nance.

(a) BOP pressure testing timeframes.You must pressure test your BOP sys-tem:

(1) When installed;(2) Before 14 days have elapsed since

your last BOP pressure test. You mustbegin to test your BOP system before12 a.m. (midnight) on the 14th day fol-lowing the conclusion of the previoustest. However, the District Supervisormay require testing every 7 days if con-ditions or BOP performance warrant;and

(3) Before drilling out each string ofcasing or a liner. The District Super-visor may allow you to omit this test ifyou did not remove the BOP stack torun the casing string or liner and therequired BOP-test pressures for thenext section of the hole are not greaterthan the test pressures for the previousBOP test. You must indicate in your


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APD which casing strings and linersmeet these criteria.

(b) BOP test pressures. When you testthe BOP system, you must conduct alow pressure and a high pressure testfor each BOP component. Each indi-vidual pressure test must hold pressurelong enough to demonstrate that thetested component(s) holds the requiredpressure. Required test pressures are asfollows:

(1) All low pressure tests must be be-tween 200 and 300 psi. Any initial pres-sure above 300 psi must be bled back toa pressure between 200 and 300 psi be-fore starting the test. If the initialpressure exceeds 500 psi, you mustbleed back to zero and reinitiate thetest. You must conduct the low pres-sure test before the high pressure test.

(2) For ram-type BOP’s, choke mani-fold, and other BOP equipment, thehigh pressure test must equal the ratedworking pressure of the equipment orthe pressure otherwise approved by theDistrict Supervisor; and

(3) For annular-type BOP’s, the highpressure test must equal 70 percent ofthe rated working pressure of theequipment or the pressure otherwiseapproved by the District Supervisor.

(c) Duration of pressure test. Each testmust hold the required pressure for 5minutes.

(1) For surface BOP systems and sur-face equipment of a subsea BOP sys-tem, a 3-minute test duration is ac-ceptable if you record your test pres-sures on the outermost half of a 4-hourchart, on a 1-hour chart, or on a digitalrecorder.

(2) If the equipment does not hold therequired pressure during a test, youmust remedy the problem and retestthe affected component(s).

(d) Additional BOP testing require-ments. You must:

(1) Use water to test a surface BOPsystem;

(2) Stump test a subsurface BOP sys-tem before installation. You must usewater to stump test a subsea BOP sys-tem. You may use drilling fluids toconduct subsequent tests of a subseaBOP system;

(3) Alternate tests between controlstations and pods. If a control stationor pod is not functional, you must sus-

pend further drilling operations untilthat station or pod is operable;

(4) Pressure test the blind or blind-shear ram during a stump test and atall casing points. Additionally, the in-terval between any blind or blind-shearram tests may not exceed 30 days;

(5) Function test annulars and ramsevery 7 days between pressure tests;

(6) Pressure-test variable bore-piperams against all sizes of pipe in use, ex-cluding drill collars and bottom-holetools;

(7) Test affected BOP components fol-lowing the disconnection or repair ofany well-pressure containment seal inthe wellhead or BOP stack assembly;

(8) Actuate safety valves assembledwith proper casing connections prior torunning casing, and

(9) If you install casing rams, youmust test the ram bonnet before run-ning casing.

(e) Postponing BOP tests. You maypostpone a BOP test if you have well-control problems such as lost circula-tion, formation fluid influx, or stuckdrill pipe. If this occurs, you must con-duct the required BOP test on the firsttrip out of the hole. You must recordthe reason for postponing any test inthe driller’s report.

(f) Visual inspections. You must vis-ually inspect your surface and subseaBOP systems and marine riser at leastonce each day if weather and sea condi-tions permit. You may use televisioncameras to inspect subsea equipment.The District Supervisor may approvealternate methods and frequencies toinspect a marine riser. Casing risers onfixed structures and jackup rigs are notsubject to the daily underwater inspec-tions.

(g) BOP maintenance. You must main-tain your BOP system to ensure thatthe equipment functions properly.

(h) BOP test records. You must recordthe time, date, and results of all pres-sure tests, actuations, and inspectionsof the BOP system, system compo-nents, and marine riser in the driller’sreport. In addition, you must:

(1) Record BOP test pressures onpressure charts;

(2) Have your onsite representativecertify (sign and date) BOP test chartsand reports as correct;


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(3) Document the sequential order ofBOP and auxiliary equipment testingand the pressure and duration of eachtest. You may reference a BOP testplan if it is available at the facility;

(4) Identify the control station or podused during the test;

(5) Identify any problems or irreg-ularities observed during BOP systemtesting and record actions taken toremedy the problems or irregularities;

(6) Retain all records, including pres-sure charts, driller’s report, and ref-erenced documents, pertaining to BOPtests, actuations, and inspections atthe facility for the duration of drilling;and

(7) After drilling is completed, youmust retain all the records listed inparagraph (h)(6) of this section for a pe-riod of 2 years at the facility, at thelessee’s field office nearest the OuterContinental Shelf (OCS) facility, or atanother location conveniently avail-able to the District Supervisor.

(i) Alternate methods. The District Su-pervisor may require, or approve, morefrequent testing, as well as differenttest pressures and inspection methods,or other practices.

[63 FR 29607, June 1, 1998]

§ 250.408 Well-control drills.(a) Well-control drills shall be con-

ducted for each drilling crew in accord-ance with the following requirements:

(1) Drills shall be designed to ac-quaint each crew member with eachmember’s function at the particulartest station so each member can per-form their functions promptly and effi-ciently.

(2) A well-control drill plan, applica-ble to the particular site, shall be pre-pared for each crew member outliningthe assignments each member is to ful-fill during the drill and establishing aprescribed time for the completion ofeach portion of the drill. A copy of thecomplete well-control drill plan shallbe posted on the rig floor and/or bul-letin board.

(3) The drill shall be carried out dur-ing periods of activity selected to mini-mize the risk of sticking the drill pipeor otherwise endangering the oper-ation. In each of these drills, the reac-tion time of participants shall be meas-ured up to the point when the des-

ignated person is prepared to activatethe closing sequence of the BOP sys-tem. The total time for the crew tocomplete its entire drill assignmentshall also be measured. This operationshall be recorded on the driller’s reportas ‘‘Well-Control Drill.’’ All drills shallbe initiated by the toolpusher throughthe raising of the float on the pit-leveldevice, activating the mud-return indi-cator, or its equivalent. This operationshall be performed at least once eachweek (well conditions permitting) witheach crew. The drills shall be timed sothey will cover a range of different op-erations which include on-bottom drill-ing and tripping. A diverter drill shallbe developed and conducted in a simi-lar manner for shallow operations.

(4) On-bottom drilling. A drill con-ducted while on bottom shall includethe following as practicable:

(i) Detect kick and sound alarm;(ii) Position kelly and tool joints so

connections are accessible from floor,but tool joints are clear of sealing ele-ments in BOP systems, stop pumps,check for flow, close in the well;

(iii) Record time;(iv) Record drill-pipe pressure and

casing pressure;(v) Measure pit gain and mark new

level;(vi) Estimate volume of additional

mud in pits;(vii) Weight sample of mud from suc-

tion pit;(viii) Check all valves on choke

manifold and BOP system for correctposition (open or closed);

(ix) Check BOP system componentsand choke manifold for leaks;

(x) Check flow line and choke ex-haust lines for flow;

(xi) Check accumulator pressure;(xii) Prepare to extinguish sources of

ignition;(xiii) Alert standby boat or prepare

safety capsule for launching;(xiv) Place crane operator on duty for

possible personnel evacuation;(xv) Prepare to lower escape ladders

and prepare other abandonment devicesfor possible use;

(xvi) Determine materials needed tocirculate out kick; and

(xvii) Time drill and enter drill re-port on driller’s report.


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30 CFR Ch. II (7–1–01 Edition)§ 250.409

(5) Tripping pipe. A drill conductedduring a trip shall include the fol-lowing as practicable:

(i) Detect kick and sound alarm;(ii) Install safety valve, close safety

valve;(iii) Position pipe, prepare to close

annular preventer;(iv) Install inside preventer, open

safety valve;(v) Record time;(vi) Record casing pressure;(vii) Check all valves on choke mani-

fold and BOP system for correct posi-tion (open or closed);

(viii) Check for leaks on BOP systemcomponent and choke manifold;

(ix) Check flow line and choke ex-haust lines for flow;

(x) Check accumulator pressure;(xi) Prepare to extinguish sources of

ignition;(xii) Alert standby boat or prepare

safety capsule for launching;(xiii) Place crane operator on duty

for possible personnel evacuation;(xiv) Prepare to lower escape ladders

and prepare other abandonment devicesfor possible use;

(xv) Prepare to strip back to bottom;and

(xvi) Time drill and enter drill reporton driller’s report.

(b) A well-control drill may be re-quired by a Minerals ManagementService (MMS) authorized representa-tive after consulting with the lessee’ssenior representative present.

§ 250.409 Diverter systems.(a) When drilling a conductor or sur-

face hole, all drilling units shall beequipped with a diverter system con-sisting of a diverter sealing element,diverter lines, and control systems un-less otherwise approved by the DistrictSupervisor for floating drilling oper-ations. The diverter system shall be de-signed, installed, and maintained so asto divert gases, water, mud, and othermaterials away from the facilities andpersonnel.

(b) No later than May 31, 1990, di-verter systems shall be in compliancewith the requirements of this section.The requirements applicable todiverters which were in effect April 1,1988 shall remain in effect until May 31,1990.

(c) The diverter system shall beequipped with remote-controlled valvesin the flow and vent lines that can beoperated from at least one remote-con-trol station in addition to the one onthe drilling floor. Any valve used in adiverter system shall be full-opening.No manual or butterfly valve shall beinstalled in any part of the divertersystem. There shall be a minimumnumber of turns in the vent line(s)downstream of the spool outlet flangeand the radius of curvature of turnsshall be as large as practicable. Allright-angle and sharp turns shall betargeted. Flexible hose may be used fordiverter lines instead of rigid pipe ifthe flexible hose has integral end cou-plings. The entire diverter system shallbe firmly anchored and supported toprevent whipping and vibration. All di-verter control instruments and linesshall be protected from physical dam-age from thrown and falling objects.

(d) For drilling operations conductedwith a surface wellhead configuration,the following shall apply:

(1) If the diverter system utilizesonly one spool outlet, branch linesshall be installed to provide downwinddiversion capability; and

(2) No spool outlet or diverter line in-ternal diameter shall be less than 10inches, except that dual spool outletsare acceptable provided that each out-let has a minimum internal diameterof 8 inches and that both outlets arepiped to overboard lines and that eachline downstream of the changeover nip-ple at the spool has a minimum inter-nal diameter of 10 inches.

(e) For drilling operations conductedwhere a floating or semisubmersibletype of drilling vessel is used and drill-ing fluids are circulated to the drillingvessel, the following shall apply:

(1) If the diverter system utilizesonly one spool outlet, branch linesshall be installed to provide downwinddiversion capability;

(2) No spool outlet or diverter line in-ternal diameter shall be less than 12inches; and

(3) Dynamically positioned drill shipsmay be equipped with a single vent lineprovided appropriate vessel heading ismaintained to allow for downwind di-version.


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(f) The diverter sealing element anddiverter valves shall be pressure testedto a minimum of 200 psi when nippledup on conductor casing with a surfacewellhead configuration. No more than 7days shall elapse between subsequentsimilar pressure tests. For surface andsubsea wellhead configurations, the di-verter sealing element, diverter valves,and diverter-control systems, includingthe remote control system, shall be ac-tuation-tested and the vent lines flowtested when first installed. Subsequentactuation tests shall be conducted notless than once every 24-hour periodthereafter alternating between controlstations. All pressure test, flow test,and actuation results shall be recordedin the driller’s report.

(g) Diverter systems and componentsfor use in subfreezing conditions shallbe suitable for use under these condi-tions.

§ 250.410 Mud program.

(a) General requirements. The quan-tities, characteristics, use, and testingof drilling mud and the related drillingprocedures shall be designed and imple-mented to prevent the loss of well con-trol.

(b) Mud control. (1) Before startingout of the hole with drill pipe, the mudshall be properly conditioned by cir-culation with the drill pipe just off bot-tom to the extent that a volume ofdrilling mud equal to the annular vol-ume is displaced. This procedure maybe omitted if proper documentation inthe driller’s report shows the following:

(i) There is no indication of influx offormation fluids prior to starting topull the drill pipe from the hole.

(ii) The weight of the returning mudis essentially the same as the weight ofthe mud entering the hole. In the eventthat the returning mud is lighter thanthe entering mud by a weight differen-tial equal to or greater than 0.2 poundsper gallon (1.5 pounds per cubic foot),the mud shall be circulated until a vol-ume of drilling mud equal to the annu-lar volume is displaced, and the mudproperties measured to assure thatthere has been no influx of gas or liq-uid.

(iii) Other mud properties recordedon the daily drilling log are within the

limits established by the approved mudprogram.

(2) When mud in the hole is cir-culated, the driller’s report shall be sonoted.

(3) When coming out of the hole withdrill pipe, the annulus shall be filledwith mud before the change in mudlevel decreases the hydrostatic pres-sure by 75 psi, or every five stands ofdrill pipe, whichever gives a lower de-crease in hydrostatic pressure. Thenumber of stands of drill pipe and drillcollars that may be pulled prior to fill-ing the hole and the equivalent mudvolume shall be calculated and postednear the driller’s station. A mechan-ical, volumetric, or electronic devicefor measuring the amount of mud re-quired to fill the hole shall be utilized.

(4) Drill pipe and downhole tool run-ning and pulling speeds shall be at con-trolled rates so as not to induce an in-flux of formation fluids from the ef-fects of swabbing nor cause a loss ofdrilling fluid and corresponding hydro-static pressure decrease from the ef-fects of surging.

(5) When there is an indication ofswabbing or influx of formation fluids,the safety devices and measures nec-essary to control the well shall be em-ployed. The mud shall be circulatedand conditioned, on or near bottom,unless well or mud conditions preventrunning the drill pipe back to the bot-tom.

(6) For each casing string, the max-imum pressure to be contained underthe BOP shall be posted near thedriller’s station.

(7) In areas where permafrost and/orhydrate zones may be present or areknown to be present, drilling fluid tem-peratures shall be controlled or othermeasures taken to drill safely throughthose zones.

(8) An operable mud-gas separatorand operable degasser shall be installedin the mud system prior to commence-ment of drilling operations and shall bemaintained for use throughout thedrilling of the well.

(9) The mud in the hole shall be cir-culated or reverse-circulated prior topulling the drill-stem test tools fromthe hole. If circulating out test fluid isnot feasible, test fluids may be bull-headed out of the drill-stem test string


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30 CFR Ch. II (7–1–01 Edition)§ 250.410

and tools with an appropriate kill fluidprior to pulling the test tools.

(c) Mud-testing and monitoring equip-ment. (1) Mud-testing equipment shallbe maintained on the drilling rig at alltimes, and mud tests shall be per-formed once each tour, or more fre-quently, as conditions warrant. Suchtests shall be conducted in accordancewith industry-accepted practices andshall include mud density, viscosity,and gel strength, hydrogen-ion con-centration (pH), filtration, and othertests as may be deemed necessary bythe District Supervisor in the interestsof monitoring and maintaining mudquality for safe operations, preventionof downhole equipment problems, andfor kick detection. The results of thesetests shall be recorded in the driller’sreport.

(2) The following mud-system moni-toring equipment shall be installedwith derrick floor indicators and usedwhen mud returns are established andthroughout subsequent drilling oper-ations:

(i) Recording mud-pit level indicatorto determine mud-pit volume gains andlosses. This indicator shall includeboth a visual and an audible warningdevice.

(ii) Mud-volume measuring device toaccurately determine mud volumes re-quired to fill the hole on trips.

(iii) Mud-return indicator deviceswhich indicate the relationship be-tween mud-return flow rate and pumpdischarge rate. This indicator shall in-clude both a visual and an audiblewarning device.

(iv) Gas-detecting equipment to mon-itor the drilling mud returns with indi-cators located in the mud-logging com-partment or on the rig floor. If the in-dicators are only in the mud-loggingcompartment, there shall be a means ofimmediate communication with the rigfloor, and the gas-detecting equipmentshall be continually manned. If the in-dicators are on the rig floor only, anaudible alarm shall be installed.

(d) Mud quantities. (1) Quantities ofmud and mud materials at the drill siteshall be utilized, maintained, and re-plenished as necessary to ensure wellcontrol. Those quantities shall bebased on known or anticipated drillingconditions to be encountered, rig stor-

age capacity, weather conditions, andestimated time for delivery.

(2) Daily inventories of mud and mudmaterials including weight materialsand additives at the drill site shall berecorded and those records maintainedat the well site.

(3) Drilling operations shall be sus-pended in the absence of sufficientquantities of mud and mud materialsto maintain well control.

(e) Safety precautions in mud-handlingareas. Mud-handling areas which areclassified as per API RP 500 or API RP505 where dangerous concentrations ofcombustible gas may accumulate shallbe equipped with ventilation systemsand gas monitors as described below nolater than May 31, 1989. Regulatory re-quirements in effect on April 1, 1988 areapplicable until May 31, 1989.

(1) Be ventilated with high-capacitymechanical ventilation systems capa-ble of replacing the air once every 5minutes or 1.0 cubic feet of air-volumeflow per minute per square foot of area,whichever is greater, unless such ven-tilation is provided by natural means.If not continuously activated, mechan-ical ventilation systems shall be acti-vated on signal from gas detectors thatare operational at all times indicatingthe presence of 1 percent or more of gasby volume.

(2) Be maintained at a negative pres-sure relative to an adjacent area if me-chanical ventilation is installed tomeet the requirements in paragraph(e)(1) of this section and dischargesmay be hazardous. The negative pres-sure areas shall be protected with atleast one of the following: (i) A pres-sure-sensitive alarm, (ii) open-dooralarms on each access to the area, (iii)automatic door-closing devices, (iv) airlocks, or (v) other devices as approvedby the District Supervisor.

(3) Be fitted with gas detectors andalarms except in open areas where ade-quate ventilation is provided by nat-ural means.

(4) Be equipped with either explosion-proof or pressurized electrical equip-ment to prevent the ignition of explo-sive gases. Where air is used for pres-suring, the air intake shall be locatedoutside of, and as far as practicablefrom, hazardous areas.


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(5) Mechanical ventilation systemsshall be fitted with alarms which areactivated upon a failure of the system.

(6) Gas detection systems shall betested for operation and recalibrated ata frequency such that no more than 90days shall elapse between tests.

[53 FR 10690, Apr. 1, 1988, as amended at 55FR 47752, Nov. 15, 1990. Redesignated at 63 FR29479, May 29, 1998, as amended at 65 FR40052, June 29, 2000]

§ 250.411 Securing of wells.A downhole safety device such as a

cement plug, bridge plug, or packershall be timely installed when drillingoperations are interrupted by eventssuch as those which force evacuation ofthe drilling crew, prevent station keep-ing, or require repairs to major drillingor well-control equipment. In floatingdrilling operations, the use of blind-shear rams or pipe rams and an insideBOP may be approved by the DistrictSupervisor in lieu of the above require-ments if supported by evidence of spe-cial circumstances and/or the lack ofsufficient time.

§ 250.412 Field drilling rules.When geological and engineering in-

formation available in a field enables aDistrict Supervisor to determine spe-cific operating requirements appro-priate to wells to be drilled in the field,field drilling rules may be establishedon the initiative of the District Super-visor, or in response to a request froma lessee. Such rules may modify the re-quirements of this subpart. After fielddrilling rules have been established, de-velopment wells to which such rulesapply shall be drilled in accordancewith such rules and other requirementsof this subpart. Field drilling rulesmay be amended or cancelled for causeat any time upon the initiative of theDistrict Supervisor or upon the ap-proval of a request by a lessee.

§ 250.413 Supervision, surveillance,and training.

(a) The lessee shall provide onsite su-pervision of drilling operations on a 24-hour per day basis.

(b) From the time drilling operationsare initiated and until the well is com-pleted or abandoned, a member of thedrilling crew or the toolpusher shall

maintain rig-floor surveillance con-tinuously, unless the well is securedwith BOP’s, bridge plugs, packers, orcement plugs.

(c) Lessee and drilling contractorpersonnel must be trained and qualifiedaccording to Subpart O of this part.Records of specific training which les-see and drilling contractor personnelhave successfully completed, the datesof completion, and the names and datesof the courses shall be maintained atthe drill site.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63FR 29479, May 29, 1998; 64 FR 9065, Feb. 24,1999]

§ 250.414 Applications for permit todrill.

(a) Prior to commencing the drillingof a well under an approved Explo-ration Plan, Development and Produc-tion Plan, or Development OperationsCoordination Document, the lesseeshall file a Form MMS–123, APD, withthe District Supervisor for approval.Prior to commencing operations, writ-ten approval from the District Super-visor must be received by the lessee un-less oral approval has been given pur-suant to § 250.140.

(b) The APD’s for wells to be drilledfrom mobile drilling units shall includethe following:

(1) An identification of the maximumenvironmental and operational condi-tions the rig is designed to withstand.

(2) Applicable current documentationof operational limitations imposed bythe American Bureau of Shipping clas-sification or other appropriate classi-fication society and either a U.S. CoastGuard Certificate of Inspection or aU.S. Coast Guard Letter of Compliance.

(3) For frontier areas, the design andoperating limitations beyond whichsuspension, curtailment, or modifica-tion of drilling or rig operations are re-quired (e.g., vessel motion, offset, riserangle, anchor tensions, wind speed,wave height, currents, icing or ice-loading, settling, tilt or lateral move-ment, resupply capability) and the con-tingency plans which identify actionsto be taken prior to exceeding the de-sign or operating limitations of the rig.

(4) A program which provides forsafety in drilling operations where afloating or semisubmersible type of


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drilling vessel is used and formationcompetency at the structural and/orconductor casing setting depth(s) is(are) not adequate to permit circula-tion of drilling fluids to the vesselwhile drilling the conductor and/or sur-face hole. This program shall includeall known pertinent information in-cluding seismic and geologic data,water depth, drilling-fluid hydrostaticpressure, a schematic diagram indi-cating the equipment to be installedfrom the rotary table to the proposedconductor and/or surface casing seat(s),and the contingency plan for movingoff location.

(c) The APD’s shall include rated ca-pacities of the proposed drilling unitand of major drilling equipment.

(d) In those areas which are subjectto subfreezing conditions, the lesseeshall furnish evidence that the drillingequipment, BOP system and compo-nents, drilling safety systems, divertersystems, and other associated equip-ment and materials are suitable fordrilling operations under subfreezingconditions.

(e) After a drilling unit has been ap-proved for use in an MMS District, theinformation listed in paragraphs (b) (1),(2), and (3), (c), and (d) of this sectionneed not be resubmitted unless re-quired by the District Supervisor orthere are changes in equipment that af-fect the rated capacity of the unit.

(f) An APD shall include the fol-lowing in addition to a fully completedForm MMS–123:

(1) A plat, drawn to a scale of 2,000feet to the inch, showing the surfaceand subsurface location of the well tobe drilled and of all the wells pre-viously drilled in the vicinity fromwhich information is available. Loca-tions shall be indicated in feet from theblock line.

(2) The design criteria considered forthe well and for well control, includingthe following:

(i) Pore pressures.(ii) Formation fracture gradients.(iii) Potential lost circulation zones.(iv) Mud weights.(v) Casing setting depths.(vi) Anticipated surface pressures

(which for purposes of this section aredefined as the pressure which can rea-sonably be expected to be exerted upon

a casing string and its related wellheadequipment). In the calculation of ananticipated surface pressure, the lesseeshall take into account the drilling,completion, and producing conditions.The lessee shall consider mud densitiesto be used below various casing strings,fracture gradients of the exposed for-mations, casing setting depths, totalwell depth, formation fluid type, andother pertinent conditions. Consider-ations for calculating anticipated sur-face pressure may vary for each seg-ment of the well. The lessee shall in-clude as a part of the statement of an-ticipated surface pressures the calcula-tions used to determine these pressuresduring the drilling phase and the com-pletion phase, including the antici-pated surface pressure used for produc-tion string design.

(vii) If a shallow hazards site surveyis conducted, the lessee shall submitwith or prior to the submittal of theAPD, two copies of a summary reportdescribing the geological and manmadeconditions present. The lessee shallalso submit two copies of the site mapsand data records identified in the sur-vey strategy.

(viii) Permafrost zones, if applicable.(3) A BOP equipment program includ-

ing the following:(i) The pressure rating of BOP equip-

ment.(ii) A well-control procedure for use

of the annular preventer for those wellswhere the anticipated surface pressureexceeds the rated working pressure ofthe annular preventer.

(iii) A description of subsea BOP ac-cumulator system or other type ofclosing system proposed for use.

(iv) A schematic drawing of the di-verter system to be used (plan and ele-vation views) showing spool outlet in-ternal diameter(s); diverter-linelengths and diameters, burst strengths,and radius of curvature at each turn;valve type, size, working pressure rat-ing, and location; the control instru-mentation logic; and the operating pro-cedure to be used by lessee or con-tractor personnel.

(v) A schematic drawing of the BOPstack showing the inside diameter ofthe BOP stack, and the number of an-nular, pipe ram, variable-bore pipe


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ram, blind ram, and blind-shear rampreventers.

(4) A casing program including thefollowing:

(i) Casing size, weight, grade, type ofconnection, and setting depth;

(ii) Casing design safety factors fortension, collapse, and burst with theassumptions made to arrive at thesevalues; and

(iii) In areas containing permafrost,casing programs that incorporate set-ting depths for conductor and surfacecasing based on the anticipated depthof the permafrost at the proposed welllocation and which utilize the currentstate-of-the-art methods to safely drilland set casing. The casing programshall provide protection from thaw sub-sidence and freezeback effect, properanchorage, and well control.

(5) The drilling prognosis includingthe following:

(i) Projected plans for coring at spec-ified depths;

(ii) Projected plans for logging;(iii) Estimated depths to the top of

significant marker formations; and(iv) Estimated depths at which en-

counters with significant porous andpermeable zones containing freshwater, oil, gas, or abnormally pres-sured water are expected.

(6) A cementing program includingtype and amount of cement in cubicfeet to be used for each casing string.

(7) A mud program including theminimum quantities of mud and mudmaterials, including weight materials,to be kept at the site.

(8) A directional survey program fordirectionally drilled wells.

(9) A plot of the estimated pore pres-sures and formation fracture gradientsand the proposed mud weights and cas-ing setting depths on the same sheet.

(10) A H2S Contingency Plan, if appli-cable, and not submitted previously.

(11) Such other information as maybe required by the District Supervisor.

(g) Public information copies of theAPD shall be submitted in accordancewith § 250.190 of this part.

[53 FR 10690, Apr. 1, 1988, as amended at 58FR 49928, Sept. 24, 1993. Redesignated andamended at 63 FR 29479, 29485, May 29, 1998; 64FR 72794, Dec. 28, 1999]

§ 250.415 Sundry notices and reportson wells.

(a) Notices of the lessee’s intentionto change plans, make changes inmajor drilling equipment, deepen orplug back a well, or engage in similaractivities and subsequent reports per-taining to such operations shall be sub-mitted to the District Supervisor onForm MMS–124, Sundry Notices andReports on Wells. Prior to commencingoperations, written approval must bereceived from the District Supervisorunless oral approval is obtained.

(b) The Form MMS–124 submittedshall contain a detailed statement ofthe proposed work that will materiallychange from the approved work de-scribed in the APD. Information sub-mitted shall include the present statusof the well, including the productionstring or last string of casing, the welldepth, the present production zonesand productive capability, and allother information specified on FormMMS–124. Within 30 days after comple-tion of the work, a subsequent detailedreport of all the work done and the re-sults obtained shall be submitted.

(c) A Form MMS–124 with a plat, cer-tified by a registered land surveyor,shall be filed as soon as the well’s finalsurveyed surface location, water depth,and the rotary kelly bushing elevationhave been determined.

(d) Public information copies of Sun-dry Notices and Reports on Wells shallbe submitted in accordance with§ 250.190 of this part.


§ 250.416 Well records.(a) Complete and accurate records for

each well and of all well operationsshall be retained for a period of 2 yearsat the lessee’s field office nearest theOCS facility or at another locationconveniently available to the DistrictSupervisor. The records shall contain adescription of any significant malfunc-tion or problem; all the formationspenetrated; the content and characterof oil, gas, and other mineral depositsand water in each formation; the kind,weight, size, grade, and setting depthof casing; all well logs and surveys run


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in the wellbore; and all other informa-tion required by the District Super-visor in the interests of resource eval-uation, waste prevention, conservationof natural resources, protection of cor-relative rights, safety, and environ-ment.

(b) When drilling operations are sus-pended, or temporarily prohibitedunder the provisions of § 250.170 of thispart, the lessee shall, within 30 daysafter termination of the suspension ortemporary prohibition or within 30days after the completion of any ac-tivities related to the suspension orprohibition, transmit to the DistrictSupervisor duplicate copies of therecords of all activities related to andconducted during the suspension ortemporary prohibition on, or attachedto, Form MMS–125, Well Summary Re-port, or Form MMS–124, as appropriate.

(c) Upon request by the Regional orDistrict Supervisor, the lessee shallfurnish the following:

(1) Copies of the records of any of thewell operations specified in paragraph(a) of this section;

(2) Paleontological reports identi-fying microscopic fossils by depth and/or washed samples of drill cuttings nor-mally maintained by the lessee for pa-leontological determinations;

(3) Copies of the daily driller’s reportat a frequency as determined by theDistrict Supervisor. Items to be re-ported include spud dates, casing set-ting depths, cement quantities, casingcharacteristics, pressure integritytests, mud weights, kicks, lost returns,and any unusual activities; and

(4) Legible, exact copies of servicecompany reports on cementing, perfo-rating, acidizing, analyses of cores,testing, or other similar services.

(d) As soon as available, the lesseeshall transmit copies (field or finalprints of individual runs) of logs orcharts of electrical, radioactive, sonic,and other well-logging operations, di-rectional-well surveys, and analyses ofcores. Composite logs of multiple runsand directional-well surveys shall betransmitted to the District Supervisorin duplicate as soon as available butnot later than 30 days after completionof each well.

(e) If the drilling unit moves from thewellbore prior to completing the well,

the lessee shall submit to the DistrictSupervisor copies of the well recordswith completed Form MMS–124, within30 days after moving from the wellbore.

(f) If the Regional or District Super-visor determines that circumstanceswarrant, the lessee shall submit anyother reports and records of operations,including paleontological interpreta-tions based upon identification of mi-croscopic fossils, in the manner andform prescribed by the Regional or Dis-trict Supervisor.

(g) Records relating to the drilling ofa well shall be retained for a period of90 days after drilling operations arecompleted. Records relating to thecompletion of a well or of anyworkover activity which materially al-ters the completion configuration ormaterially affects or alters a hydro-carbon-bearing zone shall be kept untilthe well is permanently plugged andabandoned.


§ 250.417 Hydrogen sulfide.

(a) What precautions must I take whenoperating in an H2S area? You must:

(1) Take all necessary and feasibleprecautions and measures to protectpersonnel from the toxic effects of H2Sand to mitigate damage to propertyand the environment caused by H2S.You must follow the requirements ofthis section when conducting drilling,well-completion/well-workover, andproduction operations in zones withH2S present and when conducting oper-ations in zones where the presence ofH2S is unknown. You do not need tofollow these requirements when oper-ating in zones where the absence of H2Shas been confirmed; and

(2) Follow your approved contingencyplan.

(b) Definitions. Terms used in thissection have the following meanings:

Facility means a vessel, a structure,or an artificial island used for drilling,well-completion, well-workover, and/orproduction operations.

H2S absent means:


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(1) Drilling, logging, coring, testing,or producing operations have con-firmed the absence of H2S in concentra-tions that could potentially result inatmospheric concentrations of 20 ppmor more of H2S; or

(2) Drilling in the surrounding areasand correlation of geological and seis-mic data with equivalent stratigraphicunits have confirmed an absence of H2Sthroughout the area to be drilled.

H2S present means that drilling, log-ging, coring, testing, or producing op-erations have confirmed the presenceof H2S in concentrations and volumesthat could potentially result in atmos-pheric concentrations of 20 ppm ormore of H2S.

H2S unknown means the designationof a zone or geologic formation whereneither the presence nor absence of H2Shas been confirmed.

Well-control fluid means drilling mudand completion or workover fluid asappropriate to the particular operationbeing conducted.

(c) Classifying an area for the presenceof H2S. You must:

(1) Request and obtain an approvedclassification for the area from the Re-gional Supervisor before you begin op-erations. Classifications are ‘‘H2S ab-sent,’’ H2S present,’’ or ‘‘H2S un-known’’;

(2) Submit your request with yourapplication for permit to drill;

(3) Support your request with avail-able information such as geologic andgeophysical data and correlations, welllogs, formation tests, cores and anal-ysis of formation fluids; and

(4) Submit a request for reclassifica-tion of a zone when additional data in-dicate a different classification is need-ed.

(d) What do I do if conditions change?If you encounter H2S that could poten-tially result in atmospheric concentra-tions of 20 ppm or more in areas notpreviously classified as having H2Spresent, you must immediately notifyMMS and begin to follow requirementsfor areas with H2S present.

(e) What are the requirements for con-ducting simultaneous operations? Whenconducting any combination of drill-ing, well-completion, well-workover,and production operations simulta-neously, you must follow the require-

ments in the section applicable to eachindividual operation.

(f) Requirements for submitting an H2SContingency Plan. Before you begin op-erations, you must submit an H2S Con-tingency Plan to the District Super-visor for approval. Do not begin oper-ations before the District Supervisorapproves your plan. You must keep acopy of the approved plan in the field,and you must follow the plan at alltimes. Your plan must include:

(1) Safety procedures and rules thatyou will follow concerning equipment,drills, and smoking;

(2) Training you provide for employ-ees, contractors, and visitors;

(3) Job position and title of the per-son responsible for the overall safety ofpersonnel;

(4) Other key positions, how these po-sitions fit into your organization, andwhat the functions, duties, and respon-sibilities of those job positions are;

(5) Actions that you will take whenthe concentration of H2S in the atmos-phere reaches 20 ppm, who will be re-sponsible for those actions, and a de-scription of the audible and visualalarms to be activated;

(6) Briefing areas where personnelwill assemble during an H2S alert. Youmust have at least two briefing areason each facility and use the briefingarea that is upwind of the H2S sourceat any given time;

(7) Criteria you will use to decidewhen to evacuate the facility and pro-cedures you will use to safely evacuateall personnel from the facility by ves-sel, capsule, or lifeboat. If you use heli-copters during H2S alerts, describe thetypes of H2S emergencies during whichyou consider the risk of helicopter ac-tivity to be acceptable and the pre-cautions you will take during theflights;

(8) Procedures you will use to safelyposition all vessels attendant to the fa-cility. Indicate where you will locatethe vessels with respect to wind direc-tion. Include the distance from the fa-cility and what procedures you will useto safely relocate the vessels in anemergency;

(9) How you will provide protective-breathing equipment for all personnel,including contractors and visitors;


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(10) The agencies and facilities youwill notify in case of a release of H2S(that constitutes an emergency), howyou will notify them, and their tele-phone numbers. Include all facilitiesthat might be exposed to atmosphericconcentrations of 20 ppm or more ofH2S;

(11) The medical personnel and facili-ties you will use if needed, their ad-dresses, and telephone numbers;

(12) H2S detector locations in produc-tion facilities producing gas containing20 ppm or more of H2S. Include an ‘‘H2SDetector Location Drawing’’ showing:

(i) All vessels, flare outlets,wellheads, and other equipment han-dling production containing H2S;

(ii) Approximate maximum con-centration of H2S in the gas stream;and

(iii) Location of all H2S sensors in-cluded in your contingency plan;

(13) Operational conditions when youexpect to flare gas containing H2S in-cluding the estimated maximum gasflow rate, H2S concentration, and dura-tion of flaring;

(14) Your assessment of the risks topersonnel during flaring and what pre-cautionary measures you will take;

(15) Primary and alternate methodsto ignite the flare and procedures forsustaining ignition and monitoring thestatus of the flare (i.e., ignited or ex-tinguished);

(16) Procedures to shut off the gas tothe flare in the event the flare is extin-guished;

(17) Portable or fixed sulphur dioxide(SO2)-detection system(s) you will useto determine SO2 concentration and ex-posure hazard when H2S is burned;

(18) Increased monitoring and warn-ing procedures you will take when theSO2 concentration in the atmospherereaches 2 ppm;

(19) Personnel protection measures orevacuation procedures you will initiatewhen the SO2 concentration in the at-mosphere reaches 5 ppm;

(20) Engineering controls to protectpersonnel from SO2; and

(21) Any special equipment, proce-dures, or precautions you will use ifyou conduct any combination of drill-ing, well-completion, well-workover,and production operations simulta-neously.

(g) Training program.(1) When and how often do employees

need to be trained? All operators andcontract personnel must complete anH2S training program to meet the re-quirements of this section:

(i) Before beginning work at the fa-cility; and

(ii) Each year, within 1 year aftercompletion of the previous class.

(2) What training documentation do Ineed? For each individual working onthe platform, either:

(i) You must have documentation ofthis training at the facility where theindividual is employed; or

(ii) The employee must carry a train-ing completion card.

(3) What training do I need to give tovisitors and employees previously trainedon another facility?

(i) Trained employees or contractorstransferred from another facility mustattend a supplemental briefing on yourH2S equipment and procedures beforebeginning duty at your facility;

(ii) Visitors who will remain on yourfacility more than 24 hours must re-ceive the training required for employ-ees by paragraph (g)(4) of this section;and

(iii) Visitors who will depart beforespending 24 hours on the facility areexempt from the training required foremployees, but they must, upon ar-rival, complete a briefing that in-cludes:

(A) Information on the location anduse of an assigned respirator; practicein donning and adjusting the assignedrespirator; information on the safebriefing areas, alarm system, and haz-ards of H2S and SO2; and

(B) Instructions on their responsibil-ities in the event of an H2S release.

(4) What training must I provide to allother employees? You must train all in-dividuals on your facility on the:

(i) Hazards of H2S and of SO2 and theprovisions for personnel safety con-tained in the H2S Contingency Plan;

(ii) Proper use of safety equipmentwhich the employee may be required touse;

(iii) Location of protective breathingequipment, H2S detectors and alarms,ventilation equipment, briefing areas,


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warning systems, evacuation proce-dures, and the direction of prevailingwinds;

(iv) Restrictions and correctivemeasures concerning beards, spec-tacles, and contact lenses in conform-ance with ANSI Z88.2;

(v) Basic first-aid procedures applica-ble to victims of H2S exposure. Duringall drills and training sessions, youmust address procedures for rescue andfirst aid for H2S victims;

(vi) Location of:(A) The first-aid kit on the facility;(B) Resuscitators; and(C) Litter or other device on the fa-

cility.(vii) Meaning of all warning signals.(5) Do I need to post safety information?

You must prominently post safety in-formation on the facility and on ves-sels serving the facility (i.e,, basicfirst-aid, escape routes, instructionsfor use of life boats, etc.).

(h) Drills. (1) When and how often do Ineed to conduct drills on H2S safety dis-cussions on the facility? You must:

(i) Conduct a drill for each person atthe facility during normal duty hoursat least once every 7-day period. Thedrills must consist of a dry-run per-formance of personnel activities re-lated to assigned jobs.

(ii) At a safety meeting or othermeetings of all personnel, discuss drillperformance, new H2S considerationsat the facility, and other updated H2Sinformation at least monthly.

(2) What documentation do I need? Youmust keep records of attendance for:

(i) Drilling, well-completion, andwell-workover operations at the facil-ity until operations are completed; and

(ii) Production operations at the fa-cility or at the nearest field office for1 year.

(i) Visual and audible warning sys-tems—(1) How must I install wind direc-tion equipment? You must install wind-direction equipment in a location visi-ble at all times to individuals on or inthe immediate vicinity of the facility.

(2) When do I need to display oper-ational danger signs, display flags, or ac-tivate visual or audible alarms?

(i) You must display warning signs atall times on facilities with wells capa-ble of producing H2S and on facilities

that process gas containing H2S in con-centrations of 20 ppm or more.

(ii) In addition to the signs, you mustactivate audible alarms and displayflags or activate flashing red lightswhen atmospheric concentration of H2Sreaches 20 ppm.

(3) What are the requirements for signs?Each sign must be a high-visibility yel-low color with black lettering as fol-lows:

Letter height Wording

12 inches ............................... Danger.Poisonous Gas.Hydrogen Sulfide.

7 inches ................................. Do not approach if red flag isflying.

(Use appropriate wording atright).

Do not approach if red lightsare flashing.

(4) May I use existing signs? You mayuse existing signs containing the words‘‘Danger-Hydrogen Sulfide-H2S,’’ pro-vided the words ‘‘Poisonous Gas. DoNot Approach if Red Flag is Flying’’ or‘‘Red Lights are Flashing’’ in letteringof a minimum of 7 inches in height aredisplayed on a sign immediately adja-cent to the existing sign.

(5) What are the requirements for flash-ing lights or flags? You must activate asufficient number of lights or hoist asufficient number of flags to be visibleto vessels and aircraft. Each light mustbe of sufficient intensity to be seen byapproaching vessels or aircraft anytime it is activated (day or night).Each flag must be red, rectangular, aminimum width of 3 feet, and a min-imum height of 2 feet.

(6) What is an audible warning system?An audible warning system is a publicaddress system or siren, horn, or othersimilar warning device with a uniquesound used only for H2S.

(7) Are there any other requirements forvisual or audible warning devices? Yes,you must:

(i) Illuminate all signs and flags atnight and under conditions of poor visi-bility; and

(ii) Use warning devices that are suit-able for the electrical classification ofthe area.

(8) What actions must I take when thealarms are activated? When the warningdevices are activated, the designatedresponsible persons must inform per-sonnel of the level of danger and issue


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instructions on the initiation of appro-priate protective measures.

(j) H2S-detection and H2S monitoringequipment—(1) What are the require-ments for an H2S detection system? AnH2S detection system must:

(i) Be capable of sensing a minimumof 10 ppm of H2S in the atmosphere;and

(ii) Activate audible and visualalarms when the concentration of H2Sin the atmosphere reaches 20 ppm.

(2) Where must I have sensors for drill-ing, well-completion, and well-workoveroperations? You must locate sensors atthe:

(i) Bell nipple;(ii) Mud-return line receiver tank

(possum belly);(iii) Pipe-trip tank;(iv) Shale shaker;(v) Well-control fluid pit area;(vi) Driller’s station;(vii) Living quarters; and(viii) All other areas where H2S may

accumulate.(3) Do I need mud sensors? The Dis-

trict Supervisor may require mud sen-sors in the possum belly in cases wherethe ambient air sensors in the mud-re-turn system do not consistently detectthe presence of H2S.

(4) How often must I observe the sen-sors? During drilling, well-completionand well-workover operations, youmust continuously observe the H2S lev-els indicated by the monitors in thework areas during the following oper-ations:

(i) When you pull a wet string of drillpipe or workover string;

(ii) When circulating bottoms-upafter a drilling break;

(iii) During cementing operations;(iv) During logging operations; and(v) When circulating to condition

mud or other well-control fluid.(5) Where must I have sensors for pro-

duction operations? On a platform wheregas containing H2S of 20 ppm or greateris produced, processed, or otherwisehandled:

(i) You must have a sensor in rooms,buildings, deck areas, or low-layingdeck areas not otherwise covered byparagraph (j)(2) of this section, whereatmospheric concentrations of H2Scould reach 20 ppm or more. You musthave at least one sensor per 400 square

feet of deck area or fractional part of400 square feet;

(ii) You must have a sensor in build-ings where personnel have their livingquarters;

(iii) You must have a sensor within 10feet of each vessel, compressor, well-head, manifold, or pump, which couldrelease enough H2S to result in atmos-pheric concentrations of 20 ppm at adistance of 10 feet from the component;

(iv) You may use one sensor to detectH2S around multiple pieces of equip-ment, provided the sensor is located nomore than 10 feet from each piece, ex-cept that you need to use at least twosensors to monitor compressors exceed-ing 50 horsepower;

(v) You do not need to have sensorsnear wells that are shut in at the mas-ter valve and sealed closed;

(vi) When you determine where toplace sensors, you must consider:

(A) The location of system fittings,flanges, valves, and other devices sub-ject to leaks to the atmosphere; and

(B) Design factors, such as the typeof decking and the location of firewalls; and

(vii) The District Supervisor may re-quire additional sensors or other moni-toring capabilities, if warranted by sitespecific conditions.

(6) How must I functionally test the H2SDetectors?

(i) Personnel trained to calibrate theparticular H2S detector equipmentbeing used must test detectors by ex-posing them to a known concentrationin the range of 10 to 30 ppm of H2S.

(ii) If the results of any functionaltest are not within 2 ppm or 10 percent,whichever is greater, of the appliedconcentration, recalibrate the instru-ment.

(7) How often must I test my detectors?(i) When conducting drilling, drill

stem testing, well-completion, or well-workover operations in areas classifiedas H2S present or H2S unknown, test alldetectors at least once every 24 hours.When drilling, begin functional testingbefore the bit is 1,500 feet (vertically)above the potential H2S zone.

(ii) When conducting production op-erations, test all detectors at leastevery 14 days between tests.


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(iii) If equipment requires calibrationas a result of two consecutive func-tional tests, the District Supervisormay require that H2S-detection andH2S-monitoring equipment be function-ally tested and calibrated more fre-quently.

(8) What documentation must I keep?(i) You must maintain records of

testing and calibrations (in the drillingor production operations report, as ap-plicable) at the facility to show thepresent status and history of each de-vice, including dates and details con-cerning:

(A) Installation;(B) Removal;(C) Inspection;(D) Repairs;(E) Adjustments; and(F) Reinstallation.(ii) Records must be available for in-

spection by MMS personnel.(9) What are the requirements for near-

by vessels? If vessels are stationed over-night alongside facilities in areas ofH2S present or H2S unknown, you mustequip vessels with an H2S-detectionsystem that activates audible and vis-ual alarms when the concentration ofH2S in the atmosphere reaches 20 ppm.This requirement does not apply tovessels positioned upwind and at a safedistance from the facility in accord-ance with the positioning procedure de-scribed in the approved H2S Contin-gency Plan.

(10) What are the requirements for near-by facilities? The District Supervisormay require you to equip nearby facili-ties with portable or fixed H2S detec-tor(s) and to test and calibrate thosedetectors. To invoke this requirement,the District Supervisor will considerdispersion modeling results from a pos-sible release to determine if 20 ppm H2Sconcentration levels could be exceededat nearby facilities.

(11) What must I do to protect againstSO2 if I burn gas containing H2S? Youmust:

(i) Monitor the SO2 concentration inthe air with portable or strategicallyplaced fixed devices capable of detect-ing a minimum of 2 ppm of SO2;

(ii) Take readings at least hourly andat any time personnel detect SO2 odoror nasal irritation;

(iii) Implement the personnel protec-tive measures specified in the H2S Con-tingency Plan if the SO2 concentrationin the work area reaches 2 ppm; and

(iv) Calibrate devices every 3 monthsif you use fixed or portable electronicsensing devices to detect SO2.

(12) May I use alternative measures?You may follow alternative measuresinstead of those in paragraph (j)(11) ofthis section if you propose and the Re-gional Supervisor approves the alter-native measures.

(13) What are the requirements for pro-tective-breathing equipment? In an areaclassified as H2S present or H2S un-known, you must:

(i) Provide all personnel, includingcontractors and visitors on a facility,with immediate access to self-con-tained pressure-demand-type res-pirators with hoseline capability andbreathing time of at least 15 minutes.

(ii) Design, select, use, and maintainrespirators to conform to ANSI Z88.2,American National Standard for Res-piratory Protection.

(iii) Make available at least twovoice-transmission devices, which canbe used while wearing a respirator, foruse by designated personnel.

(iv) Make spectacle kits available asneeded.

(v) Store protective-breathing equip-ment in a location that is quickly andeasily accessible to all personnel.

(vi) Label all breathing-air bottles ascontaining breathing-quality air forhuman use.

(vii) Ensure that vessels attendant tofacilities carry appropriate protective-breathing equipment for each crewmember. The District Supervisor mayrequire additional protective-breathingequipment on certain vessels attendantto the facility.

(viii) During H2S alerts, limit heli-copter flights to and from facilities tothe conditions specified in the H2S Con-tingency Plan. During authorizedflights, the flight crew and passengersmust use pressure-demand-type res-pirators. You must train all membersof flight crews in the use of the par-ticular type(s) of respirator equipmentmade available.

(ix) As appropriate to the particularoperation(s), (production, drilling,


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well-completion or well-workover oper-ations, or any combination of them),provide a system of breathing-airmanifolds, hoses, and masks at the fa-cility and the briefing areas. You mustprovide a cascade air-bottle system forthe breathing-air manifolds to refill in-dividual protective-breathing appa-ratus bottles. The cascade air-bottlesystem may be recharged by a high-pressure compressor suitable for pro-viding breathing-quality air, providedthe compressor suction is located in anuncontaminated atmosphere.

(k) Personnel safety equipment—(1)What additional personnel-safety equip-ment do I need? You must ensure thatyour facility has:

(i) Portable H2S detectors capable ofdetecting a 10 ppm concentration ofH2S in the air available for use by allpersonnel;

(ii) Retrieval ropes with safety har-nesses to retrieve incapacitated per-sonnel from contaminated areas;

(iii) Chalkboards and/or note pads forcommunication purposes located onthe rig floor, shale-shaker area, the ce-ment-pump rooms, well-bay areas, pro-duction processing equipment area, gascompressor area, and pipeline-pumparea;

(iv) Bull horns and flashing lights;and

(v) At least three resuscitators onmanned facilities, and a number equalto the personnel on board, not to ex-ceed three, on normally unmanned fa-cilities, complete with face masks, ox-ygen bottles, and spare oxygen bottles.

(2) What are the requirements for ven-tilation equipment? You must:

(i) Use only explosion-proof ventila-tion devices;

(ii) Install ventilation devices inareas where H2S or SO2 may accumu-late; and

(iii) Provide movable ventilation de-vices in work areas. The movable ven-tilation devices must be multidirec-tional and capable of dispersing H2S orSO2 vapors away from working per-sonnel.

(3) What other personnel safety equip-ment do I need? You must have the fol-lowing equipment readily available oneach facility:

(i) A first-aid kit of appropriate sizeand content for the number of per-sonnel on the facility; and

(ii) At least one litter or an equiva-lent device.

(l) Do I need to notify MMS in theevent of an H2S release? You must notifyMMS without delay in the event of agas release which results in a 15-minute time weighted average atmos-pheric concentration of H2S of 20 ppmor more anywhere on the facility.

(m) Do I need to use special drilling,completion and workover fluids or proce-dures? When working in an area classi-fied as H2S present or H2S unknown:

(1) You may use either water- or oil-base muds in accordance with§ 250.300(b)(1).

(2) If you use water-base well-controlfluids, and if ambient air sensors detectH2S, you must immediately conduct ei-ther the Garrett-Gas-Train test or acomparable test for soluble sulfides toconfirm the presence of H2S.

(3) If the concentration detected byair sensors in over 20 ppm, personnelconducting the tests must don protec-tive-breathing equipment conformingto paragraph (j)(13) of this section.

(4) You must maintain on the facilitysufficient quantities of additives forthe control of H2S, well-control fluidpH, and corrosion equipment.

(i) Scavengers. You must have scav-engers for control of H2S available onthe facility. When H2S is detected, youmust add scavengers as needed. Youmust suspend drilling until the scav-enger is circulated throughout the sys-tem.

(ii) Control pH. You must add addi-tives for the control of pH to water-base well-control fluids in sufficientquantities to maintain pH of at least10.0.

(iii) Corrosion inhibitors. You mustadd additives to the well-control fluidsystem as needed for the control of cor-rosion.

(5) You must degas well-controlfluids containing H2S at the optimumlocation for the particular facility. Youmust collect the gases removed andburn them in a closed flare system con-forming to paragraph (q)(6) of this sec-tion.

(n) What must I do in the event of akick? In the event of a kick, you must


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use one of the following alternatives todispose of the well-influx fluids givingconsideration to personnel safety, pos-sible environmental damage, and pos-sible facility well-equipment damage:

(1) Contain the well-fluid influx byshutting in the well and pumping thefluids back into the formation.

(2) Control the kick by using appro-priate well-control techniques to pre-vent formation fracturing in an openhole within the pressure limits of thewell equipment (drill pipe, work string,casing, wellhead, BOP system, and re-lated equipment). The disposal of H2Sand other gases must be through pres-surized or atmospheric mud-separatorequipment depending on volume, pres-sure and concentration of H2S. Theequipment must be designed to recoverwell-control fluids and burn the gasesseparated from the well-control fluid.The well-control fluid must be treatedto neutralize H2S and restore andmaintain the proper quality.

(o) Well testing in a zone known to con-tain H2S. When testing a well in a zonewith H2S present, you must do all ofthe following:

(1) Before starting a well test, con-duct safety meetings for all personnelwho will be on the facility during thetest. At the meetings, emphasize theuse of protective-breathing equipment,first-aid procedures, and the Contin-gency Plan. Only competent personnelwho are trained and are knowledgeableof the hazardous effects of H2S must beengaged in these tests.

(2) Perform well testing with theminimum number of personnel in theimmediate vicinity of the rig floor andwith the appropriate test equipment tosafely and adequately perform the test.During the test, you must continuouslymonitor H2S levels.

(3) Not burn produced gases exceptthrough a flare which meets the re-quirements of paragraph (q)(6) of thissection. Before flaring gas containingH2S, you must activate SO2 monitoringequipment in accordance with para-graph (j)(11) of this section. If you de-tect SO2 in excess of 2 ppm, you mustimplement the personnel protectivemeasures in your H2S ContingencyPlan, required by paragraph (f)(13)(iv)of this section. You must also followthe requirements of § 250.1105. You

must pipe gases from stored test fluidsinto the flare outlet and burn them.

(4) Use downhole test tools and well-head equipment suitable for H2S serv-ice.

(5) Use tubulars suitable for H2S serv-ice. You must not use drill pipe for welltesting without the prior approval ofthe District Supervisor. Water cush-ions must be thoroughly inhibited inorder to prevent H2S attack on metals.You must flush the test string fluidtreated for this purpose after comple-tion of the test.

(6) Use surface test units and relatedequipment that is designed for H2Sservice.

(p) Metallurgical properties of equip-ment. When operating in a zone withH2S present, you must use equipmentthat is constructed of materials withmetallurgical properties that resist orprevent sulfide stress cracking (alsoknown as hydrogen embrittlement,stress corrosion cracking, or H2S em-brittlement), chloride-stress cracking,hydrogen-induced cracking, and otherfailure modes. You must do all of thefollowing:

(1) Use tubulars and other equipment,casing, tubing, drill pipe, couplings,flanges, and related equipment that isdesigned for H2S service.

(2) Use BOP system components,wellhead, pressure-control equipment,and related equipment exposed to H2S-bearing fluids that conform to NACEStandard MR0175–99.

(3) Use temporary downhole well-se-curity devices such as retrievablepackers and bridge plugs that are de-signed for H2S service.

(4) When producing in zones bearingH2S, use equipment constructed of ma-terials capable of resisting or pre-venting sulfide stress cracking.

(5) Keep the use of welding to a min-imum during the installation or modi-fication of a production facility. Weld-ing must be done in a manner that en-sures resistance to sulfide stress crack-ing.

(q) General requirements when oper-ating in an H2S zone—(1) Coring oper-ations. When you conduct coring oper-ations in H2S-bearing zones, all per-sonnel in the working area must wearprotective-breathing equipment atleast 10 stands in advance of retrieving


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the core barrel. Cores to be transportedmust be sealed and marked for thepresence of H2S.

(2) Logging operations. You must treatand condition well-control fluid in usefor logging operations to minimize theeffects of H2S on the logging equip-ment.

(3) Stripping operations. Personnelmust monitor displaced well-controlfluid returns and wear protective-breathing equipment in the workingarea when the atmospheric concentra-tion of H2S reaches 20 ppm or if thewell is under pressure.

(4) Gas-cut well-control fluid or wellkick from H2S-bearing zone. If you decideto circulate out a kick, personnel inthe working area during bottoms-upand extended-kill operations must wearprotective-breathing equipment.

(5) Drill- and workover-string designand precautions. Drill- and workover-strings must be designed consistentwith the anticipated depth, conditionsof the hole, and reservoir environmentto be encountered. You must minimizeexposure of the drill- or workover-string to high stresses as much as prac-tical and consistent with well condi-tions. Proper handling techniques mustbe taken to minimize notching andstress concentrations. Precautionsmust be taken to minimize stressescaused by doglegs, improper stiffnessratios, improper torque, whip, abrasivewear on tool joints, and joint imbal-ance.

(6) Flare system. The flare outlet mustbe of a diameter that allows easy non-restricted flow of gas. You must locateflare line outlets on the downside ofthe facility and as far from the facilityas is feasible, taking into account theprevailing wind directions, the wakeeffects caused by the facility and adja-cent structure(s), and the height of allsuch facilities and structures. Youmust equip the flare outlet with anautomatic ignition system including apilot-light gas source or an equivalentsystem. You must have alternatemethods for igniting the flare. Youmust pipe to the flare system used forH2S all vents from production processequipment, tanks, relief valves, burstplates, and similar devices.

(7) Corrosion mitigation. You must useeffective means of monitoring and con-

trolling corrosion caused by acid gases(H2S and CO2) in both the downhole andsurface portions of a production sys-tem. You must take specific corrosionmonitoring and mitigating measures inareas of unusually severe corrosionwhere accumulation of water and/orhigher concentration of H2S exists.

(8) Wireline lubricators. Lubricatorswhich may be exposed to fluids con-taining H2S must be of H2S-resistantmaterials.

(9) Fuel and/or instrument gas. Youmust not use gas containing H2S for in-strument gas. You must not use gascontaining H2S for fuel gas without theprior approval of the District Super-visor.

(10) Sensing lines and devices. Metalsused for sensing line and safety-controldevices which are necessarily exposedto H2S-bearing fluids must be con-structed of H2S-corrosion resistant ma-terials or coated so as to resist H2Scorrosion.

(11) Elastomer seals. You must useH2S-resistant materials for all sealswhich may be exposed to fluids con-taining H2S.

(12) Water disposal. If you dispose ofproduced water by means other thansubsurface injection, you must submitto the District Supervisor an analysisof the anticipated H2S content of thewater at the final treatment vessel andat the discharge point. The District Su-pervisor may require that the water betreated for removal of H2S. The Dis-trict Supervisor may require the sub-mittal of an updated analysis if thewater disposal rate or the potentialH2S content increases.

(13) Deck drains. You must equip opendeck drains with traps or similar de-vices to prevent the escape of H2S gasinto the atmosphere.

(14) Sealed voids. You must take pre-cautions to eliminate sealed spaces inpiping designs (e.g., slip-on flanges, re-inforcing pads) which can be invadedby atomic hydrogen when H2S ispresent.

[62 FR 3795, Jan. 27, 1997. Redesignated andamended at 63 FR 29479, 29485, May 29, 1998; 65FR 15864, Mar. 24, 2000]


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Subpart E—Oil and Gas Well-Completion Operations

§ 250.500 General requirements.Well-completion operations shall be

conducted in a manner to protectagainst harm or damage to life (includ-ing fish and other aquatic life), prop-erty, natural resources of the OCS in-cluding any mineral deposits (in areasleased and not leased), the national se-curity or defense, or the marine, coast-al, or human environment.

§ 250.501 Definition.When used in this subpart, the fol-

lowing term shall have the meaninggiven below:

Well-completion operations means thework conducted to establish the pro-duction of a well after the production-casing string has been set, cemented,and pressure-tested.

§ 250.502 Equipment movement.The movement of well-completion

rigs and related equipment on and off aplatform or from well to well on thesame platform, including rigging upand rigging down, shall be conducted ina safe manner. All wells in the samewell-bay which are capable of pro-ducing hydrocarbons shall be shut inbelow the surface with a pump-through-type tubing plug and at thesurface with a closed master valveprior to moving well-completion rigsand related equipment, unless other-wise approved by the District Super-visor. A closed surface-controlled sub-surface safety valve of the pump-through type may be used in lieu of thepump-through-type tubing plug, pro-vided that the surface control has beenlocked out of operation. The well fromwhich the rig or related equipment isto be moved shall also be equipped witha back-pressure valve prior to remov-ing the blowout preventer (BOP) sys-tem and installing the tree.

[53 FR 10690, Apr. 1, 1988, as amended at 55FR 47752, Nov. 15, 1990. Redesignated at 63 FR29479, May 29, 1998]

§ 250.503 Emergency shutdown system.When well-completion operations are

conducted on a platform where there

are other hydrocarbon-producing wellsor other hydrocarbon flow, an emer-gency shutdown system (ESD) manu-ally controlled station shall be in-stalled near the driller’s console orwell-servicing unit operator’s work sta-tion.

§ 250.504 Hydrogen sulfide.

When a well-completion operation isconducted in zones known to containhydrogen sulfide (H2S) or in zoneswhere the presence of H2S is unknown(as defined in § 250.417 of this part), thelessee shall take appropriate pre-cautions to protect life and property onthe platform or completion unit, in-cluding, but not limited to operationssuch as blowing the well down, disman-tling wellhead equipment and flowlines, circulating the well, swabbing,and pulling tubing, pumps, and pack-ers. The lessee shall comply with therequirements in § 250.417 of this part aswell as the appropriate requirements ofthis subpart.

[53 FR 10690, Apr. 1, 1988. Redesignated andamended at 63 FR 29479, 29485, May 29, 1998]

§ 250.505 Subsea completions.

No subsea well completion shall becommenced until the lessee obtainswritten approval from the District Su-pervisor in accordance with § 250.513 ofthis part. That approval shall be basedupon a case-by-case determination thatthe proposed equipment and procedureswill adequately control the well andpermit safe production operations.


§ 250.506 Crew instructions.

Prior to engaging in well-completionoperations, crew members shall be in-structed in the safety requirements ofthe operations to be performed, pos-sible hazards to be encountered, andgeneral safety considerations to pro-tect personnel, equipment, and the en-vironment. Date and time of safetymeetings shall be recorded and avail-able at the facility for review by MMSrepresentatives.


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30 CFR Ch. II (7–1–01 Edition)§§ 250.507–250.508

§§ 250.507–250.508 [Reserved]

§ 250.509 Well-completion structureson fixed platforms.

Derricks, masts, substructures, andrelated equipment shall be selected, de-signed, installed, used, and maintainedso as to be adequate for the potentialloads and conditions of loading thatmay be encountered during the pro-posed operations. Prior to moving awell-completion rig or equipment ontoa platform, the lessee shall determinethe structural capability of the plat-form to safely support the equipmentand proposed operations, taking intoconsideration the corrosion protection,age of platform, and previous stressesto the platform.

[53 FR 10690, Apr. 1, 1988, as amended at 54FR 50616, Dec. 8, 1989. Redesignated at 63 FR29479, May 29, 1998]

§ 250.510 Diesel engine air intakes.No later than May 31, 1989, diesel en-

gine air intakes shall be equipped witha device to shut down the diesel enginein the event of runaway. Diesel engineswhich are continuously attended shallbe equipped with either remote oper-ated manual or automatic-shutdowndevices. Diesel engines which are notcontinuously attended shall beequipped with automatic-shutdown de-vices.

§ 250.511 Traveling-block safety de-vice.

After May 31, 1989, all units beingused for well-completion operationswhich have both a traveling block anda crown block shall be equipped with asafety device which is designed to pre-vent the traveling block from strikingthe crown block. The device shall bechecked for proper operation weeklyand after each drill-line slipping oper-ation. The results of the operationalcheck shall be entered in the oper-ations log.

§ 250.512 Field well-completion rules.When geological and engineering in-

formation available in a field enablesthe District Supervisor to determinespecific operating requirements, fieldwell-completion rules may be estab-lished on the District Supervisor’s ini-

tiative or in response to a request froma lessee. Such rules may modify thespecific requirements of this subpart.After field well-completion rules havebeen established, well-completion oper-ations in the field shall be conducted inaccordance with such rules and otherrequirements of this subpart. Fieldwell-completion rules may be amendedor canceled for cause at any time uponthe initiative of the District Super-visor or upon the request of a lessee.

§ 250.513 Approval and reporting ofwell-completion operations.

(a) No well-completion operationshall begin until the lessee receiveswritten approval from the District Su-pervisor. If completion is planned andthe data are available at the time theApplication for Permit to Drill, FormMMS–123 (see § 250.414 of this part), issubmitted, approval for a well comple-tion may be requested on that form. Ifthe completion has not been approvedor if the completion objective or planshave significantly changed, approvalfor such operations shall be requestedon Form MMS–124, Sundry Notices andReports on Wells.

(b) The following information shallbe submitted with Form MMS–124 (orwith Form MMS–123):

(1) A brief description of the well-completion procedures to be followed, astatement of the expected surface pres-sure, and type and weight of comple-tion fluids;

(2) A schematic drawing of the wellshowing the proposed producing zone(s)and the subsurface well-completionequipment to be used;

(3) For multiple completions, a par-tial electric log showing the zones pro-posed for completion, if logs have notbeen previously submitted; and

(4) When the well-completion is in azone known to contain H2S or a zonewhere the presence of H2S is unknown,information pursuant to § 250.417 of thispart.

(c) Within 30 days after completion,Form MMS–125, Well Summary Report,including a schematic of the tubingand subsurface equipment, shall be sub-mitted to the District Supervisor.


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(d) Public information copies ofForm MMS–125 shall be submitted inaccordance with § 250.190.


§ 250.514 Well-control fluids, equip-ment, and operations.

(a) Well-control fluids, equipment,and operations shall be designed, uti-lized, maintained, and/or tested as nec-essary to control the well in foresee-able conditions and circumstances, in-cluding subfreezing conditions. Thewell shall be continuously monitoredduring well-completion operations andshall not be left unattended at anytime unless the well is shut in and se-cured.

(b) The following well-control-fluidequipment shall be installed, main-tained, and utilized:

(1) A fill-up line above the uppermostBOP;

(2) A well-control, fluid-volumemeasuring device for determining fluidvolumes when filling the hole on trips;and

(3) A recording mud-pit-level indi-cator to determine mud-pit-volumegains and losses. This indicator shallinclude both a visual and an audiblewarning device.

(c) When coming out of the hole withdrill pipe, the annulus shall be filledwith well-control fluid before thechange in such fluid level decreases thehydrostatic pressure 75 pounds persquare inch (psi) or every five stands ofdrill pipe, whichever gives a lower de-crease in hydrostatic pressure. Thenumber of stands of drill pipe and drillcollars that may be pulled prior to fill-ing the hole and the equivalent well-control fluid volume shall be cal-culated and posted near the operator’sstation. A mechanical, volumetric, orelectronic device for measuring theamount of well-control fluid requiredto fill the hole shall be utilized.

§ 250.515 Blowout prevention equip-ment.

(a) The BOP system and system com-ponents and related well-control equip-ment shall be designed, used, main-tained, and tested in a manner nec-

essary to assure well control in foresee-able conditions and circumstances, in-cluding subfreezing conditions. Theworking pressure rating of the BOPsystem and BOP system componentsshall exceed the expected surface pres-sure to which they may be subjected. Ifthe expected surface pressure exceedsthe rated working pressure of the an-nular preventer, the lessee shall submitwith Form MMS–124 or Form MMS–123,as appropriate, a well-control proce-dure that indicates how the annularpreventer will be utilized, and the pres-sure limitations that will be appliedduring each mode of pressure control.

(b) The minimum BOP system forwell-completion operations shall in-clude the following:

(1) Three preventers, when the ex-pected surface pressure is less than5,000 psi, consisting of an annular pre-venter, one preventer equipped withpipe rams, and one preventer equippedwith blind or blind-shear rams.

(2) Four preventers, when the ex-pected surface pressure is 5,000 psi orgreater, or for multiple tubing stringsconsisting of an annular preventer, twopreventers equipped with pipe rams,and one preventer equipped with blindor blind-shear rams. When dual tubingstrings are being handled simulta-neously, dual pipe rams shall be in-stalled on one of the pipe-ram pre-venters.

(3) When tapered drill string is used,the minimum BOP system shall in-clude either of the following:

(i) Four preventers, when the ex-pected surface pressure is less than5,000 psi, consisting of an annular pre-venter, two sets of pipe rams, one capa-ble of sealing around the larger sizedrill string and one capable of sealingaround the smaller size drill string(one set of variable bore rams may besubstituted for the two sets of piperams), and one preventer equipped withblind or blind shear rams; or

(ii) Five preventers, when the ex-pected surface pressure is 5,000 psi orgreater, consisting of an annular pre-venter, two sets of pipe rams capable ofsealing around the larger size drillstring, one set of pipe rams capable ofsealing around the smaller size drillstring (one set of variable bore ramsmay be substituted for one set of pipe


318

30 CFR Ch. II (7–1–01 Edition)§ 250.516

rams capable of sealing around thelarger size drill string and the set ofpipe rams capable of sealing around thesmaller size drill string), and a pre-venter equipped with blind or blind-shears rams.

(c) The BOP systems for well comple-tions shall be equipped with the fol-lowing:

(1) A hydraulic-actuating systemthat provides sufficient accumulatorcapacity to supply 1.5 times the volumenecessary to close all BOP equipmentunits with a minimum pressure of 200psi above the precharge pressure with-out assistance from a charging system.No later than December 1, 1988, accu-mulator regulators supplied by rig airand without a secondary source ofpneumatic supply, shall be equippedwith manual overrides, or alternately,other devices provided to ensure capa-bility of hydraulic operations if rig airis lost.

(2) A secondary power source, inde-pendent from the primary powersource, with sufficient capacity toclose all BOP system components andhold them closed.

(3) Locking devices for the pipe-rampreventers.

(4) At least one remote BOP-controlstation and one BOP-control station onthe rig floor.

(5) A choke line and a kill line eachequipped with two full opening valvesand a choke manifold. At least one ofthe valves on the choke line shall beremotely controlled. At least one ofthe valves on the kill line shall be re-motely controlled, except that a checkvalve on the kill line in lieu of the re-motely controlled valve may be in-stalled provided that two readily acces-sible manual valves are in place andthe check valve is placed between themanual valves and the pump. Thisequipment shall have a pressure ratingat least equivalent to the ram pre-venters.

(d) An inside BOP or a spring-loaded,back-pressure safety valve and an es-sentially full-opening, work-stringsafety valve in the open position shallbe maintained on the rig floor at alltimes during well-completion oper-ations. A wrench to fit the work-stringsafety valve shall be readily available.Proper connections shall be readily

available for inserting valves in thework string.

[53 FR 10690, Apr. 1, 1988, as amended at 54FR 50616, Dec. 8, 1989; 58 FR 49928, Sept. 24,1993. Redesignated at 62 29479, May 29, 1998]

§ 250.516 Blowout preventer systemtests, inspections, and maintenance.

(a) BOP pressure testing timeframes.You must pressure test your BOP sys-tem:

(1) When installed; and(2) Before 14 days have elapsed since

your last BOP pressure test. You mustbegin to test your BOP system before12 a.m. (midnight) on the 14th day fol-lowing the conclusion of the previoustest. However, the District Supervisormay require testing every 7 days if con-ditions or BOP performance warrant.

(b) BOP test pressures. When you testthe BOP system, you must conduct alow pressure and a high pressure testfor each BOP component. Each indi-vidual pressure test must hold pressurelong enough to demonstrate that thetested component(s) holds the requiredpressure. The District Supervisor mayapprove or require other test pressuresor practices. Required test pressuresare as follows:

(1) All low pressure tests must be be-tween 200 and 300 psi. Any initial pres-sure above 300 psi must be bled back toa pressure between 200 and 300 psi be-fore starting the test. If the initialpressure exceeds 500 psi, you mustbleed back to zero and reinitiate thetest. You must conduct the low pres-sure test before the high pressure test.

(2) For ram-type BOP’s, choke mani-fold, and other BOP equipment, thehigh pressure test must equal the ratedworking pressure of the equipment.

(3) For annular-type BOP’s, the highpressure test must equal 70 percent ofthe rated working pressure of theequipment.

(c) Duration of pressure test. Each testmust hold the required pressure for 5minutes.

(1) For surface BOP systems and sur-face equipment of a subsea BOP sys-tem, a 3-minute test duration is ac-ceptable if you record your test pres-sures on the outermost half of a 4-hourchart, on a 1-hour chart, or on a digitalrecorder.


319


(2) If the equipment does not hold therequired pressure during a test, youmust remedy the problem and retestthe affected component(s).

(d) Additional BOP testing require-ments. You must:

(1) Use water to test the surface BOPsystem;

(2) Stump test a subsurface BOP sys-tem before installation. You must usewater to stump test a subsea BOP sys-tem. You may use drilling or comple-tion fluids to conduct subsequent testsof a subsea BOP system;

(3) Alternate tests between controlstations and pods. If a control stationor pod is not functional, you must sus-pend further completion operationsuntil that station or pod is operable;

(4) Pressure test the blind or blind-shear ram at least every 30 days;

(5) Function test annulars and ramsevery 7 days;

(6) Pressure-test variable bore-piperams against all sizes of pipe in use, ex-cluding drill collars and bottom-holetools; and

(7) Test affected BOP components fol-lowing the disconnection or repair ofany well-pressure containment seal inthe wellhead or BOP stack assembly;

(e) Postponing BOP tests. You maypostpone a BOP test if you have well-control problems. You must conductthe required BOP test as soon as pos-sible (i.e., first trip out of the hole)after the problem has been remedied.You must record the reason for post-poning any test in the driller’s report.

(f) Weekly crew drills. You must con-duct a weekly drill to familiarize allpersonnel engaged in well-completionoperations with appropriate safetymeasures.

(g) BOP inspections. You must vis-ually inspect your BOP system and ma-rine riser at least once each day ifweather and sea conditions permit.You may use television cameras to in-spect this equipment. The District Su-pervisor may approve alternate meth-ods and frequencies to inspect a marineriser.

(h) BOP maintenance. You must main-tain your BOP system to ensure thatthe equipment functions properly.

(i) BOP test records. You must recordthe time, date, and results of all pres-sure tests, actuations, crew drills, and

inspections of the BOP system, systemcomponents, and marine riser in thedriller’s report. In addition, you must:

(1) Record BOP test pressures onpressure charts;

(2) Have your onsite representativecertify (sign and date) BOP test chartsand reports as correct;

(3) Document the sequential order ofBOP and auxiliary equipment testingand the pressure and duration of eachtest. You may reference a BOP testplan if it is available at the facility;

(4) Identify the control station or podused during the test;

(5) Identify any problems or irreg-ularities observed during BOP systemand equipment testing and record ac-tions taken to remedy the problems orirregularities;

(6) Retain all records including pres-sure charts, driller’s report, and ref-erenced documents pertaining to BOPtests, actuations, and inspections atthe facility for the duration of thecompletion activity; and

(7) After completion of the well, youmust retain all the records listed inparagraph (i)(6) of this section for a pe-riod of 2 years at the facility, at thelessee’s field office nearest the OCS fa-cility, or at another location conven-iently available to the District Super-visor.

(j) Alternate methods. The District Su-pervisor may require, or approve, morefrequent testing, as well as differenttest pressures and inspection methods,or other practices.

[63 FR 29607, June 1, 1998]

§ 250.517 Tubing and wellhead equip-ment.

(a) No tubing string shall be placed inservice or continue to be used unlesssuch tubing string has the necessarystrength and pressure integrity and isotherwise suitable for its intended use.

(b) In the event of prolonged oper-ations such as milling, fishing, jarring,or washing over that could damage thecasing, the casing shall be pressure-tested, calipered, or otherwise evalu-ated every 30 days and the results sub-mitted to the District Supervisor.

(c) When the tree is installed, thewellhead shall be equipped so that allannuli can be monitored for sustainedpressure. If sustained casing pressure is


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30 CFR Ch. II (7–1–01 Edition)§ 250.600

observed on a well, the lessee shall im-mediately notify the District Super-visor.

(d) Wellhead, tree, and related equip-ment shall have a pressure ratinggreater than the shut–in tubing pres-sure and shall be designed, installed,used, maintained, and tested so as toachieve and maintain pressure control.New wells completed as flowing or gas-lift wells shall be equipped with a min-imum of one master valve and one sur-face safety valve, installed above themaster valve, in the vertical run of thetree.

(e) Subsurface safety equipment shallbe installed, maintained, and tested incompliance with § 250.801 of this part.

[53 FR 10690, Apr. 1, 1988, as amended at 55FR 47753 Nov. 15, 1990. Redesignated andamended at 63 FR 29479, 29485, May 29, 1998]

Subpart F—Oil and Gas Well-Workover Operations

§ 250.600 General requirements.Well-workover operations shall be

conducted in a manner to protectagainst harm or damage to life (includ-ing fish and other aquatic life), prop-erty, natural resources of the OuterContinental Shelf (OCS) including anymineral deposits (in areas leased andnot leased), the national security or de-fense, or the marine, coastal, or humanenvironment.

§ 250.601 Definitions.When used in this subpart, the fol-

lowing terms shall have the meaningsgiven below:

Routine operations mean any of thefollowing operations conducted on awell with the tree installed:

(a) Cutting paraffin;(b) Removing and setting pump-

through-type tubing plugs, gas-liftvalves, and subsurface safety valveswhich can be removed by wireline oper-ations;

(c) Bailing sand;(d) Pressure surveys;(e) Swabbing;(f) Scale or corrosion treatment;(g) Caliper and gauge surveys;(h) Corrosion inhibitor treatment;(i) Removing or replacing subsurface

pumps;

(j) Through-tubing logging(diagnostics);

(k) Wireline fishing; and(l) Setting and retrieving other sub-

surface flow-control devices.Workover operations mean the work

conducted on wells after the initialcompletion for the purpose of main-taining or restoring the productivity ofa well.

§ 250.602 Equipment movement.

The movement of well-workover rigsand related equipment on and off aplatform or from well to well on thesame platform, including rigging upand rigging down, shall be conducted ina safe manner. All wells in the samewell-bay which are capable of pro-ducing hydrocarbons shall be shut inbelow the surface with a pump-through-type tubing plug and at thesurface with a closed master valveprior to moving well-workover rigs andrelated equipment unless otherwise ap-proved by the District Supervisor. Aclosed surface-controlled subsurfacesafety valve of the pump-through-typemay be used in lieu of the pump-through-type tubing plug provided thatthe surface control has been locked outof operation. The well to which a well-workover rig or related equipment is tobe moved shall also be equipped with aback-pressure valve prior to removingthe tree and installing and testing theblowout-preventer (BOP) system. Thewell from which a well-workover rig orrelated equipment is to be moved shallalso be equipped with a back pressurevalve prior to removing the BOP sys-tem and installing the tree. Coiled tub-ing units, snubbing units, or wirelineunits may be moved onto a platformwithout shutting in wells.

§ 250.603 Emergency shutdown system.

When well-workover operations areconducted on a well with the tree re-moved, an emergency shutdown system(ESD) manually controlled stationshall be installed near the driller’s con-sole or well-servicing unit operator’swork station, except when there is noother hydrocarbon-producing well orother hydrocarbon flow on the plat-form.


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§ 250.604 Hydrogen sulfide.When a well-workover operation is

conducted in zones known to containhydrogen sulfide (H2S) or in zoneswhere the presence of H2S is unknown(as defined in § 250.417 of this part), thelessee shall take appropriate pre-cautions to protect life and property onthe platform or rig, including but notlimited to operations such as blowingthe well down, dismantling wellheadequipment and flow lines, circulatingthe well, swabbing, and pulling tubing,pumps and packers. The lessee shallcomply with the requirements in§ 250.417 of this part as well as the ap-propriate requirements of this subpart.

[53 FR 10690, Apr. 1, 1988. Redesignated andamended at 63 FR 29479, 29485, May 29, 1998; 64FR 9065, Feb. 24, 1999]

§ 250.605 Subsea workovers.No subsea well-workover operation

including routine operations shall becommenced until the lessee obtainswritten approval from the District Su-pervisor in accordance with § 250.613 ofthis part. That approval shall be basedupon a case-by-case determination thatthe proposed equipment and procedureswill maintain adequate control of thewell and permit continued safe produc-tion operations.


§ 250.606 Crew instructions.Prior to engaging in well-workover

operations, crew members shall be in-structed in the safety requirements ofthe operations to be performed, pos-sible hazards to be encountered, andgeneral safety considerations to pro-tect personnel, equipment, and the en-vironment. Date and time of safetymeetings shall be recorded and avail-able at the facility for review by a Min-erals Management Service representa-tive.

§§ 250.607–250.608 [Reserved]

§ 250.609 Well-workover structures onfixed platforms.

Derricks, masts, substructures, andrelated equipment shall be selected, de-signed, installed, used, and maintainedso as to be adequate for the potential

loads and conditions of loading thatmay be encountered during the oper-ations proposed. Prior to moving awell-workover rig or well-servicingequipment onto a platform, the lesseeshall determine the structural capa-bility of the platform to safely supportthe equipment and proposed oper-ations, taking into consideration thecorrosion protection, age of the plat-form, and previous stresses to the plat-form.

§ 250.610 Diesel engine air intakes.No later than May 31, 1989, diesel en-

gine air intakes shall be equipped witha device to shut down the diesel enginein the event of runaway. Diesel engineswhich are continuously attended shallbe equipped with either remote oper-ated manual or automatic shutdowndevices. Diesel engines which are notcontinuously attended shall beequipped with automatic shutdown de-vices.


§ 250.611 Traveling-block safety de-vice.

After May 31, 1989, all units beingused for well-workover operationswhich have both a traveling block anda crown block shall be equipped with asafety device which is designed to pre-vent the traveling block from strikingthe crown block. The device shall bechecked for proper operation weeklyand after each drill-line slipping oper-ation. The results of the operationalcheck shall be entered in the oper-ations log.

§ 250.612 Field well-workover rules.When geological and engineering in-

formation available in a field enablesthe District Supervisor to determinespecific operating requirements, fieldwell-workover rules may be establishedon the District Supervisor’s initiativeor in response to a request from a les-see. Such rules may modify the specificrequirements of this subpart. Afterfield well-workover rules have been es-tablished, well-workover operations inthe field shall be conducted in accord-ance with such rules and other require-ments of this subpart. Field well-


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30 CFR Ch. II (7–1–01 Edition)§ 250.613

workover rules may be amended orcanceled for cause at any time uponthe initiative of the District Super-visor or upon the request of a lessee.

§ 250.613 Approval and reporting forwell-workover operations.

(a) No well-workover operation ex-cept routine ones, as defined in § 250.601of this part, shall begin until the lesseereceives written approval from the Dis-trict Supervisor. Approval for such op-erations shall be requested on FormMMS–124, Sundry Notices and Reportson Wells.

(b) The following information shallbe submitted with Form MMS–124:

(1) A brief description of the well-workover procedures to be followed, astatement of the expected surface pres-sure, and type and weight of workoverfluids;

(2) When changes in existing sub-surface equipment are proposed, a sche-matic drawing of the well showing thezone proposed for workover and theworkover equipment to be used; and

(3) Where the well-workover is in azone known to contain H2S or a zonewhere the presence of H2S is unknown,information pursuant to § 250.417 of thispart.

(c) The following additional informa-tion shall be submitted with FormMMS–124 if completing to a new zone isproposed:

(1) Reason for abandonment ofpresent producing zone including sup-portive well test data, and

(2) A statement of anticipated orknown pressure data for the new zone.

(d) Within 30 days after completingthe well-workover operation, exceptroutine operations, Form MMS–124,Sundry Notices and Reports on Wells,shall be submitted to the District Su-pervisor, showing the work as per-formed. In the case of a well-workoveroperation resulting in the initial re-completion of a well into a new zone, aForm MMS–125, Well Summary Report,shall be submitted to the District Su-pervisor and shall include a new sche-matic of the tubing subsurface equip-

ment if any subsurface equipment hasbeen changed.

[53 FR 10690, Apr. 1, 1988, as amended at 58FR 49928, Sept. 24, 1993. Redesignated andamended at 63 FR 29479, 29485, May 29, 1998; 65FR 35824, June 6, 2000]


The following requirements applyduring all well-workover operationswith the tree removed:

(a) Well-control fluids, equipment,and operations shall be designed, uti-lized, maintained, and/or tested as nec-essary to control the well in foresee-able conditions and circumstances, in-cluding subfreezing conditions. Thewell shall be continuously monitoredduring well-workover operations andshall not be left unattended at anytimeunless the well is shut in and secured.

(b) When coming out of the hole withdrill pipe or a workover string, the an-nulus shall be filled with well-controlfluid before the change in such fluidlevel decreases the hydrostatic pres-sure 75 pounds per square inch (psi) orevery five stands of drill pipe orworkover string, whichever gives alower decrease in hydrostatic pressure.The number of stands of drill pipe orworkover string and drill collars thatmay be pulled prior to filling the holeand the equivalent well-control fluidvolume shall be calculated and postednear the operator’s station. A mechan-ical, volumetric, or electronic devicefor measuring the amount of well-con-trol fluid required to fill the hold shallbe utilized.

(c) The following well-control-fluidequipment shall be installed, main-tained, and utilized:

(1) A fill-up line above the uppermostBOP;

(2) A well-control, fluid-volumemeasuring device for determining fluidvolumes when filling the hole on trips;and



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(a) The BOP system, system compo-nents and related well-control equip-ment shall be designed, used, main-tained, and tested in a manner nec-essary to assure well control in foresee-able conditions and circumstances, in-cluding subfreezing conditions. Theworking pressure rating of the BOPsystem and system components shallexceed the expected surface pressure towhich they may be subjected. If the ex-pected surface pressure exceeds therated working pressure of the annularpreventer, the lessee shall submit withForm MMS–124, requesting approval ofthe well-workover operation, a well-control procedure that indicates howthe annular preventer will be utilized,and the pressure limitations that willbe applied during each mode of pres-sure control.

(b) The minimum BOP system forwell-workover operations with the treeremoved shall include of the following:

(1) Three preventers, when the ex-pected surface pressure is less than5,000 psi, consisting of an annular pre-venter, one preventer equipped withpipe rams, and one preventer equippedwith blind or blind-shear rams.

(2) Four preventers, when the ex-pected surface pressure is 5,000 psi orgreater, or for multiple tubing stringsconsisting of an annular preventer, twopreventers equipped with pipe rams,and one preventer equipped with blindor blind-shear rams. When dual tubingstrings are being handled simulta-neously, dual pipe rams shall be in-stalled on one of the pipe-ram pre-venters.

(3) When a tapered drill string isused, the minimum BOP system shallinclude either of the following:

(i) Four preventers, when the ex-pected surface pressure is less than5,000 psi, consisting of an annular pre-venter, two sets of pipe rams, one capa-ble of sealing around the larger sizedrill string, and one capable of sealingaround the smaller size drill string(one set of variable bore rams may besubstituted for the two sets of piperams), and one preventer equipped withblind or blind-shear rams; or

(ii) Five preventers, when the ex-pected surface pressure is 5,000 psi or

greater, consisting of an annular pre-venter, two sets of pipe rams capable ofsealing around the larger size drillstring, one set of pipe rams capable ofsealing around the smaller size drillstring (one set of variable bore ramsmay be substituted for one set of piperams capable of sealing around thelarger size drill string and the set ofpipe rams capable of sealing around thesmaller size drill string), and a pre-venter equipped with blind or blind-shear rams.

(c) The BOP systems for well-workover operations with the tree re-moved shall be equipped with the fol-lowing:

(1) A hydraulic-actuating systemthat provides sufficient accumulatorcapacity to supply 1.5 times the volumenecessary to close all BOP equipmentunits with a minimum pressure of 200psi above the precharge pressure with-out assistance from a charging system.No later than December 1, 1988, accu-mulator regulators supplied by rig airand without a secondary source ofpneumatic supply, shall be equippedwith manual overrides, or alternately,other devices provided to ensure capa-bility of hydraulic operations if rig airis lost;

(2) A secondary power source, inde-pendent from the primary powersource, with sufficient capacity toclose all BOP system components andhold them closed;

(3) Locking devices for the pipe-rampreventers;

(4) At least one remote BOP-controlstation and one BOP-control station onthe rig floor; and

(5) A choke line and a kill line eachequipped with two full opening valvesand a choke manifold. At least one ofthe valves on the choke-line shall beremotely controlled. At least one ofthe valves on the kill line shall be re-motely controlled, except that a checkvalve on the kill line in lieu of the re-motely controlled valve may be in-stalled provided two readily accessiblemanual valves are in place and thecheck valve is placed between the man-ual valves and the pump. This equip-ment shall have a pressure rating atleast equivalent to the ram preventers.

(d) The minimum BOP-system com-ponents for well-workover operations


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30 CFR Ch. II (7–1–01 Edition)§ 250.616

with the tree in place and performedthrough the wellhead inside of conven-tional tubing using small-diameterjointed pipe (usually 3⁄4 inch to 11⁄4inch) as a work string, i.e., small-tub-ing operations, shall include the fol-lowing:

(1) Two sets of pipe rams, and(2) One set of blind rams.(e) The minimum BOP-system com-

ponents for well-workover operationswith the tree in place and performed bymanipulating spooled, nonjointed pipethrough the wellhead, i.e., coiled-tub-ing operations, shall include the fol-lowing:

(1) One set of pipe rams hydraulicallyoperated,

(2) One two-way slip assembly hy-draulically operated,

(3) One pipe-cutter assembly hydrau-lically operated,

(4) One set of blind rams hydrau-lically operated,

(5) One pipe-stripper assembly, and(6) One spool with side outlets.(f) The minimum BOP-system compo-

nents for well-workover operationswith the tree in place and performed bymoving tubing or drill pipe in or out ofa well under pressure utilizing equip-ment specifically designed for that pur-pose, i.e., snubbing operations, shall in-clude the following:

(1) One set of pipe rams hydraulicallyoperated, and

(2) Two sets of stripper-type piperams hydraulically operated with spac-er spool.

(g) An inside BOP or a spring-loaded,back-pressure safety valve and an es-sentially full-opening, work-stringsafety valve in the open position shallbe maintained on the rig floor at alltimes during well-workover operationswhen the tree is removed or duringwell-workover operations with the treeinstalled and using small tubing as thework string. A wrench to fit the work-string safety valve shall be readilyavailable. Proper connections shall bereadily available for inserting valves inthe work string. The full-opening safe-ty valve is not required for coiled tub-ing or snubbing operations.

[53 FR 10690, Apr. 1, 1988, as amended at 54FR 50616, Dec. 8, 1989; 58 FR 49928, Sept. 24,1993. Redesignated at 63 FR 29479, May 29,1998]

§ 250.616 Blowout preventer systemtesting, records, and drills.

(a) Prior to conducting high-pressuretests, all BOP system components shallbe successfully tested to a low pressureof 200 to 300 psi. Ram-type BOP’s, re-lated control equipment, including thechoke and kill manifolds, and safetyvalves shall be successfully tested tothe rated working pressure of the BOPequipment or as otherwise approved bythe District Supervisor. Variable borerams shall be pressure-tested againstall sizes of drill pipe in the well exclud-ing drill collars. Surface BOP systemsshall be pressure tested with water.The annular-type BOP shall besuccessfullly tested at 70 percent of itsrated working pressure or as otherwiseapproved by the District Supervisor.Each valve in the choke and kill mani-folds shall be successfully, sequentiallypressure tested to the ram-type BOPtest pressure.

(b) The BOP systems shall be testedat the following times:

(1) When installed;(2) At least every 7 days, alternating

between control stations and at stag-gered intervals to allow each crew tooperate the equipment. If either con-trol system is not functional, furtheroperations shall be suspended until thenonfunctional, system is operable. Thetest every 7 days is not required forblind or blind-shear rams. The blind orblind-shear rams shall be tested atleast once every 30 days during oper-ation. A longer period between blowoutpreventer tests is allowed when there isa stuck pipe or pressure-control oper-ation and remedial efforts are beingperformed. The tests shall be con-ducted as soon as possible and beforenormal operations resume. The reasonfor postponing testing shall be enteredinto the operations log.

(3) Following repairs that require dis-connecting a pressure seal in the as-sembly, the affected seal will be pres-sure tested.

(c) All personnel engaged in well-workover operations shall participatein a weekly BOP drill to familiarizecrew members with appropriate safetymeasures.

(d) The lessee shall record pressureconditions during BOP tests on pres-sure charts, unless otherwise approved


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by the District Supervisor. The test in-terval for each BOP component testedshall be sufficient to demonstrate thatthe component is effectively holdingpressure. The charts shall be certifiedas correct by the operator’s representa-tive at the facility.

(e) The time, date, and results of allpressure tests, actuations, inspections,and crew drills of the BOP system, sys-tem components, and marine risersshall be recorded in the operations log.The BOP tests shall be documented inaccordance with the following:

(1) The documentation shall indicatethe sequential order of BOP and auxil-iary equipment testing and the pres-sure and duration of each test. As analternate, the documentation in theoperations log may reference a BOPtest plan that contains the required in-formation and is retained on file at thefacility.

(2) The control station used duringthe test shall be identified in the oper-ations log. For a subsea system, thepod used during the test shall be iden-tified in the operations log.

(3) Any problems or irregularities ob-served during BOP and auxiliary equip-ment testing and any actions taken toremedy such problems or irregularitiesshall be noted in the operations log.

(4) Documentation required to be en-tered in the operation log may insteadbe referenced in the operations log. Allrecords including pressure charts, oper-ations log, and referenced documentspertaining to BOP tests, actuations,and inspections, shall be available forMMS review at the facility for the du-ration of well-workover activity. Fol-lowing completion of the well-workover actity, all such records shallbe retained for a period of 2 years atthe facility, at the lessee’s filed officenearest the OCS facility, or at anotherlocation conveniently available to theDistrict Supervisor.

[53 FR 10690, Apr. 1, 1988, as amended at 54FR 50617, Dec. 8, 1989; 56 FR 1915, Jan. 18,1991. Redesignated at 63 FR 29479, May 29,1998]


The lessee shall comply with the fol-lowing requirements during well-

workover operations with the tree re-moved:

(a) No tubing string shall be placed inservice or continue to be used unlesssuch tubing string has the necessarystrength and pressure integrity and isotherwise suitable for its intended use.

(b) In the event of prolonged oper-ations such as milling, fishing, jarring,or washing over that could damage thecasing, the casing shall be pressuretested, calipered, or otherwise evalu-ated every 30 days and the results sub-mitted to the District Supervisor.

(c) When reinstalling the tree, thewellhead shall be equiped so that allannuli can be monitored for sustainedpressure. If sustained casing pressure isobserved on a well, the lessee shall im-mediately notify the District Super-visor.

(d) Wellhead, tree, and related equip-ment shall have a pressure ratinggreater than the shut-in tubing pres-sure and shall be designed, installed,used, maintained, and tested so as toachieve and maintain pressure control.The tree shall be equipped with a min-imum of one master valve and one sur-face safety valve in the vertical run ofthe tree when it is reinstalled.

(e) Subsurface safety equipment shallbe installed, maintained, and tested incompliance with § 250.801 of this part.

[53 FR 10690, Apr. 1, 1988, as amended at 54FR 50617, Dec. 8, 1989; 55 FR 47753, Nov. 15,1990. Redesignated and amended at 63 FR29479, 29485, May 29, 1998]

§ 250.618 Wireline operations.

The lessee shall comply with the fol-lowing requirements during routine, asdefined in § 250.601 of this part, andnonroutine wireline workover oper-ations:

(a) Wireline operations shall be con-ducted so as to minimize leakage ofwell fluids. Any leakage that doesoccur shall be contained to prevent pol-lution.

(b) All wireline perforating oper-ations and all other wireline operationswhere communication exists betweenthe completed hydrocarbon-bearingzone(s) and the wellbore shall use a lu-bricator assembly containing at leastone wireline valve.


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30 CFR Ch. II (7–1–01 Edition)§ 250.700

(c) When the lubricator is initiallyinstalled on the well, it shall be suc-cessfully pressure tested to the ex-pected shut-in surface pressure.


Subpart G—Abandonment ofWells

§ 250.700 General requirements.(a) The lessee shall abandon all wells

in a manner to assure downhole isola-tion of hydrocarbon zones, protectionof freshwater aquifers, clearance ofsites so as to avoid conflict with otheruses of the Outer Continental Shelf(OCS), and prevention of migration offormation fluids within the wellbore orto the seafloor. Any well which is nolonger used or useful for lease oper-ations shall be plugged and abandonedin accordance with the provisions ofthis subpart. However, no productionwell shall be abandoned until its lackof capacity for further profitable pro-duction of oil, gas, or sulphur has beendemonstrated to the satisfaction of theDistrict Supervisor. No well shall beplugged if the plugging operationswould jeopardize safe and economic op-erations of nearby wells, unless thewell poses a hazard to safety or the en-vironment.

(b) Lessees must plug and abandonall well bores, remove all platforms orother facilities, and clear the ocean ofall obstructions to other users. Thisobligation:

(1) Accrues to the lessee when thewell is drilled, the platform or other fa-cility is installed, or the obstruction iscreated; and

(2) Is the joint and several responsi-bility of all lessees and owners of oper-ating rights under the lease at the timethe obligation accrues, and of each fu-ture lessee or owner of operatingrights, until the obligation is satisfiedunder the requirements of this part.

[53 FR 10690, Apr. 1, 1988, as amended at 62FR 27955, May 22, 1997. Redesignated at 63 FR29479, May 29, 1998]

§ 250.701 Approvals.The lessee shall not commence aban-

donment operations without prior ap-proval of the District Supervisor. The

lessee shall submit a request on FormMMS–124, Sundry Notices and Reportson Wells, for approval to abandon awell and a subsequent report of aban-donment within 30 days from comple-tion of the work in accordance with thefollowing:

(a) Notice of Intent to Abandon Well. Arequest for approval to abandon a wellshall contain the reason for abandon-ment including supportive well logsand test data, a description and sche-matic of proposed work includingdepths, type, location, length of plugs,the plans for mudding, cementing,shooting, testing, casing removal, andother pertinent information.

(b) Subsequent report of abandonment.The subsequent report of abandonmentshall include a description of the man-ner in which the abandonment or plug-ging work was accomplished, includingthe nature and quantities of materialsused in the plugging, and all informa-tion listed in paragraph (a) of this sec-tion with a revised schematic. If an at-tempt was made to cut and pull anycasing string, the subsequent reportshall include a description of the meth-ods used, size of casing removed, depthof the casing removal point, and theamount of the casing removed from thewell.

[53 FR 10690, Apr. 1, 1988, as amended at 58FR 49928, Sept. 24, 1993. Redesignated at 63FR 29479, May 29, 1998]

§ 250.702 Permanent abandonment.

(a) Isolation of zones in open hole. Inuncased portions of wells, cement plugsshall be set to extend from a minimumof 100 feet below the bottom to 100 feetabove the top of any oil, gas, or fresh-water zones to isolate fluids in thestrata in which they are found and toprevent them from escaping into otherstrata or to the seafloor. The place-ment of additional cement plugs toprevent the migration of formationfluids in the wellbore may be requiredby the District Supervisor.

(b) Isolation of open hole. Where thereis an open hole below the casing, a ce-ment plug shall be placed in the deep-est casing by the displacement methodand shall extend a minimum of 100 feetabove and 100 feet below the casingshoe. In lieu of setting a cement plug


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across the casing shoe, the followingmethods are acceptable:

(1) A cement retainer and a cementplug shall be set. The cement retainershall have effective back-pressure con-trol and shall be set not less than 50feet and not more than 100 feet abovethe casing shoe. The cement plug shallextend at least 100 feet below the cas-ing shoe and at least 50 feet above theretainer.

(2) If lost circulation conditions havebeen experienced or are anticipated, apermanent-type bridge plug may beplaced within the first 150 feet abovethe casing shoe with a minimum of 50feet of cement on top of the bridgeplug. This bridge plug shall be tested inaccordance with paragraph (g) of thissection.

(c) Plugging or isolating perforated in-tervals. A cement plug shall be set bythe displacement method opposite allperforations which have not beensqueezed with cement. The cement plugshall extend a minimum of 100 feetabove the perforated interval and ei-ther 100 feet below the perforated inter-val or down to a casing plug, whicheveris the lesser. In lieu of setting a cementplug by the displacement method, thefollowing methods are acceptable, pro-vided the perforations are isolatedfrom the hole below:

(1) A cement retainer and a cementplug shall be set. The cement retainershall have effective back-pressure con-trol and shall be set not less than 50feet and not more than 100 feet abovethe top of the perforated interval. Thecement plug shall extend at least 100feet below the bottom of the perforatedinterval with 50 feet placed above theretainer.

(2) A permanent-type bridge plugshall be set within the first 150 feetabove the top of the perforated intervalwith at least 50 feet of cement on top ofthe bridge plug.

(3) A cement plug which is at least200 feet long shall be set by the dis-placement method with the bottom ofthe plug within the first 100 feet abovethe top of the perforated interval.

(d) Plugging of casing stubs. If casingis cut and recovered leaving a stub, thestub shall be plugged in accordancewith one of the following methods:

(1) A stub terminating inside a casingstring shall be plugged with a cementplug extending at least 100 feet aboveand 100 feet below the stub. In lieu ofsetting a cement plug across the stub,the following methods are acceptable:

(i) A cement retainer or a permanent-type bridge plug shall be set not lessthan 50 feet above the stub and cappedwith at least 50 feet of cement, or

(ii) A cement plug which is at least200 feet long shall be set with the bot-tom of the plug within 100 feet abovethe stub.

(2) If the stub is below the next largerstring, plugging shall be accomplishedas required to isolate zones or to iso-late an open hole as described in para-graphs (a) and (b) of this section.

(e) Plugging of annular space. Any an-nular space communicating with anyopen hole and extending to the mudline shall be plugged with at least 200feet of cement.

(f) Surface plug. A cement plug whichis at least 150 feet in length shall be setwith the top of the plug within thefirst 150 feet below the mud line. Theplug shall be placed in the smalleststring of casing which extends to themud line.

(g) Testing of plugs. The setting andlocation of the first plug below the sur-face plug shall be verified by one of thefollowing methods:

(1) The lessee shall place a minimumpipe weight of 15,000 pounds on the ce-ment plug, cement retainer, or bridgeplug. The cement placed above thebridge plug or retainer is not requiredto be tested.

(2) The lessee shall test the plug witha minimum pump pressure of 1,000pounds per square inch with a result ofno more than a 10-percent pressuredrop during a 15-minute period.

(h) Fluid left in hole. Each of the re-spective intervals of the hole betweenthe various plugs shall be filled withfluid of sufficient density to exert a hy-drostatic pressure exceeding the great-est formation pressure in the intervalsbetween the plugs at time of abandon-ment.

(i) Clearance of location. Allwellheads, casings, pilings, and otherobstructions shall be removed to adepth of at least 15 feet below the mud


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30 CFR Ch. II (7–1–01 Edition)§ 250.703

line or to a depth approved by the Dis-trict Supervisor. The lessee shall verifythat the location has been cleared ofall obstructions in accordance with§ 250.704 of this part. The requirementfor removing subsea wellheads or otherobstructions and for verifying locationclearance may be reduced or elimi-nated when, in the opinion of the Dis-trict Supervisor, the wellheads or otherobstructions would not constitute ahazard to other users of the seafloor orother legitimate uses of the area.

(j) Requirements for permafrost areas.The following requirements shall beimplemented for permafrost areas:

(1) Fluid left in the hole adjacent topermafrost zones shall have a freezingpoint below the temperature of the per-mafrost and shall be treated to inhibitcorrosion.

(2) The cement used for cement plugsplaced across permafrost zones shall bedesigned to set before freezing and tohave a low heat of hydration.


§ 250.703 Temporary abandonment.(a) Any drilling well which is to be

temporarily abandoned shall meet therequirements for permanent abandon-ment (except for the provisions in§§ 250.702 (f) and (i), and 250.704) and thefollowing:

(1) A bridge plug or a cement plug atleast 100 feet in length shall be set atthe base of the deepest casing stringunless the casing string has been ce-mented and has not been drilled out. Ifa cement plug is set, it is not necessaryfor the cement plug to extend belowthe casing shoe into the open hole.

(2) A retrievable or a permanent-typebridge plug or a cement plug at least100 feet in length, shall be set in thecasing within the first 200 feet belowthe mud line.

(b) Subsea wellheads, casing stubs, orother obstructions above the seafloorremaining after temporary abandon-ment will be protected in such a man-ner as to allow commercial fisheriesgear to pass over the structure withoutdamage to the structure or fishinggear. Depending on water depth, natureand height of obstruction above theseafloor, and the types and periods offishing activity in the area, the Dis-

trict Supervisor may waive this re-quirement.

(c) In order to maintain the tempo-rarily abandoned status of a well, thelessee shall provide, within 1 year ofthe original temporary abandonmentand at successive 1-year intervalsthereafter, an annual report describingplans for reentry to complete or perma-nently abandon the well.

(d) Identification and reporting ofsubsea wellheads, casing stubs, orother obstructions extending above themud line will be accomplished in ac-cordance with the requirements of theU.S. Coast Guard.


§ 250.704 Site clearance verification.

(a) The lessees shall verify site clear-ance after abandonment by one ormore of the following methods as ap-proved by the District Supervisor:

(1) Drag a trawl in two directionsacross the location,

(2) Perform a diver search around thewellbore,

(3) Scan across the location with aside-scan or on-bottom scanning sonar,or

(4) Use other methods based on par-ticular site conditions.

(b) Certification that the area wascleared of all obstructions, the date thework was performed, the extent of thearea searched around the location, andthe search method utilized shall besubmitted on Form MMS–124.

[53 FR 10690, Apr. 1, 1988, as amended at 58FR 49928, Sept. 24, 1993. Redesignated at 63FR 29479, May 29, 1998]

Subpart H—Oil and GasProduction Safety Systems

§ 250.800 General requirements.

Production safety equipment shall bedesigned, installed, used, maintained,and tested in a manner to assure thesafety and protection of the human,marine, and coastal environments. Pro-duction safety systems operated in sub-freezing climates shall utilize equip-ment and procedures selected with con-sideration of floating ice, icing, and


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other extreme environmental condi-tions that may occur in the area. Pro-duction shall not commence until theproduction safety system has been ap-proved and a preproduction inspectionhas been requested by the lessee.

§ 250.801 Subsurface safety devices.

(a) General. All tubing installationsopen to hydrocarbon-bearing zonesshall be equipped with subsurface safe-ty devices that will shut off the flowfrom the well in the event of an emer-gency unless, after application and jus-tification, the well is determined bythe District Supervisor to be incapableof natural flowing. These devices mayconsist of a surface-controlled sub-surface safety valve (SSSV), a sub-surface-controlled SSSV, an injectionvalve, a tubing plug, or a tubing/annu-lar subsurface safety device, and anyassociated safety valve lock or landingnipple.

(b) Specifications for SSSV’s. Surface-controlled and subsurface-controlledSSSV’s and safety valve locks andlanding nipples installed in the OCSshall conform to the requirements in§ 250.806 of this part.

(c) Surface-controlled SSSV’s. All tub-ing installations open to a hydro-carbon-bearing zone which is capable ofnatural flow shall be equipped with asurface-controlled SSSV, except asspecified in paragraphs (d), (f), and (g)of this section. The surface controlsmay be located on the site or a remotelocation. Wells not previously equippedwith a surface-controlled SSSV andwells in which a surface-controlledSSSV has been replaced with a sub-surface-controlled SSSV in accordancewith paragraph (d)(2) of this sectionshall be equipped with a surface-con-trolled SSSV when the tubing is firstremoved and reinstalled.

(d) Subsurface-controlled SSSV’s. Wellsmay be equipped with subsurface-con-trolled SSSV’s in lieu of a surface-con-trolled SSSV provided the lessee dem-onstrates to the District Supervisor’ssatisfaction that one of the followingcriteria are met:

(1) Wells not previously equippedwith surface-controlled SSSV’s shall beso equipped when the tubing is first re-moved and reinstalled,

(2) The subsurface-controlled SSSV isinstalled in wells completed from a sin-gle-well or multiwell satellite caissonor seafloor completions, or

(3) The subsurface-controlled SSSV isinstalled in wells with a surface-con-trolled SSSV that has become inoper-able and cannot be repaired without re-moval and reinstallation of the tubing.

(e) Design, installation, and operationof SSSV’s. The SSSV’s shall be de-signed, installed, operated, and main-tained to ensure reliable operation.

(1) The device shall be installed at adepth of 100 feet or more below theseafloor within 2 days after productionis established. When warranted by con-ditions such as permafrost, unstablebottom conditions, hydrate formation,or paraffins, an alternate setting depthof the subsurface safety device may beapproved by the District Supervisor.

(2) Until a subsurface safety device isinstalled, the well shall be attended inthe immediate vicinity so that emer-gency actions may be taken while thewell is open to flow. During testing andinspection procedures, the well shallnot be left unattended while open toproduction unless a properly operatingsubsurface-safety device has been in-stalled in the well.

(3) The well shall not be open to flowwhile the subsurface safety device isremoved, except when flowing of thewell is necessary for a particular oper-ation such as cutting paraffin, bailingsand, or similar operations.

(4) All SSSV’s shall be inspected, in-stalled, maintained, and tested in ac-cordance with American Petroleum In-stitute Recommended Practice 14B,Recommended Practice for Design, In-stallation, and Operation of SubsurfaceSafety Valve Systems.

(f) Subsurface safety devices in shut-inwells. New completions (perforated butnot placed on production) and comple-tions shut in for a period of 6 monthsshall be equipped with either (1) apump-through-type tubing plug; (2) asurface-controlled SSSV, provided thesurface control has been rendered inop-erative; or (3) an injection valve capa-ble of preventing backflow. The settingdepth of the subsurface safety deviceshall be approved by the District Su-pervisor on a case-by-case basis, when


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warranted by conditions such as per-mafrost, unstable bottom conditions,hydrate formations, and paraffins.

(g) Subsurface safety devices in injec-tion wells. A surface-controlled SSSV oran injection valve capable of pre-venting backflow shall be installed inall injection wells. This requirement isnot applicable if the District Super-visor concurs that the well is incapableof flowing. The lessee shall verify theno-flow condition of the well annually.

(h) Temporary removal for routine oper-ations. (1) Each wireline- or pumpdown-retrievable subsurface safety devicemay be removed, without further au-thorization or notice, for a routine op-eration which does not require the ap-proval of a Form MMS–124, Sundry No-tices and Reports on Wells, in § 250.601of this part for a period not to exceed15 days.

(2) The well shall be identified by asign on the wellhead stating that thesubsurface safety device has been re-moved. The removal of the subsurfacesafety device shall be noted in therecords as required in § 250.804(b) of thispart. If the master valve is open, atrained person shall be in the imme-diate vicinity of the well to attend thewell so that emergency actions may betaken, if necessary.

(3) A platform well shall be mon-itored, but a person need not remain inthe well-bay area continuously if themaster valve is closed. If the well is ona satellite structure, it must be at-tended or a pump-through plug in-stalled in the tubing at least 100 feetbelow the mud line and the mastervalve closed, unless otherwise approvedby the District Supervisor.

(4) The well shall not be allowed toflow while the subsurface safety deviceis removed, except when flowing thewell is necessary for that particular op-eration. The provisions of this para-graph are not applicable to the testingand inspection procedures in § 250.804 ofthis part.

(i) Additional safety equipment. Alltubing installations in which awireline- or pumpdown-retrievable sub-surface safety device is installed afterthe effective date of this subpart shallbe equipped with a landing nipple withflow couplings or other protectiveequipment above and below to provide

for the setting of the SSSV. The con-trol system for all surface-controlledSSSV’s shall be an integral part of theplatform Emergency Shutdown System(ESD). In addition to the activation ofthe ESD by manual action on the plat-form, the system may be activated bya signal from a remote location. Sur-face-controlled SSSV’s shall close inresponse to shut-in signals from theESD and in response to the fire loop orother fire detection devices.

(j) Emergency action. In the event ofan emergency, such as an impendingstorm, any well not equipped with asubsurface safety device and which iscapable of natural flow shall have thedevice properly installed as soon aspossible with due consideration beinggiven to personnel safety.

[53 FR 10690, Apr. 1, 1988, as amended at 54FR 50617, Dec. 8, 1989; 58 FR 49928, Sept. 24,1993. Redesignated and amended at 63 FR29479, 29485, May 29, 1998]

§ 250.802 Design, installation, and op-eration of surface production–safe-ty systems.

(a) General. All production facilities,including separators, treaters, com-pressors, headers, and flowlines shallbe designed, installed, and maintainedin a manner which provides for effi-ciency, safety of operation, and protec-tion of the environment.

(b) Platforms. All platform productionfacilities shall be protected with abasic and ancillary surface safety sys-tem designed, analyzed, installed, test-ed, and maintained in operating condi-tion in accordance with the provisionsof API RP 14C, Recommended Practicefor Analysis, Design, Installation andTesting of Basic Surface Safety Sys-tems for Offshore Production Plat-forms. If processing components are tobe utilized, other than those for whichSafety Analysis Checklists are in-cluded in API RP 14C, the analysistechnique and documentation specifiedtherein shall be utilized to determinethe effects and requirements of thesecomponents upon the safety system.Safety device requirements for pipe-lines are contained in § 250.1004 of thispart.

(c) Specification for surface safetyvalves (SSV) and underwater safetyvalves (USV). All wellhead SSV’s,


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USV’s, and their actuators which areinstalled in the OCS shall conform tothe requirements in § 250.806 of thispart.

(d) Use of SSV’s and USV’s. All SSV’sand USV’s shall be inspected, installed,maintained, and tested in accordancewith API RP 14H, Recommended Prac-tice for Use of Surface Safety Valvesand Underwater Safety Valves Off-shore. If any SSV or USV does not op-erate properly or if any fluid flow is ob-served during the leakage test, thevalve shall be repaired or replaced.

(e) Approval of safety-systems designand installation features. Prior to instal-lation, the lessee shall submit, in du-plicate for approval to the District Su-pervisor a production safety system ap-plication containing information rel-ative to design and installation fea-tures. Information concerning ap-proved design and installation featuresshall be maintained by the lessee atthe lessee’s offshore field office nearestthe OCS facility or other location con-veniently available to the District Su-pervisor. All approvals are subject tofield verifications. The applicationshall include the following:

(1) A schematic flow diagram show-ing tubing pressure, size, capacity, de-sign working pressure of separators,flare scrubbers, treaters, storage tanks,compressors, pipeline pumps, meteringdevices, and other hydrocarbon-han-dling vessels.

(2) A schematic flow diagram (APIRP 14C, Figure E1) and the relatedSafety Analysis Function Evaluationchart (API RP 14C, subsection 4.3c).

(3) A schematic piping diagram show-ing the size and maximum allowableworking pressures as determined in ac-cordance with API RP 14E, Design andInstallation of Offshore ProductionPlatform Piping Systems.

(4) Electrical system information in-cluding the following:

(i) A plan for each platform deck out-lining all hazardous areas classified ac-cording to API RP 500, RecommendedPractice for Classification of Locationsfor Electrical Installations at Petro-leum Facilities Classified as Class I,Division 1 and Division 2, or API RP505, Recommended Practice for Classi-fication of Locations for Electrical In-stallations at Petroleum Facilities

Classified as Class I, Zone 0, Zone 1,and Zone 2, and outlining areas inwhich potential ignition sources, otherthan electrical, are to be installed. Thearea outlined will include the followinginformation:

(A) All major production equipment,wells, and other significant hydro-carbon sources and a description of thetype of decking, ceiling, walls (e.g.,grating or solid) and firewalls; and

(B) Location of generators, controlrooms, panel boards, major cabling/conduit routes, and identification ofthe primary wiring method (e.g., typecable, conduit, or wire).

(ii) Elementary electrical schematicof any platform safety shut-down sys-tem with a functional legend.

(5) Certification that the design forthe mechanical and electrical systemsto be installed were approved by reg-istered professional engineers. Afterthese systems are installed, the lesseeshall submit a statement to the Dis-trict Supervisor certifying that new in-stallations conform to the approved de-signs of this subpart.

(6) The design and schematics of theinstallation and maintenance of allfire- and gas-detection systems shallinclude the following:

(i) Type, location, and number of de-tection sensors;

(ii) Type and kind of alarms, includ-ing emergency equipment to be acti-vated;

(iii) Method used for detection;(iv) Method and frequency of calibra-

tion; and(v) A functional block diagram of the

detection system, including the elec-tric power supply.

[53 FR 10690, Apr. 1, 1988, as amended at 61FR 60024, Nov. 26, 1996. Redesignated andamended at 63 FR 29479, 29485, May 29, 1998; 65FR 219, Jan. 4, 2000]

§ 250.803 Additional production systemrequirements.

(a) General. Lessees shall complywith the following production safetysystem requirements (some of whichare in addition to those contained inAPI RP 14C), incorporated by referencein § 250.802(b) of this part.

(b) Design, installation, and operationof additional production systems. (1) Pres-sure and fired vessels. Pressure and fired


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vessels shall be designed, fabricated,code stamped, and maintained in ac-cordance with applicable provisions ofsections I, IV, and VIII of the ASMEBoiler and Pressure Vessel Code. Allexisting uncoded vessels in use must bejustified and approval for continueduse obtained from the District Super-visor no later than August 29, 1988.

(i) Pressure relief valves shall be de-signed, installed, and maintained in ac-cordance with applicable provisions ofsections I, IV, and VIII of the ASMEBoiler and Pressure Vessel Code. Therelief valves shall conform to thevalve-sizing and pressure-relieving re-quirements specified in these docu-ments; however, the relief valves, ex-cept completely redundant reliefvalves, shall be set no higher than themaximum-allowable working pressureof the vessel. All relief valves and ventsshall be piped in such a way as to pre-vent fluid from striking personnel orignition sources.

(ii) Steam generators operating atless than 15 pounds per square inchgauge (psig) shall be equipped with alevel safety low (LSL) sensor whichwill shut off the fuel supply when thewater level drops below the minimumsafe level. Steam generators operatingat greater than 15 psig require, in addi-tion to an LSL, a water-feeding devicewhich will automatically control thewater level.

(iii) The lessee shall use pressure re-corders to establish the new operatingpressure ranges of pressure vessels atany time when there is a change in op-erating pressures that requires newsettings for the high–pressure shut–insensor and/or the low–pressure shut–insensor as provided herein. The pres-sure-recorder charts used to determinecurrent operating pressure ranges shallbe maintained at the lessee’s field of-fice nearest the OCS facility or atother locations conveniently availableto the District Supervisor. The high-pressure shut-in sensor shall be set nohigher than 15 percent or 5 psi, which-ever is greater, above the highest oper-ating pressure of the vessel. This set-ting shall also be set sufficiently below(5 percent or 5 psi, whichever is great-er) the relief valve’s set pressure to as-sure that the pressure source is shut inbefore the relief valve activates. The

low-pressure shut-in sensor shall acti-vate no lower than 15 percent or 5 psi,whichever is greater, below the lowestpressure in the operating range. Theactivation of low-pressure sensors onpressure vessels which operate at lessthan 5 psi shall be approved by the Dis-trict Supervisor on a case-by-casebasis.

(2) Flowlines. (i) Flowlines from wellsshall be equipped with high- and low-pressure shut-in sensors located in ac-cordance with section A.1 and FigureA1 of API RP 14C. The lessee shall usepressure recorders to establish the newoperating pressure ranges of flowlinesat any time when there is a significantchange in operating pressures. Themost recent pressure-recorder chartsused to determine operating pressureranges shall be maintained at the les-see’s field office nearest the OCS facil-ity or at other locations convenientlyavailable to the District Supervisor.The high-pressure shut-in sensor(s)shall be set no higher than 15 percentor 5 psi, whichever is greater, above thehighest operating pressure of the line.But in all cases, it shall be set suffi-ciently below the maximum shut-inwellhead pressure or the gas-lift supplypressure to assure actuation of theSSV. The low-pressure shut-in sen-sor(s) shall be set no lower than 15 per-cent or 5 psi, whichever is greater,below the lowest operating pressure ofthe line in which it is installed.

(ii) If a well flows directly to thepipeline before separation, the flowlineand valves from the well located up-stream of and including the headerinlet valve(s) shall have a workingpressure equal to or greater than themaximum shut-in pressure of the wellunless the flowline is protected by oneof the following:

(A) A relief valve which vents intothe platform flare scrubber or someother location approved by the DistrictSupervisor. The platform flare scrubbershall be designed to handle, withoutliquid-hydrocarbon carryover to theflare, the maximum-anticipated flow ofliquid hydrocarbons which may be re-lieved to the vessel.

(B) Two SSV’s with independenthigh-pressure sensors installed withadequate volume upstream of anyblock valve to allow sufficient time for


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the valve(s) to close before exceedingthe maximum allowable working pres-sure.

(3) Safety sensors. All shutdown de-vices, valves, and pressure sensors shallfunction in a manual reset mode. Sen-sors with integral automatic resetshall be equipped with an appropriatedevice to override the automatic resetmode. All pressure sensors shall beequipped to permit testing with an ex-ternal pressure source.

(4) ESD. The ESD shall conform tothe requirements of Appendix C, sec-tion C1, of API RP 14C, and the fol-lowing:

(i) The manually operated ESDvalve(s) shall be quick-opening andnonrestricted to enable the rapid actu-ation of the shutdown system. OnlyESD stations at the boat landing mayutilize a loop of breakable synthetictubing in lieu of a valve.

(ii) Closure of the SSV shall not ex-ceed 45 seconds after automatic detec-tion of an abnormal condition or actu-ation of an ESD. The surface-con-trolled SSSV shall close in not morethan 2 minutes after the shut-in signalhas closed the SSV. Design-delayedclosure time greater than 2 minutesshall be justified by the lessee based onthe individual well’s mechanical/pro-duction characteristics and be ap-proved by the District Supervisor.

(iii) A schematic of the ESD whichindicates the control functions of allsafety devices for the platforms shallbe maintained by the lessee on theplatform or at the lessee’s field officenearest the OCS facility or other loca-tion conveniently available to the Dis-trict Supervisor.

(5) Engines. (i) Engine exhaust. Engineexhausts shall be equipped to complywith the insulation and personnel pro-tection requirements of API RP 14C,section 4.2c(4). Exhaust piping fromdiesel engines shall be equipped withspark arresters.

(ii) Diesel engine air intake. No laterthan May 31, 1989, diesel engine air in-takes shall be equipped with a deviceto shutdown the diesel engine in theevent of runaway. Diesel engines whichare continuously attended shall beequipped with either remote operatedmanual or automatic shutdown de-vices. Diesel engines which are not con-

tinuously attended shall be equippedwith automatic shutdown devices.

(6) Glycol dehydration units. A pres-sure relief system or an adequate ventshall be installed on the glycol regen-erator (reboiler) which will preventoverpressurization. The discharge ofthe relief valve shall be vented in anonhazardous manner.

(7) Gas compressors. Compressor in-stallations shall be equipped with thefollowing protective equipment as re-quired in API RP 14C, sections A4 andA8.

(i) A Pressure Safety High (PSH), aPressure Safety Low (PSL), a PressureSafety Valve (PSV), and a Level SafetyHigh (LSH), and an LSL to protecteach interstage and suction scrubber.

(ii) A Temperature Safety High(TSH) on each compressor dischargecylinder.

(iii) The PSH and PSL shut-in sen-sors and LSH shut-in controls pro-tecting compressor suction andinterstage scrubbers shall be designedto actuate automatic shutdown valves(SDV) located in each compressor suc-tion and fuel gas line so that the com-pressor unit and the associated vesselscan be isolated from all input sources.All automatic SDV’s installed in com-pressor suction and fuel gas pipingshall also be actuated by the shutdownof the prime mover. Unless otherwiseapproved by the District Supervisor,gas-well gas affected by the closure ofthe automatic SDV on a compressorsuction shall be diverted to the pipe-line or shut in at the wellhead.

(iv) A blowdown valve is required onthe discharge line of all compressor in-stallations of 1,000 horsepower (746kilowatts) or greater.

(8) Firefighting systems. Firefightingsystems for both open and totally en-closed platforms installed for extremeweather conditions or other reasonsshall conform to subsection 5.2, Fire-water systems, of API RP 14G, FirePrevention and Control Open Type Off-shore Production Platforms, and shallrequire approval of the District Super-visor. The following additional require-ments shall apply for both open- andclosed-production platforms:

(i) A firewater system consisting ofrigid pipe with firehose stations or


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30 CFR Ch. II (7–1–01 Edition)§ 250.803

fixed firewater monitors shall be in-stalled. The firewater system shall beinstalled to provide needed protectionin all areas where production-handlingequipment is located. A fixedwaterspray system shall be installed inenclosed well-bay areas where hydro-carbon vapors may accumulate.

(ii) Fuel or power for firewater pumpdrivers shall be available for at least 30minutes of run time during a platformshut-in. If necessary, an alternate fuelor power supply shall be installed toprovide for this pump-operating timeunless an alternate firefighting systemhas been approved by the District Su-pervisor.

(iii) A firefighting system usingchemicals may be used in lieu of awater system if the District Supervisordetermines that the use of a chemicalsystem provides equivalent fire-protec-tion control.

(iv) A diagram of the firefighting sys-tem showing the location of all fire-fighting equipment shall be posted in aprominent place on the facility orstructure.

(v) For operations in subfreezing cli-mates, the lessee shall furnish evidenceto the District Supervisor that the fire-fighting system is suitable for the con-ditions.

(9) Fire- and gas-detection system. (i)Fire (flame, heat, or smoke) sensorsshall be installed in all enclosed classi-fied areas. Gas sensors shall be in-stalled in all inadequately ventilated,enclosed classified areas. Adequateventilation is defined as ventilationwhich is sufficient to prevent accumu-lation of significant quantities ofvapor-air mixture in concentrationsover 25 percent of the lower explosivelimit (LEL). One approved method ofproviding adequate ventilation is achange of air volume each 5 minutes or1 cubic foot of air-volume flow perminute per square foot of solid floorarea, whichever is greater. Enclosedareas (e.g., buildings, living quarters,or doghouses) are defined as thoseareas confined on more than four oftheir six possible sides by walls, floors,or ceilings more restrictive to air flowthan grating or fixed open louvers andof sufficient size to all entry of per-sonnel. A classified area is any areaclassified Class I, Group D, Division 1

or 2, following the guidelines of API RP500, or any area classified Class I, Zone0, Zone 1, or Zone 2, following theguidelines of API RP 505.

(ii) All detection systems shall be ca-pable of continuous monitoring. Fire-detection systems and portions of com-bustible gas-detection systems relatedto the higher gas concentration levelsshall be of the manual-reset type. Com-bustible gas-detection systems relatedto the lower gas-concentration levelmay be of the automatic-reset type.

(iii) A fuel-gas odorant or an auto-matic gas-detection and alarm systemis required in enclosed, continuouslymanned areas of the facility which areprovided with fuel gas. Living quartersand doghouses not containing a gassource and not located in a classifiedarea do not require a gas detection sys-tem.

(iv) The District Supervisor may re-quire the installation and maintenanceof a gas detector or alarm in any po-tentially hazardous area.

(v) Fire- and gas-detection systemsshall be an approved type, designed andinstalled in accordance with API RP14C, API RP 14G, and API RP 14F, De-sign and Installation of Electrical Sys-tems for Offshore Production Plat-forms.

(10) Electrical equipment. Electricalequipment and systems shall be de-signed, installed, and maintained in ac-cordance with the requirements in§ 250.403 of this part.

(11) Erosion. A program of erosioncontrol shall be in effect for wells orfields having a history of sand produc-tion. The erosion-control program mayinclude sand probes, X-ray, ultrasonic,or other satisfactory monitoring meth-ods. Records by lease, indicating thewells which have erosion-control pro-grams in effect and the results of theprograms, shall be maintained by thelessee for a period of 2 years and shallbe made available to MMS upon re-quest.

(c) General platform operations. (1)Surface or subsurface safety devicesshall not be bypassed or blocked out ofservice unless they are temporarily outof service for startup, maintenance, ortesting procedures. Only the minimumnumber of safety devices shall be takenout of service. Personnel shall monitor


335


the bypassed or blocked-out functionsuntil the safety devices are placed backin service. Any surface or subsurfacesafety device which is temporarily outof service shall be flagged.

(2) When wells are disconnected fromproducing facilities and blind flanged,equipped with a tubing plug, or themaster valves have been locked closed,compliance is not required with theprovisions of API RP 14C or this regu-lation concerning the following:

(i) Automatic fail-close SSV’s onwellhead assemblies, and

(ii) The PSH and PSL shut-in sensorsin flowlines from wells.

(3) When pressure or atmospheric ves-sels are isolated from production facili-ties (e.g., inlet valve locked closed orinlet blind-flanged) and are to remainisolated for an extended period of time,safety device compliance with API RP14C or this subpart is not required.

(4) All open-ended lines connected toproducing facilities and wells shall beplugged or blind-flanged, except thoselines designed to be open-ended such asflare or vent lines.

(d) Welding and burning practices andprocedures. All welding, burning, andhot-tapping activities shall be con-ducted according to the specific re-quirements in § 250.402 of this part.

[53 FR 10690, Apr. 1, 1988; 53 FR 12227, Apr. 13,1988, as amended at 55 FR 47753, Nov. 15, 1990;61 FR 60025, Nov. 26, 1996. Redesignated andamended at 63 FR 29479, 29485, May 29, 1998; 65FR 219, Jan. 4, 2000]

§ 250.804 Production safety-systemtesting and records.

(a) Inspection and testing. The safety-system devices shall be successfully in-spected and tested by the lessee at theinterval specified below or more fre-quently if operating conditions war-rant. Testing shall be in accordancewith API RP 14C, Appendix D, and thefollowing:

(1) Testing requirements for sub-surface safety devices are as follows:

(i) Each surface-controlled sub-surface safety device installed in awell, including such devices in shut-inand injection wells, shall be tested inplace for proper operation when in-stalled or reinstalled and thereafter atintervals not exceeding 6 months. Ifthe device does not operate properly, or

if a liquid leakage rate in excess of 200cubic centimeters per minute or a gasleakage rate in excess of 5 cubic feetper minute is observed, the device shallbe removed, repaired and reinstalled,or replaced. Testing shall be in accord-ance with API RP 14B to ensure properoperation.

(ii) Each subsurface-controlled SSSVinstalled in a well shall be removed, in-spected, and repaired or adjusted, asnecessary, and reinstalled or replacedat intervals not exceeding 6 months forthose valves not installed in a landingnipple and 12 months for those valvesinstalled in a landing nipple.

(iii) Each tubing plug installed in awell shall be inspected for leakage byopening the well to possible flow at in-tervals not exceeding 6 months. If a liq-uid leakage rate in excess of 200 cubiccentimeters per minute or a gas leak-age rate in excess of 5 cubic feet perminute is observed, the device shall beremoved, repaired and reinstalled, orreplaced. An additional tubing plugmay be installed in lieu of removal.

(iv) Injection valves shall be tested inthe manner as outlined for testing tub-ing plugs in paragraph (a)(1)(iii) of thissection. Leakage rates outlined inparagraph (a)(1)(iii) of this sectionshall apply.

(2) All PSV’s shall be tested for oper-ation at least once every 12 months.These valves shall be either bench-test-ed or equipped to permit testing withan external pressure source. Weighteddisk vent valves used as PSV’s on at-mospheric tanks may be disassembledand inspected in lieu of function test-ing.

(3) The following safety devices shallbe tested at least once each calendarmonth, but at no time shall more than6 weeks elapse between tests:

(i) All PSH and PSL,(ii) All LSH and LSL controls,(iii) All automatic inlet SDV’s which

are actuated by a sensor on a vessel orcompressor, and

(iv) All SDV’s in liquid dischargelines and actuated by vessel low-levelsensors.

(4) All SSV’s and USV’s shall be test-ed for operation and for leakage atleast once each calendar month, but atno time shall more than 6 weeks elapsebetween tests. The testing shall be in


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30 CFR Ch. II (7–1–01 Edition)§ 250.805

accordance with the test proceduresspecified in API RP 14H. If the SSV orUSV does not operate properly or ifany fluid flow is observed during theleakage test, the valve shall be re-paired or replaced.

(5) All flowline Flow Safety Valves(FSV) shall be checked for leakage atleast once each calendar month, but atno time shall more than 6 weeks elapsebetween tests. The FSV’s shall be test-ed for leakage in accordance with thetest procedure specified in API RP 14C,appendix D, section D4, table D2, sub-section D. If the leakage measured ex-ceeds a liquid flow of 200 cubic centi-meters per minute or a gas flow of 5cubic feet per minute, the FSV’s shallbe repaired or replaced.

(6) The TSH shutdown controls in-stalled on compressor installationswhich can be nondestructively testedshall be tested every 6 months and re-paired or replaced as necessary.

(7) All pumps for firewater systemsshall be inspected and operated weekly.

(8) All fire- (flame, heat, or smoke)detection systems shall be tested foroperation and recalibrated every 3months provided that testing can beperformed in a nondestructive manner.Open flame or devices operating attemperatures which could ignite amethane-air mixture shall not be used.All combustible gas-detection systemsshall be calibrated every 3 months.

(9) All TSH devices shall be tested atleast once every 12 months, excludingthose addressed in paragraph (a)(6) ofthis section and those which would bedestroyed by testing. Burner safety lowand flow safety low devices shall alsobe tested at least once every 12months.

(10) The ESD shall be tested for oper-ation at least once each calendarmonth, but at no time shall more than6 weeks elapse between tests. The testshall be conducted by alternating ESDstations monthly to close at least onewellhead SSV and verify a surface-con-trolled SSSV closure for that well asindicated by control circuitry actu-ation.

(11) Prior to the commencement ofproduction, the lessee shall notify theDistrict Supervisor when the lessee isready to conduct a preproduction testand inspection of the integrated safety

system. The lessee shall also notify theDistrict Supervisor upon commence-ment of production in order that acomplete inspection may be conducted.

(b) Records. The lessee shall maintainrecords for a period of 2 years for eachsubsurface and surface safety device in-stalled. These records shall be main-tained by the lessee at the lessee’s fieldoffice nearest the OCS facility or otherlocations conveniently available to theDistrict Supervisor. These recordsshall be available for review by a rep-resentative of MMS. The records shallshow the present status and history ofeach device, including dates and detailsof installation, removal, inspection,testing, repairing, adjustments, and re-installation.

[53 FR 10690, Apr. 1, 1988, as amended at 55FR 47753, Nov. 15, 1990; 62 FR 5331, Feb. 5,1997. Redesignated at 63 FR 29479, May 29,1998, as amended at 65 FR 35824, June 6, 2000]

§ 250.805 Safety device training.

Personnel installing, inspecting, test-ing, and maintaining these safety de-vices and personnel operating the pro-duction platforms shall be qualified inaccordance with subpart O.

§ 250.806 Safety and pollution preven-tion equipment quality assurancerequirements.

(a) General requirements. (1) Except asprovided in paragraph (b)(1) of this sec-tion, you may install only certifiedsafety and pollution prevention equip-ment (SPPE) in wells located on theOCS. SPPE includes the following:

(i) Surface safety valves (SSV) andactuators;

(ii) Underwater safety valves (USV)and actuators; and

(iii) Subsurface safety valves (SSSV)and associated safety valve locks andlanding nipples.

(2) Certified SPPE is equipment themanufacturer certifies as manufac-tured under a quality assurance pro-gram MMS recognizes. MMS considersall other SPPE as noncertified. MMSrecognizes two quality assurance pro-grams:

(i) ANSI/ASME SPPE–1, Quality As-surance and Certification of Safety andPollution-Prevention Equipment Usedin Offshore Oil and Gas Operations; and


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(ii) API Spec Q1, Specification forQuality Programs.

(3) All SSV’s and USV’s must meetthe technical specifications of APISpec 6A and 6AV1. All SSSVs mustmeet the technical specifications ofAPI Specification 14A.

(4) For information on all standardsmentioned in this section, see § 250.198.

(b) Use of noncertified SPPE. (1) BeforeApril 1, 1998, you may continue to useand install noncertified SPPE if it wasin your inventory as of April 1, 1988,and was included in a list of noncer-tified SPPE submitted to MMS prior toAugust 29, 1988.

(2) On or after April 1, 1998:(i) You may not install additional

noncertified SPPE; and(ii) When noncertified SPPE that is

already in service requires offsite re-pair, remanufacturing, or hot worksuch as welding, you must replace itwith certified SPPE.

(c) Recognizing other quality assuranceprograms. The MMS will consider recog-nizing other quality assurance pro-grams covering the manufacture ofSPPE. If you want MMS to evaluateother quality assurance programs, sub-mit relevant information about theprogram and reasons for recognition byMMS to the Chief, Engineering and Op-erations Division; Minerals Manage-ment Service; Mail Stop 4700; 381 EldenStreet; Herndon, Virginia 20170–4817.

[62 FR 42671, Aug. 8, 1997. Redesignated at 63FR 29479, May 29, 1998, as amended at 63 FR37068, July 9, 1998; 65 FR 76935, Dec. 8, 2000]

§ 250.807 Hydrogen sulfide.Production operations in zones

known to contain hydrogen sulfide(H2S) or in zones where the presence ofH2S is unknown, as defined in § 250.417of this part, shall be conducted in ac-cordance with that section and otherrelevant requirements of subpart H,Production Safety Systems.


Subpart I—Platforms andStructures

§ 250.900 General requirements.(a) The lessee shall design, fabricate,

install, use, inspect, and maintain all

platforms and structures (platforms)on the Outer Continental Shelf (OCS)to assure their structural integrity forthe safe conduct of drilling, workover,and production operations, consideringthe specific environmental conditionsat the platform location.

(b) All new fixed or bottom-foundedplatforms (i.e., platforms or otherstructures, e.g., single-well caissons,artificial islands), shall be designed,fabricated, installed, inspected, andmaintained in accordance with all therequirements of this section and§§ 250.901 and 250.904 through 250.914 ofthis subpart. Applications submittedpursuant to § 250.901 shall require theapproval by the Regional Supervisorprior to platform installation.

(c) All new platforms which meet anyof the conditions listed below shall besubject to the Platform VerificationProgram and shall be designed, fab-ricated, and installed in accordancewith the requirements of §§ 250.901through 250.914 of this part.

(1) Platforms installed in waterdepths exceeding 400 feet,

(2) Platforms having natural periodsin excess of 3 seconds,

(3) Platforms installed in areas of un-stable bottom conditions,

(4) Platforms having configurationsand designs which have not previouslybeen used or proven for use in the area,or

(5) Platforms installed in seismicallyactive areas.

(d) Major modification to any plat-form shall be subject to the require-ments of this subpart and shall requirethe approval of the Regional Super-visor. Major modification means anystructural changes which materiallyalter the approved plan or causes amajor deviation from approved oper-ations.

(e)(1) Major repairs of damage to anyplatform shall require the prior ap-proval of the Regional Supervisor.Major repairs of damage means correc-tive operations involving structuralmembers affecting the structural in-tegrity of a portion or all of the plat-form.

(2) Under emergency conditions, re-pairs to primary structural elementsmay be made to restore an existing


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permitted condition without prior ap-proval. The Regional Supervisor shallbe notified within 24 hours of the dam-age that occurred and repairs that weremade. The Regional Supervisor’s ap-proval for repairs shall be obtained.

(f) The requirements for an applica-tion for approval for the reuse or con-version of the use of an existing fixedor mobile platforms shall be deter-mined on a case-by-case basis. An ap-plication shall be submitted to the Re-gional Supervisor for approval andshall include location, intended use,and demonstrate the adequacy of thedesign and structural condition of theplatform.

(g) In addition to the requirements ofthis subpart, platform design, fabrica-tion, and installation shall conform toAPI RP 2A, Recommended Practice ForPlanning, Designing, And ConstructingFixed Offshore Platforms, or AmericanConcrete Institute (ACI) 357R, Guidefor the Design and Construction ofFixed Offshore Concrete Structures, asappropriate. Alternative codes or rulesmay be utilized with approval of theRegional Supervisor. The requirementscontained in these documents (API RP2A and ACI 357R) are incorporatedherein insofar as they do not conflictwith other provisions of this subpart.

[53 FR 10690, Apr. 1, 1988. Redesignated andamended at 63 FR 29479, 29485, May 29, 1998; 64FR 9065, Feb. 24, 1999]

§ 250.901 Application for approval.(a) All applications under the provi-

sions of this subpart shall be submittedto the Regional Supervisor for ap-proval. All significant changes ormodifications to approved applicationsshall be submitted to the Regional Su-pervisor for approval.

(b) Applications for all new platformsor major modifications shall be sub-mitted in triplicate and shall containthe following information:

(1) General platform information in-cluding the following:

(i) The platform designation, leasenumber, area name, and block number;

(ii) Longitude and latitude coordi-nates, Universal Transverse Mercatorgrid-system coordinates, state planecoordinates in the Lambert or Trans-verse Mercator Projection system, anda plat drawn to a scale of 1 inch = 2,000

feet showing surface location of theplatform and distance from the nearestblock lines;

(iii) Drawings, plats, front and sideelevations of the entire platform, andplan views that clearly illustrate es-sential parts, i.e., number and locationof well slots, design loadings of eachdeck, water depth, nominal size andthickness of all primary load-bearingjacket and deck structural members,and nominal size, makeup, thickness,and design penetration of piling;

(iv) Corrosion protection or dura-bility details which consist of the cor-rosion-protection method; expectedlife; and durability criteria for the sub-merged, splash, and atmospheric zones;and

(v) In the Alaska OCS Region, thefollowing additional information shallbe submitted:

(A) Slope protection and berm ele-vation for manmade islands,

(B) Wall thickness with size andplacement of major steel reinforcementfor concrete-gravity structures,

(C) Shell thickness with size and lo-cation of major reinforcement mem-bers for steel-gravity structures, and

(D) A plan for periodic inspections ofthe installed platforms in accordancewith § 250.912 of this part.

(2) A summary of environmentaldata, as addressed in § 250.904 of thispart, which has a bearing on the plat-form’s design, installation, and oper-ation, e.g., wave heights and periods,current, vertical distribution of windand gust velocities, water depth, stormand astronomical tide data, marinegrowth, snow and ice effects, and airand sea temperatures;

(3) Foundation information includingthe following:

(i) A geotechnical investigation re-port containing a brief summary of themajor strata encountered at the loca-tion by bore holes presented in tabularform, a detailed subsurface profile il-lustrating results of field and labora-tory testing, a listing of field and lab-oratory investigations and tests with abasic summary of resultant determina-tions, the identification of propertiesand conditions of the seabed and thesubsoil, and the identification of anymanmade hazards or obstructions;


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(ii) A description of the effect of theenvironmental and functional loads onthe foundation;

(iii) A determination, with sup-porting information, of the suscepti-bility of the area to soil movementand, if susceptible, an analysis of slopeand soil stability;

(iv) A summary of the foundation de-sign criteria as specified in § 250.909 ofthis part; and

(v) A summary of the seafloor surveyresults specified in § 250.909(b)(2) of thispart.

(4) Structural information includingthe following:

(i) The design life of the platform andthe basis for such determination.

(ii) A summary description of the de-sign load conditions and design loadcombinations, taking into consider-ation the worst environmental andoperational conditions anticipated overthe service life of the platform.

(iii) A listing and description of theappropriate material specifications.

(iv) A description of the design meth-odologies, e.g., elastic, inelastic, andultimate strength, used in design of theplatform.

(v) A summary of pertinent derivedfactors of safety against failure formajor structural members, e.g., unitycheck ratios exceeding 0.85 for steel-jacket platform members, indicated on‘‘line’’ sketches of jacket sections.

(vi)(A) In the Alaska, Atlantic, andPacific OCS Regions, a summary of thefatigue analysis as specified in §§ 250.905through 250.909 of this part. The spe-cific requirements for a fatigue anal-ysis shall be determined by the Re-gional Supervisor on a case-by-casebasis to determine the adequacy of thedesign and to assure the structural in-tegrity of the platform.

(B) In the Gulf of Mexico OCS Re-gion, a summary of the fatigue anal-ysis as specified in §§ 250.905 through250.909 of this part. A fatigue analysisshall be performed for each steel tem-plate, pile-supported platform withnatural periods greater than 3 seconds,and for each platform to be fabricatedof high-strength steel (i.e., over 50thousand pounds per square inch min-imum yield) where components of high-strength steel are subjected to cyclicloading. The specific requirements for

a fatigue analysis for other platformsshall be determined by the RegionalSupervisor on a case-by-case basis todetermine adequacy of the design andto assure the structural integrity ofthe platform.

(c) The information shall be sub-mitted with or subsequent to the sub-mittal of an Exploration Plan or Devel-opment and Production Plan. Addi-tional detailed data and informationmay be required by the Regional Su-pervisor when needed to determine theadequacy of the design.

(d) The lessee shall have detailedstructural plans as called for in para-graph (b)(1)(iii) of this section andspecifications for new platforms orother structures and major modifica-tions certified by a registered profes-sional structural engineer or civil engi-neer specializing in structural design.The lessee shall also sign, date, andsubmit the following certification: Les-see certifies that the design of thestructure/modification has been cer-tified by a registered professionalstructural or a civil engineer special-izing in structural design, and thestructure/modification will be fab-ricated, installed, and maintained asdescribed in the application and anyapproved modification thereto. Cer-tified design and as built plans andspecifications will be on file at———.

(e) The lessee shall notify the Re-gional Supervisor at least 1 week priorto transporting the platform to the in-stallation site.

[53 FR 10690, Apr. 1, 1988. Redesignated andamended at 63 FR 29479, 29485, 29486, May 29,1998; 64 FR 9065, Feb. 24, 1999]

§ 250.902 Platform Verification Pro-gram requirements.

(a) Requirements. These requirementsapply to the design, fabrication, and in-stallation of new, fixed, bottom-found-ed, pile-supported, or concrete-gravityplatforms. The applicability of theserequirements to other types of plat-forms shall be determined by the MMSon a case-by-case basis. For all newplatforms or major modificationswhich meet any of the conditions con-tained in § 250.900(c) of this part, thelessee shall submit the design, fabrica-tion, and installation verification plansto the Regional Supervisor for approval


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in accordance with paragraph (b) ofthis section. The design plan shall besubmitted with or subsequent to thesubmittal of an Exploration Plan orDevelopment and Production Plan. Thefabrication and installation plans shallbe submitted and approval obtained be-fore such operations are initiated.

(b) Verification plan requirements. (1)General plan requirements. Eachverification plan shall be submitted intriplicate and include the following:

(i) A nomination of a CertifiedVerification Agent (CVA) who shallconduct specified reviews in accord-ance with § 250.903 of this part,

(ii) The CVA qualification statementconsisting of the following:

(A) Previous experience in third-party verification or experience in thedesign, fabrication, and/or installationof offshore oil and gas platforms, man-made islands, or other marine struc-tures;

(B) Technical capabilities of the indi-vidual or the primary staff to be asso-ciated with the CVA functions for thespecific project;

(C) Size and type of organization orcorporation;

(D) In-house availability of, or accessto, appropriate technology, i.e., com-puter programs and hardware and test-ing materials and equipment;

(E) Ability to perform the CVA func-tions for the specific project consid-ering current commitments; and

(F) Previous experience with MMSrequirements and procedures.

(iii) The level of work to be per-formed by the CVA, and

(iv) A list of documents to be fur-nished to the CVA.

(2) Design verification plan require-ments. The design plan shall also in-clude the following:

(i) All design documentation speci-fied in § 250.901(b) of this part, and

(ii) Abstracts of the computer pro-grams used in the design process.

(3) Fabrication verification plan re-quirements. The fabrication plan shallalso include fabrication drawings andmaterial specifications for artificial is-land structures, major members ofconcrete- and steel-gravity structures,all the primary load-bearing membersincluded in the space-frame analysis

for jacket structures, and a summarydescription of the following:

(i) Structural tolerances,(ii) Welding procedures,(iii) Material (concrete, gravel, or

silt) placement methods,(iv) Fabrication standards,(v) Material quality-control proce-

dures,(vi) Methods and extent of non-

destructive examinations (NDE) forwelds and materials, and

(vii) Quality assurance procedures.(4) Installation verification plan re-

quirements. Additionally, the installa-tion plan shall include a summary de-scription of the planned marine oper-ations, contingencies considered, alter-nate courses of action, and the inspec-tions to be performed including agraphical identification of areas to beinspected and the acceptance/rejectioncriteria.

(c) Requirements for resubmittal. Allsuch plans or the appropriate part af-fected shall be resubmitted for ap-proval if the CVA is changed, if theCVA’s or assigned personnel’s quali-fications change, or if the level of workto be performed changes. The summaryof technical details need not be resub-mitted, unless changes are made in thetechnical details.

(d) Combining of plans. For manmadeislands or platforms fabricated and in-stalled in place, the fabrication and in-stallation verification plans shall becombined.


§ 250.903 Certified Verification Agentduties and nomination.

(a) CVA duties. The CVA nominatedby the lessee and approved by the Re-gional Supervisor shall conduct the ap-propriate reviews in accordance withthe following:

(1) Design phase. (i) The CVA shallconduct the design verification to en-sure that the proposed platform ormajor modification has been designedto withstand the maximum environ-mental and functional load conditionsanticipated during the intended servicelife at the proposed location.

(ii) The design verification shall beconducted by, or be under the direct


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supervision of, a registered profes-sional civil or structural engineer.

(iii) The CVA shall consider the ap-plicable provisions of §§ 250.904 through250.911 of this part and use good engi-neering practice in conducting an inde-pendent assessment of the adequacy ofall proposed planning criteria, environ-mental data, load determinations,stress analyses, material designations,soil and foundation conditions, safetyfactors, and other pertinent param-eters of the proposed design.

(iv) Interim reports shall be sub-mitted by the CVA, as appropriate, tothe Regional Supervisor and the lessee.

(v) Upon completion of the designverification, a final report shall be pre-pared which summarizes the materialreviewed by the CVA and the findingsand includes a recommendation thatthe Regional Supervisor either accept,request modification(s), or reject theproposed design. In addition, the reportshall include the particulars of how, bywhom, and when the independent re-view was conducted and any specialcomments considered necessary. Thefinal report shall be submitted to thelessee and, in triplicate, to the Re-gional Supervisor within 6 weeks of thereceipt of the design data or from thedate the approval to act as a CVA wasissued, whichever is later.

(2) Fabrication verification. The CVAshall monitor the fabrication of theplatform or major modification to en-sure that it has been built in accord-ance with the approved design plansand specifications and the fabricationplan, including the following:

(i) Periodic onsite inspections shallbe made while fabrication is inprogress. The following of the fabrica-tion items, as appropriate, shall beverified:

(A) Quality control by lessee andbuilder,

(B) Fabrication site facilities,(C) Material quality and identifica-

tion methods,(D) Fabrication procedures specified

in the approved plan and adherence tosuch procedures,

(E) Welder and welding procedurequalification and identification,

(F) Structural tolerances specifiedand adherence to those tolerances,

(G) The NDE requirements and eval-uation results of the specified examina-tions,

(H) Destructive testing requirementsand results,

(I) Repair procedures,(J) Installation of corrosion-protec-

tion systems and splash-zone protec-tion,

(K) Erection procedures to ensurethat overstressing of structural mem-bers does not occur,

(L) Alignment procedures,(M) Dimensional check of the overall

structure, and(N) Status of quality-control records

at various stages of fabrication.(ii) The CVA shall consider the appli-

cable provisions of §§ 250.904 through250.911 of this part and use good engi-neering practice in conducting an inde-pendent assessment of the adequacy ofthe fabrication of the platform ormajor modification.

(iii) Interim reports shall be sub-mitted by the CVA, as appropriate, tothe Regional Supervisor and the lessee.

(iv) If the CVA finds that fabricationprocedures are changed or design speci-fications are modified, the lessee shallbe informed. If the lessee prefers to ac-cept the modifications as informed bythe CVA, the Regional Supervisor shallalso be informed.

(v) A final report shall be prepared bythe CVA covering the adequacy of theentire fabrication phase giving detailsof how, by whom, and when the inde-pendent monitoring activities wereconducted and providing any specialcomments considered necessary. Thefinal report is not required to cover as-pects of the fabrication already in-cluded in interim reports. The final re-port shall describe the CVA’s activitiesduring the verification process, sum-marize the findings, contain a con-firmation or denial of compliance withthe design specifications and the ap-proved fabrication plan, and a rec-ommendation to accept or reject thefabrication. The report shall be sub-mitted to the lessee and, in triplicate,to the Regional Supervisor imme-diately after completion of the fabrica-tion of the platform.

(3) Installation phase. The CVA shallwitness the loadout of the jacket,deck(s), and piles from the fabrication


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site(s); review the towing records; con-duct an onsite survey after transpor-tation to the approved location; wit-ness the actual installation of the plat-form or major modification; determinethat the platform has been installed atthe approved location in accordancewith the approved design and the in-stallation plan; and shall comply withthe following:

(i) The CVA shall consider the appli-cable provisions of §§ 250.904 through250.911 of this part and use good engi-neering practice in conducting an inde-pendent assessment of the adequacy ofthe installation activities. The fol-lowing parts of the overall installationprocess, as appropriate, shall beverified:

(A) Loadout and initial flotation op-erations, if any;

(B) Towing operations to the speci-fied location;

(C) Launching and uprighting oper-ations;

(D) Submergence operations;(E) Pile installation; and(F) Final deck and/or component in-

stallation.(ii) The CVA shall observe the instal-

lation activities, spot-check equip-ment, procedures, and recordkeeping,as necessary, to determine compliancewith §§ 250.904 through 250.911 of thispart and the approved plans, and imme-diately report to the Regional Super-visor and the lessee any discrepanciesor damage to structural members. Ap-proval for modified installation proce-dures or for major deviation from ap-proved installation procedures shall beobtained from the Regional Supervisor.

(iii) Interim reports shall be sub-mitted by the CVA, as appropriate, tothe Regional Supervisor and the lessee.

(iv) A final report shall be preparedby the CVA covering the adequacy ofthe entire installation phase giving de-tails of how, by whom, and when theindependent monitoring activities wereconducted and providing any specialcomments considered necessary. Thefinal report shall describe the CVA’sactivities during the verification proc-ess, summarize the findings, contain aconfirmation or denial of compliancewith the approved installation plan,and a recommendation to accept or re-ject the installation. The report shall

be submitted to the lessee and, in trip-licate, to the Regional Supervisorwithin 2 weeks of completion of the in-stallation of the platform.

(4) All data provided to the CVA shallbe handled in the strictest confidenceand not be released by the CVA with-out the consent of the lessee.

(5) Individuals or organizations act-ing as CVA’s for a particular platformshall not function in any capacityother than that of a CVA for that spe-cific project, whenever the additionalactivities would create a conflict, orappearance of a conflict of interest.

(b) CVA nomination. (1) Nomination.Individuals or organizations shall benominated by the lessee planning touse their services. The lessee shallspecify whether the nomination is forthe design, fabrication, or installationphase of verification; for two phases; orfor all three phases.

(2) Qualifications. Qualification sub-missions shall contain sufficient infor-mation to determine compliance with§ 250.902(b)(1)(ii) of this part.


§ 250.904 Environmental conditions.

(a) General. The performance stand-ards of this section pertain to all plat-forms covered by these requirementsregardless of the fabrication material.

(1) Environmental considerations. Allenvironmental phenomena appropriateto the areas of fabrication, transpor-tation, and installation of an offshoreplatform shall be considered and theirinfluence on the platform accountedfor. Such phenomena shall includewind, waves, current, temperature,tide, marine growth, chemical compo-nents of air and water, snow and ice,earthquakes, tsunami, seiche, andother appropriate phenomena.

(2) Environmental data. Statisticaldata and defensible statistical andmathematical models shall be em-ployed to describe the range of perti-nent expected variations of environ-mental phenomena. Defensible datasupplied by meteorologists, oceanog-raphers, or other appropriate special-ists are acceptable as the basis for de-sign. Where possible, environmentalphenomena shall be described by the


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characteristic parameters most rel-evant in the evaluation of effects onthe platform.

(b) Statistical methods. (1) When statis-tical methods are employed in the de-termination of parameters character-izing environmental phenomena, thestatistical methods and distributionsemployed shall be appropriate to theirapplication as evidenced by relevantstatistical tests, confidence limits, andother measures of statistical signifi-cance.

(2) Short-term and long-term vari-ations of environmental phenomenasuch as wind, waves, and current shallbe described by statistical distribu-tions relevant to the parameter consid-ered. Defensible statistical modelingtechniques shall be used in the pre-diction of extreme values.

(3) When hindcasting techniques areemployed to approximate environ-mental parameters, the validity of themodel used shall be defensible.

(c) Design considerations. (1) General.A thorough assessment of the environ-ment in the vicinity of the installationsite shall be made to determine theconditions expected to occur at the siteover the life of the platform.

(2) Design environmental condition. (i)‘‘Design environmental condition’’means the environmental factors pro-ducing the most unfavorable effects onthe platform. Parameters describingthe design environmental condition aregiven in paragraphs (c)(2)(ii) (A), (B),and (C) of this section.

(ii) The design environmental condi-tion shall reflect the various environ-mental events that individually or col-lectively represent the most severeconditions the platform is anticipatedto experience. Such conditions shall beformulated with a set of parametersthat describe the relevant environ-mental events, including the following:

(A) The maximum wave cor-responding to a selected recurrence pe-riod together with the associated wind,current, and appropriate ice and snoweffects;

(B) The minimum air and sea tem-peratures appropriate to the eventbeing treated; and

(C) The maximum water level due totide and storm surge.

(iii) Consideration shall be given toother combinations of the parametersspecified in paragraph (c)(2)(ii)(A) ofthis section involving either maximumwind, maximum current, or maximumice load which may cause a greater re-sponse of the platform.

(iv) In general, the recurrence periodchosen for the events specified in para-graphs (c)(2)(ii) (A) and (C) of this sec-tion shall primarily be based on the de-sign service life of the platform. Forplatforms designed for a service life of20 years, the recurrence period chosenfor the determination of these eventsshall not be less than 100 years. Forother service lives, the design event re-currence interval shall generally be ad-justed to provide for a risk of occur-rence which does not exceed the risk ofoccurrence for the 20-year/100-yearcombination.

(v) For installation sites located inseismically active areas, see paragraph(d)(8) of this section.

(3) Operating environmental conditions.Operating environmental conditionsmeans the set of characteristic param-eters of environmental conditions asso-ciated with a normal function or oper-ation to be conducted on the platform.For each such intended normal func-tion or operation, the lessee shall de-termine a set of characteristic param-eters of environmental conditions.

(d) Specific environmental conditions.(1) Waves information including thefollowing:

(i) Wave conditions considered for de-sign shall be described by defensiblestatistical and/or deterministic meth-ods.

(ii) Parameters characterizing designenvironmental waves shall be based onwave statistics or the results of defen-sible analytic prediction methods suchas hindcasting techniques.

(iii) When using probabilistic anal-yses, the probability of occurrence ofvarious wave-height groups classifiedby directionality and for a wide rangeof possible periods (i.e., tables of ex-ceedance) shall be determined. Whererequired by the method selected to pre-dict extreme values, the average dura-tion of various wave-height groups(i.e., persistence data) shall be deter-mined. All extrapolations and long-


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30 CFR Ch. II (7–1–01 Edition)§ 250.904

term wave data analyses shall use de-fensible techniques, and available dataon extreme values measured in the vi-cinity of the site shall be included inthe long-term prediction.

(iv) When using deterministic meth-ods, waves shall be described by the pa-rameters, height, period, and other rel-evant shape characteristics. The de-sign-wave formulation used shall bevalid for the problem considered.

(v) Breaking-wave criteria appro-priate to the installation site shall bedetermined using defensible formula-tions.

(vi) If spectral wave data are estab-lished for the dynamic analysis ofstructural response to waves, such datashall be derived in accordance with de-fensible methods. If spectral data arenot available in adequate quantities forthe intended application, defensiblemathematical formulations that bestfit the available data shall be used.

(2) Wind information including thefollowing:

(i) Wind velocities shall be classifiedon the basis of their duration. Wind ve-locities having a duration of less than1 minute are referred to as gust winds.Wind velocities having a durationequal to or greater than 1 minute arereferred to as sustained winds. The ref-erence elevation is 33 feet above still-water level.

(ii) Wind conditions considered fordesign shall be described by defensiblestatistical or deterministic methods.

(iii) Wind profiles shall be deter-mined on the basis of defensible statis-tical or mathematical models. Correc-tions of wind velocity data to aver-aging periods other than those em-ployed in the collections of data shallbe based on defensible methods.

(iv) Distribution of the direction andspeed of wind approach to the platformshall be determined, or alternatively,winds shall be considered to approachfrom any direction.

(3) Current information including thefollowing:

(i) Current velocities to be used in de-sign shall be determined on the basis ofthe best statistics available. Tidal cur-rent, wind-generated current, densitycurrent, circulation current, and river-outflow current shall be combined onthe basis of their probability of simul-

taneous occurrence in arriving at cur-rent velocities to be used in design.

(ii) Current velocity profiles shall bedetermined on the basis of site-specificstudies or defensible empirical rela-tionships. Unusual profiles due to bot-tom currents and stratified effects inregions near the mouth of large riversshall be accounted for.

(iii) Directional data on currentswhich exist in the absence of wavesshall be described for each month or byseason. Unless a detailed study of cur-rent directions is made, currents shallbe assumed to run in any direction.

(4) Tide information including thefollowing:

(i) The design storm-tide elevationshall be identified for the installationsite. For design purposes, the designenvironmental wave height shall be su-perimposed on the storm-tide ele-vation.

(ii) Variations in the elevation of thedaily lunar tide shall be used in deter-mining the elevations of boat landings,barge fenders, and the corrosion-pre-vention treatment of platforms in thesplash zone (see § 250.906(c)(5) of thispart).

(iii) The assumed maximum or stormtide shall include astronomical tide,wind tide, and pressure-induced stormsurge. Minimum-tide estimates shallbe based on either the astronomical orlunar tide only. The water depth shallbe referenced to a datum (e.g., meanlow/water or mean low low/water) con-sistent with all other references to ele-vations and depths.

(iv) If data directly applicable to theinstallation site are not available, thebest estimate based on data for nearbylocations shall be used.

(5) Temperature information includ-ing the following:

(i) Extreme values of low tempera-tures shall be expressed in terms of themost probable, lowest values with theircorresponding recurrence periods;

(ii) Air, sea surface, and seabed tem-peratures shall be accounted for in de-scribing the environment and in justi-fying the temperatures used in design.

(6) Snow and ice information includ-ing the following:

(i) If the platform is to be located inan area where sea ice may develop ordrift, ice conditions shall be accounted


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for. Data shall be derived from actualfield investigations, laboratory anal-yses, or other appropriate analogoussources;

(ii)(A) Relevant statistical and phys-ical data on the sea-ice and snow condi-tions shall be described with particularattention to the following:

(1) Concentration and distribution ofice and snow,

(2) Morphology of sea ice (e.g., icefloes, ice ridges, or rafted ice),

(3) Mechanical properties of ice(mode of failure),

(4) Drift speed and direction,(5) Thickness of ice and keel depth of

pressure ridges, and(6) Probability of encountering ice-

bergs, ice floes, ice-floe fragments, andhummocks.

(B) The weight of the maximum snowand ice anticipated to accumulate onthe platform shall be determined.

(7) Marine growth information in-cluding the following:

(i) When assessing the potential formarine growth, account shall be takenof relevant observations and experiencein the area. In the absence of such in-formation, defensible analytical tech-niques shall be employed to assess thepotential for marine growth. Thesetechniques shall take into account sa-linity, oxygen content, hydrogen-ionconcentration value, current, tempera-ture, water turbidity, and other appro-priate factors.

(ii) Consideration shall be given tothe selection of surface coatings whichresist breakdown by micro-organismswhich reduce the onset of corrosion.

(iii) Particular attention shall bepaid to the effects that marine growthhas on surface roughness characteris-tics of submerged structural members.

(8) Earthquake information includingthe following:

(i) The effects of earthquakes on plat-forms located in areas known to beseismically active shall be addressed.

(ii) Except for the provision of§ 250.905(d)(5)(ii) of this part, the seis-micity of the site shall be determined.Preferably, this shall be based on site-specific data. However, regional datashall be deemed acceptable for usewhen site-specific data are not avail-able and the regional data are inter-preted in a manner to produce the most

adverse effect on a platform at the spe-cific site. The following data shall beobtained:

(A) Recurrence interval of seismicevents appropriate to the design life ofthe structure,

(B) Proximity to active faults,(C) Type of faulting,(D) Attenuation of ground motion be-

tween the faults and the site,(E) Subsurface soil conditions, and(F) Records from past seismic events

at the site or from analogous sites.(iii) The use of available data to de-

scribe the seismic characteristics ofthe site is permitted where it can beshown that such data are consistentwith the requirements of paragraph(d)(8)(ii) of this section.

(iv) The seismic data shall be used toestablish a quantitative design earth-quake criterion describing the designearthquake-induced ground motion. Inaddition to ground motion and as ap-plicable to the installation site, thefollowing earthquake-related phe-nomena shall be taken into account:

(A) Liquefaction of subsurface soils,(B) Submarine slides,(C) Tsunamis, and(D) Fluid motions in tanks.


§ 250.905 Loads.(a) Introduction. This section covers

the identification, definition, and de-termination of the loads to which afixed offshore platform may be exposedduring and after its transportation andinstallation. The requirements con-tained in paragraphs (b) through (d) ofthis section apply to both steel-piledplatforms and concrete-gravity plat-forms. Additional requirements cov-ering steel-piled platforms are con-tained in paragraph (e) of this section.Additional requirements covering con-crete-gravity platforms are containedin paragraph (f) of this section.

(b) General. (1) All types of loadsspecified in paragraphs (c)(1) through(c)(5) of this section shall be accountedfor in the design and operation of theplatform.

(2) Where applicable, the effects of in-creased dimensions and weight due to


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marine growth and snow and ice accu-mulation shall be addressed in the de-sign.

(c) Load definition. (1) Dead loads.Dead loads associated with the plat-form are loads that do not change dur-ing the mode of operation under con-sideration. Dead loads include the fol-lowing:

(i) Weight in the air of the platform(refer to paragraphs (e)(1) and (f)(1) ofthis section for itemizations of weightfor pilefounded platforms and gravityplatforms, respectively).

(ii) Weight of permanent ballast andthe weight of permanent machinery in-cluding liquids at operating levels.

(iii) External hydrostatic pressureand buoyancy in calm sea conditionscalculated on the basis of the designwaterline.

(iv) Static earth pressure.(2) Live loads. Live loads associated

with the normal operation and use ofthe platform are loads that couldchange during the mode of operationconsidered. Live loads acting after fab-rication or installation include the fol-lowing:

(i) Weight of drilling and productionequipment that can be removed such asderrick, draw works, mud pumps, mudtanks, separators, and tanks.

(ii) Weight of crew and consumablesupplies such as mud, chemicals, water,fuel, pipe, cable, stores, drill stem, andcasing.

(iii) Weight of liquids in storagetanks.

(iv) Forces exerted on the platformdue to drilling, e.g., the maximum der-rick reaction when placing or pullingcasing.

(v) The forces exerted on the plat-form during the operation of cranesand vehicles.

(vi) The forces exerted on the plat-form by vessels moored to the plat-form.

(vii) The forces exerted on the plat-form by helicopters during takeoff andlanding or while parked on the plat-form. When applicable, the dynamic ef-fects on the platform of the forces spec-ified in paragraphs (c)(2) (iv) through(vii) of this section shall be taken intoaccount. Live loads occurring duringtransportation and installation shallbe determined for each specific oper-

ation involved, and the dynamic effectsof such loads shall be addressed (see§ 250.910 of this part).

(3) Deformation loads. Deformationloads are loads due to deformations im-posed on the platform. For anitemization of deformation loads appli-cable to steel-piled platforms andconcretegravity platforms, see para-graphs (e)(2) and (f)(2) of this section,respectively.

(4) Accidental loads. Considerationshall be given to accidental loadings;and where such loadings are deter-mined to be a factor, they shall bequantified and incorporated into thedesign. Accidental loads are loads thatcould occur as the result of an accidentor exceptional conditions, such as thefollowing:

(i) Extreme impact loads caused bysupply boats, barges, and other craftanticipated to work in the vicinity ofthe platform;

(ii) Impact loads caused by droppedobjects, such as drill collars, casing,blowout-preventer stacks;

(iii) Loss of internal pressure re-quired to resist hydrostatic loadingand to maintain buoyancy during theinstallation of the platform;

(iv) Explosion;(v) Effects of fire; and(vi) Iceberg collision.(5) Environmental load information

including the following:(i) Environmental loads are loads due

to wind, waves, current, ice, snow,earthquake, and other environmentalphenomena.

(ii) The characteristic parameters de-fining an environmental load shall beappropriate to the installation site asdetermined by the studies required by§ 250.904 of this part. Operating environ-mental loads are loads derived fromthe parameters characterizing oper-ating environmental conditions (see§ 250.904(c)(3) of this part). Design envi-ronmental loads are loads derived fromthe parameters characterizing the de-sign environmental condition (see§ 250.904(c)(2) of this part).

(iii) Environmental loads shall be ap-plied to the platform from directionsproducing the most unfavorable effectson the platform unless site-specificstudies allow for a less stringent re-quirement.


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(iv) The combination and severity ofdesign environmental loads shall beconsistent with the likelihood of theirsimultaneous occurrence. The simulta-neous occurrence of environmentalloads shall be modeled by appropriatesuperposition methods.

(v) Earthquake loads and loads re-sulting from accidental or rare envi-ronmental phenomena need not becombined with other environmentalloads unless site-specific conditions in-dicate that such combination is appro-priate.

(d) Determination of environmentalloads. (1) Wave load information includ-ing the following:

(i) Wave-induced loads shall be cal-culated using defensible methods orshall be obtained from adequate modelor field test data;

(ii) A sufficient range of waves andwavecrest positions relative to theplatform shall be investigated to en-sure an accurate determination of themaximum wave load on the platform;

(iii) Wave impact loads on structuralmembers below the design wave crestelevation shall be accounted for by de-fensible theoretical methods or rel-evant model test of full-scale data;

(iv) Where applicable, the possibilityof dynamic excitation of the platformdue to flow-induced cyclic loading shallbe addressed;

(v) For additional requirements per-taining to steel-piled platforms andconcrete gravity-platforms, see para-graphs (e)(3) and (f)(3) of this section,respectively; and

(vi) Where applicable, additional hy-drostatic loading effects shall be ad-dressed.

(2) Wind load information includingthe following:

(i) Wind loads, local wind pressures,and wind profiles shall be determinedon the basis of defensible analyticalmethods or wind tunnel tests on a rep-resentative model of the platform,

(ii) In determining design environ-mental loads on the overall platform,wind loads calculated on the basis ofthe design-sustained wind velocityshall be combined with other design en-vironmental loads,

(iii) The design gust wind load shallbe used in the design of local structureunless the effects of the load combina-

tion described in paragraph (d)(2)(ii) ofthis section are more severe,

(iv) Where appropriate, the dynamiceffects due to the cyclic nature of gustwind and cyclic loads due to vortexshedding shall be taken into account.Both the drag and lift components ofloads due to vortex shedding shall betaken into account.

(v) Where appropriate, flutter andload amplification due to vortex shed-ding shall be addressed.

(3) Current load information includ-ing the following:

(i) Current-induced loads on im-mersed members of the platform shallbe accounted for by defensible methodsor the results of model test or site-spe-cific data,

(ii) The lift and drag coefficients usedin the determination of current loadsshall be appropriate to the current ve-locity and structural configuration,

(iii) Current velocity profiles used indesign shall be appropriate to the in-stallation site,

(iv) For determination of loads in-duced by the simultaneous occurrenceof wave and current fields, the total ve-locity field shall be computed by defen-sible methods before computing thetotal force, and

(v) Where appropriate, flutter andload amplification due to vortex shed-ding shall be addressed.

(4) Ice and snow load information in-cluding the following:

(i) For platforms located in areas as-sociated with ice movement, contactloads caused by floating ice shall be de-termined according to defensible theo-retical methods, model test data, orfull-scale measurements;

(ii) In locations where platforms aresubject to ice and snow accumulation,the additional weight of snow and iceon the platform shall be addressed;

(iii) The effects of ice accumulationand ice jam, including the effects ofchanges in configuration due to adhe-sion, shall be accounted for in the de-termination of the total environmentalload; and

(iv) The incident pressure due topack ice, pressure ridges, and where ap-propriate, ice island fragments imping-ing on the platform shall be addressed.

(5) Earthquake load information in-cluding the following:


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30 CFR Ch. II (7–1–01 Edition)§ 250.905

(i) For platforms located in seis-mically active areas, design earth-quake-induced ground motions shall bedetermined on the basis of seismic dataapplicable to the installation site. De-sign earthquake ground motions shallbe described by either applicableground motion records or responsespectra consistent with the recurrenceperiod appropriate to the design life ofthe platform.

(ii) Available and defensible stand-ardized spectra applicable to the regionof the installation site are acceptableif such spectra reflect those site-spe-cific conditions affecting frequencycontent and energy distribution. Theseconditions include the type of activefaults in the region, the proximity ofthe site to the potential source faults,the attenuation or amplification ofground motion between the faults andthe site, and the soil conditions at thesite.

(iii) Ground-motion descriptionsshall consist of three components cor-responding to two orthogonal hori-zontal directions and the vertical di-rection. All three components shall beapplied to the platform simulta-neously.

(iv)(A) When the response spectrummethod is used for structural analysis,input values of ground motion (spectralacceleration representation) shall notbe less severe than the following:

(1) One hundred percent in a principalhorizontal direction,

(2) Sixty-seven percent in the orthog-onal horizontal direction, and

(3) Fifty percent in the vertical direc-tion.

(B) The horizontal components shallalso be applied in the alternative or-thogonal horizontal directions.

(v) If the time history method is usedfor structural analysis, at least threesets of ground-motion time historiesshall be employed. The manner inwhich the time histories are used shallaccount for the potential sensitivity ofthe platform’s response to variations inthe phasing of the ground-motionrecords.

(vi) When applicable, effects of soilliquefaction and/or loads resultingfrom submarine slides or creep,tsunamis, and earthquake motionsshall be addressed.

(e) Loads on steel pile-supported plat-forms. The following requirementsapply to loads on steel pile-supportedplatforms and shall be applied togetherwith the requirements in paragraphs(b), (c), and (d) of this section:

(1) The dead load of the platformshall include, as appropriate, theweight in air of the jacket, piling,grout, superstructure modules, stiff-eners, decking, piping, heliport, andany other fixed structural part lessbuoyancy, with due allowance forflooding.

(2) Where appropriate, the deforma-tion loads to be accounted for are thoseresulting from temperature variationsleading to thermal stresses in the plat-form, and those resulting from soil dis-placements (e.g., differential settle-ments or lateral displacements).

(3) Wave load information includingthe following:

(i) For platforms composed of mem-bers having diameters that are neg-ligible in relation to the wave lengthsconsidered, semiempirical formulationsaccounting for wave-induced drag andinertia forces based on the water par-ticle velocities and accelerations on anundisturbed, incident flow field are ac-ceptable;

(ii) When a method as described inparagraph (e)(3)(i) of this section isused, the wave field shall be describedby a defensible wave theory appro-priate to the wave heights, wave peri-ods, and water depth at the installa-tion site;

(iii) The coefficients of drag and iner-tia used in calculating wave loads shallbe determined on the basis of modeltest results, published data, or full-scale measurements appropriate to thestructural configuration, surfaceroughness, and wave field; and

(iv) For platforms composed of mem-bers whose diameters are not negligiblein relation to the wave lengths consid-ered and for structural configurationsthat will substantially alter the undis-turbed, incident flow field, diffractionforces and the hydrodynamic inter-action of structural members shall betaken into account.

(f) Loads on concrete-gravity platforms.The following requirements apply toloads on concrete-gravity platformsand shall be applied together with the


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requirements described in paragraphs(b), (c), and (d) of this section.

(1) The dead load of the platformshall include, as appropriate, theweight in air of the foundation, skirts,columns, superstructure modules,decking, piping, heliport, and anyother fixed structural part less buoy-ancy with due allowance for flooding.Weight calculations based on nominaldimensions and mean values of densityare acceptable.

(2) The deformation loads to be ac-counted for are those due to prestress,shrinkage and expansion, creep, tem-perature variations, and differentialsettlements.

(3) Wave load information includingthe following:

(i) For platforms composed of largegravity bases and one or more columnswhose diameters are not negligible inrelation to the wave lengths consid-ered, defensible wave-load theorieswhich account for the drag, inertia,and diffraction forces on the platformshall be employed;

(ii) For complex structural configu-rations, the hydrodynamic interactionof large, immersed structural membersshall be addressed;

(iii) When diffraction forces and hy-drodynamic interaction are negligible,only semiempirical formulations com-parable to those mentioned in para-graphs (e)(3) (i) and (iii) of this sectionaccounting for drag and inertia forcesare acceptable; and

(iv) The undisturbed, incident flowfield shall be addressed by a defensiblewave theory appropriate to the waveheights, wave periods, and water depthat the installation site.


§ 250.906 General design requirements.(a) General. This section specifies the

general concepts and methods of anal-ysis to be incorporated in the design ofa platform.

(b) Analytical approaches. (1) Struc-tural response information includingthe following:

(i) Methods of analysis employed inassociation with the specifications ofthese requirements shall treat geo-metric and material nonlinearities in a

defensible manner. When nonlinearmethods of analysis are used to assesscollapse mechanisms, it shall be dem-onstrated that the platform has suffi-cient ductility to develop the requiredresistance or structural displacements.

(ii) Where theoretically based analyt-ical procedures covering the platformor parts thereof are unavailable or notwell defined, model studies shall be uti-lized. The acceptability of model stud-ies depends on the procedures em-ployed, including enumeration of thepossible sources of errors, the limits ofapplicability of the model test results,and the methods of extrapolation tofull-scale data.

(2) Loading format information in-cluding the following:

(i) Either a deterministic or spectralformat shall be employed to describevarious load components. When a stat-ic approach is used, it shall be dem-onstrated, where appropriate, that thegeneral effects of dynamic amplifi-cation were addressed. The influence ofwaves other than the highest wavesshall be investigated for their potentialto produce maximum peak stresses re-sulting from possible resonance withthe platform.

(ii) When considering the designearthquake as discussed in § 250.905 ofthis part, a dynamic analysis shall beperformed. A dynamic analysis shallalso be performed to assess the effectsof environmental or other types ofloads if significant dynamic amplifi-cation is expected.

(iii) For fatigue analysis, the long-term distribution of the stress range,with proper consideration of dynamiceffects, shall be obtained for relevantloadings anticipated during the designlife of the platform (see §§ 250.907(c)(6)and 250.908(c)(6) of this part).

(3) Combinations of loading compo-nents information including the fol-lowing:

(i) Loads imposed during and after in-stallation shall be taken into account.Of the various loads described in§ 250.905, of this part, those loads to beconsidered for design shall be combinedin a manner consistent with their prob-ability of simultaneous occurrence.However, earthquake loadings shall beapplied without consideration of other


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environmental effects unless condi-tions at the site necessitate their in-clusion. The direction of applied envi-ronmental loads shall be that pro-ducing the highest possible influenceson the platform, considering the plat-form’s orientation and location withrespect to bottom topography, direc-tion of fetch, and nearby land masses.

(ii) While it is required to obtain anduse those loading components whichproduce realistic maximum effects onthe platform, loading combinationscorresponding to conditions after in-stallation shall reflect both operatingand design environmental loadings.Sections 250.907, 250.908, and 250.909 ofthis part give the minimum load com-binations to be considered.

(iii) The operating environmentalconditions and the maximum tolerableenvironmental loads during installa-tion shall be specified.

(c) Overall design considerations. (1)Design life. The design service life ofthe platform shall be specified as pre-scribed in § 250.904(c)(2)(iv) of this part.

(2) Air gap. An air gap of 5 feet shallbe provided between the maximumcrest elevation of the design wave (in-cluding tidal effects) and the lowestportion of the platform upon whichwave forces have not been included inthe design. After accounting for theinitial and long-term settlements re-sulting from consolidation and subsid-ence, the elevation of the crest of thedesign wave shall be based on the ele-vation of the mean low-water line, as-tronomical and storm tides, waverunup, the tilting of the platform, andwhere necessary, tsunamis.

(3) Long-term and secondary effects.The following effects shall be ad-dressed, as appropriate, for the plannedplatform:

(i) Local vibration due to machinery,equipment, and vortex shedding;

(ii) Stress concentrations at criticaljoints;

(iii) Secondary stresses induced bylarge deflections (P-∆ effects);

(iv) Cumulative fatigue;(v) Corrosion;(vi) Marine growth; and(vii) Ice abrasion.(4) General arrangement. The platform

and equipment shall be arranged tominimize the potential of structural

damage and personal injury resultingfrom accidents. In this regard, the con-sequences of the arrangement or place-ment of the following components andtheir effects shall be addressed:

(i) Equipment and machinery—noiseand vibration,

(ii) High-pressure piping—leakage inclosed spaces,

(iii) Lifting devices—dropped loads,and

(iv) Vessel mooring devices—linebreakage and tripping quick-releasemechanisms.

(5) Corrosion-protection zones. Meas-ures taken to mitigate the effects ofcorrosion as required by §§ 250.907(d)and 250.908(c)(5) of this part shall bespecified and described in terms of thefollowing definitions for corrosion-pro-tection zones:

(i) Submerged zone—that part of theplatform below the splash zone,

(ii) Splash zone—that part of theplatform between the highest and low-est water levels reached by sea statesexceeded for 1 percent of the time an-nually when superimposed on the high-est and lowest levels of tide with dueallowance for high and low installationof the platform,

(iii) Atmospheric zone—that part ofthe platform above the splash zone,

(iv) Ice zone—that part of the plat-form which can reasonably be expectedto come into contact with floating orsubmerged ice annually.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11,1988. Redesignated and amended at 63 FR29479, 29486, May 29, 1998; 63 FR 34597, June 25,1998]

§ 250.907 Steel platforms.

(a) Materials—(1) General. (i) This sec-tion covers specifications for materialsused for the construction of steel pile-supported platforms. Steels shall besuitable for their intended service asdemonstrated by testing under rel-evant service conditions or previoussatisfactory performance under serviceconditions similar to those intended.Steels shall be of good commercialquality, defined by specification, andfree of injurious defects.


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(ii) Steels shall exhibit satisfactoryformability and weldability character-istics and fracture toughness satisfac-tory for the intended applications. Ma-terials for structural members whichare fracture critical or for memberswhich sustain significant tensile stressand whose fracture would pose a threatto the survival of the platform shallhave sufficient toughness to guardagainst brittle fracture. Materials se-lected for members which are subjectedto significant tensile stress shall havetoughness suitable to their intendedapplication.

(iii) In cases where principal loadsfrom either service or weld residualstresses are imposed normal to theplate, appropriate precautions shall betaken to avoid lamellar tearing par-allel to the plate surface.

(2) Material selection information in-cluding the following:

(i) Steels for structural membersshall be selected according to criteriathat take into account the requiredyield strength, fracture toughness,service temperature (see paragraph(a)(3) of this section), and intended ap-plication;

(ii) Bolts and nuts shall have me-chanical and corrosion properties com-parable to the structural elementsbeing joined. Materials for bolts andnuts shall be defined by and tested inaccordance with material standardscompatible with those for the joinedstructural members;

(iii) When new alloys are used, theadequacy of fracture toughness shall besupported by appropriate fracturetests; and

(iv) When materials other than steelare used for structural purposes, themechanical and durability propertiesnecessary for their intended functionshall be designated, including tough-ness and fatigue characteristics, wherenecessary.

(3) Service temperature. Service tem-perature means the temperature thatthe material is expected to achieve inthe operational environment.

(i) For material at or below the wa-terline, the minimum service tempera-ture shall be the lowest average dailywater temperature applicable to theparticular depth. For material abovethe waterline, the minimum service

temperature shall be the lowest 1-dayaverage daily atmospheric temperatureover a 10-year period, unless the mate-rial is warmed by auxiliary heating.

(ii) In all cases where material tem-perature is reduced by localized cryo-genic storage or other cooling means,such factors shall be accounted for inestablishing minimum service tem-perature.

(4) Classification of applications. Whenconsidering the welding requirementsgiven in subsequent sections, materialsshall be considered as ‘‘Weld Class A’’if the members are critical or specialstructural elements, ‘‘Weld Class B’’ ifthe members are primary load-carryingmembers of the platform, or ‘‘WeldClass C’’ if the members are secondarystructural elements.

(5) Material designation. All materialemployed in platform constructionshall be described and designated by amaterial specification.

(b) Fabrication and welding—(1) Gen-eral. (i) Welding shall be performed inaccordance with the applicable provi-sions of the American Welding Society(AWS) publication, AWS D1.1, Struc-tural Welding Code—Steel, or other ap-propriate welding codes.

(ii) Fabrication other than weldingshall be performed in accordance withAmerican Institute of Steel Construc-tion (AISC) publication, Specificationfor Structural Steel Buildings, Allow-able Stress Design and Plastic Design,or other appropriate codes. The code tobe followed during fabrication and con-struction shall be specified on designdocuments.

(2) Welding. (i) Welding proceduresand filler metals shall be selected toproduce sound welds, and the fillermetal shall have strength and tough-ness compatible with the base metal.Workmanship shall be in compliancewith paragraph (b)(1)(i) of this section.

(ii) Forming processes shall not de-grade the base metals below their min-imum required properties. A heattreatment shall be employed to providethe required properties, where nec-essary.

(iii) Misalignment between parallel(abutting) members shall be mini-mized. Weld size for fillet welds shallbe sufficient to compensate for the gap


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30 CFR Ch. II (7–1–01 Edition)§ 250.907

between faying surfaces of the mem-bers. Lapped joints shall possess suffi-cient overlaps. Both edges of an over-lap joint shall have continuous filletwelds.

(iv) When arc-air gouging is em-ployed, the carbon buildup and burningof the weld or base metals shall beminimized.

(v) Peening shall not be used for sin-gle-pass welds or for the root or coverpasses of multipass welds. Peeningshall be used only after cleaning ofweld passes. Fairing by heating, flameshrinking, or other methods, when ap-plied to Weld Class A or B structuralelements, shall be performed withoutdamaging the base metals. Such cor-rective measures shall be kept to aminimum when treating high-strengthsteels.

(3) Quality assurance. A documentedinspection plan shall be prepared andfollowed and shall cover the followingitems:

(i) A suitable system for materialidentification and quality control dur-ing all stages of construction,

(ii) Requirements for welding proce-dures and welder qualifications,

(iii) The extent of weld inspection(including nondestructive examinationmethods) and the criteria for weld ac-ceptance or rejection, and

(iv) Necessary dimensional toler-ances.

(4) Weld nondestructive examination. (i)All welds shall be subjected to visualexamination. Nondestructive examina-tion shall be conducted to the extentindicated in paragraph (b)(4)(ii) of thissection after all forming and postweldheat treatments have been completed.Weld examination procedures shall beadequate to detect delayed weld crack-ing in cases involving high-strengthsteels or high-hydrogen welding proc-esses.

(ii) As called for in paragraph(b)(3)(iii) of this section, a plan for non-destructive examination of the weldsshall be prepared and followed. The ex-tent of inspection of Weld Classes Aand B structural elements shall be con-sistent with the applications involved.Important welds of Weld Classes A andB structural elements are those inac-cessible or very difficult to inspect inservice. Important welds shall be sub-

jected to an increased level of non-destructive examination during fab-rication.

(iii) If the proportion of unacceptablewelds becomes excessive, the frequencyof nondestructive examination shall beincreased.

(c) Design and analysis—(1) General. (i)Steel platforms shall be adequately de-signed and analyzed to withstand theloads to which they are likely to be ex-posed during their design life. The ef-fects on the platform shall be deter-mined for a minimum set of loadingconditions by using a defensible meth-od to ensure that the resulting re-sponses do not exceed the safety cri-teria appropriate to the methods em-ployed.

(ii) The use of design methods, otherthan those specifically covered in thissection, and their associated safety cri-teria are allowed if it can be dem-onstrated that such alternative meth-ods will result in a structural safetylevel equivalent to that provided bythe direct application of these require-ments.

(iii) Sections 250.905 and 250.906 ofthis part shall be consulted regardingdefinitions and requirements pertinentto the determination of loads and gen-eral design requirements.

(2) Loading conditions. (i) Appropriateloading conditions that produce themost adverse effects on the platformduring and after fabrication and instal-lation shall be considered;

(ii) Loadings corresponding to condi-tions after installation shall include atleast those relating to both the oper-ating and design environmental condi-tions, combined with other pertinentloads in the following manner:

(A) Operating environmental condi-tions combined with dead and liveloads appropriate to the function andoperation of the platform;

(B) Design environmental conditionscombined with dead and live loads ap-propriate to the function and operationof the platform;

(C) Design environmental conditionscombined with dead loads and min-imum live loads appropriate to thefunction and operation of the platform;and

(iii) For platforms located in seis-mically active areas, loads induced by


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earthquake ground motions shall becombined with dead and live loads ap-propriate to the operation and functionof the platform.

(3) Methods of design and analysis. (i)The nature of loads and loading com-binations as well as the local environ-mental conditions shall be consideredin the selection of design methods.Methods of analysis and their associ-ated assumptions shall be compatiblewith the overall design principles.

(ii) Linear, elastic methods (workingstress methods) of design and analysisare acceptable if proper measures aretaken to prevent general and localbuckling failure. Regarding structuralinstability as a possible mode of fail-ure, the effects of initial stresses andgeometric imperfection shall be takeninto account.

(iii) Dynamic effects shall be ac-counted for if the wave energy in thefrequency range of the structural reso-nance frequencies is of sufficient mag-nitude to produce significant stressesin the platform. The determination ofdynamic effects shall be accomplishedeither by computing the dynamic am-plification effects in conjunction witha deterministic analysis or by a ran-dom dynamic analysis based on a spec-tral formulation. In the latter case, theanalysis shall be accompanied by a sta-tistical description and evaluation ofthe relevant input parameters.

(iv) The interaction of the soil withthe platform’s piles shall be included inthe analytical model used to obtain thestructural response (see§ 250.909(d)(1)(ii) of this part).

(v) For static loads, plastic methodsof design and analysis shall be em-ployed only when the properties of thesteel and the connections exclude thepossibility of brittle fracture and allowfor formation of plastic hinges withsufficient plastic rotation capacity andadequate fatigue resistance.

(vi) Whenever plastic analysis isused, it shall be demonstrated that thecollapse mode (mechanism) cor-responding to the smallest loading in-tensities has been used for the deter-mination of the ultimate strength ofthe platform. The effect of bucklingand other destabilizing nonlinear ef-fects shall be taken into account in theplastic analysis of platforms with com-

pressive forces. Whenevernonmonotonic or repeating loads arepresent, it shall be demonstrated thatthe structure will not fail by incre-mental collapse or fatigue.

(vii) Under dynamic loads when plas-tic strains may occur, the consider-ations specified in paragraph (c)(3)(v)of this section shall be satisfied andany buckling and destabilizing non-linear effects shall be taken into ac-count.

(4) Allowable stresses and load factors.(i) When the design is based on a work-ing-stress method (see paragraphs(c)(1)(ii) and (c)(3)(ii) of this section),the safety criteria shall be expressed interms of appropriate basic allowablestresses in accordance with require-ments specified in paragraphs (c)(4) (ii)through (vi) of this section.

(ii) For structural members and load-ings covered by AISC publication,Specification for Structural SteelBuildings, Allowable Stress Design andPlastic Design, with the exception ofearthquake loadings (see paragraph(c)(4)(v) of this section) and tubularstructural members under the com-bined loading of axial compression andbending, the basic allowable stresses ofthe members shall be obtained usingthe AISC specification. For tubularmembers subjected to the aforemen-tioned interaction, stress limits shallbe set in accordance with a defensibleformulation.

(iii) Where stresses in members listedin paragraph (c)(4)(ii) of this sectionare shown to result from forces im-posed by the design environmental con-ditions acting alone or in combinationwith dead and live loads (see paragraph(c)(2)(ii) of this section), the basic al-lowable stresses cited in paragraph(c)(4)(ii) of this section, modified by afactor of four-thirds, are permitted forthe design environmental load con-tribution if the resulting structuralmember sizes are not less than thoserequired for dead and live loads plusoperating environmental conditionswithout the one-third increase in al-lowable stresses.

(iv) For any two- or three-dimen-sional stress fields within the scope ofthe working-stress formulation, theequivalent stress (e.g., the von Misesstress intensity) shall be limited by an


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appropriate allowable stress less thanthe yield stress, with the exception ofstresses of a highly localized nature. Inthe latter case, local yielding of thestructure is acceptable if it can bedemonstrated that such yielding doesnot lead to progressive collapse of theoverall platform and that the generalstructural stability can be maintained.

(v) When considering loading com-binations on individual members or onthe overall platform, which includeloads defined as accidental (see§ 250.905(c)(4) of this part), or in pur-suing structural analysis for earth-quake loads (see paragraph (c)(2)(iii) ofthis section), the allowable stress setat a level of the minimum yield orbuckling strength of the material shallbe considered appropriate.

(vi) Whenever elastic instability,overall or local, may occur before thecompressive stresses reach the min-imum specified yield strength of thematerial, appropriate allowable buck-ling stresses shall govern.

(vii) Whenever the ultimate strengthof the platform is used as the basis forthe design of its members, the safetyfactors or the factored loads shall beformulated in accordance with the re-quirements of AISC publication, Speci-fication for Structural Steel Buildings,Allowable Stress Design and PlasticDesign, or an equivalent code. The ca-pability of the primary structuralmembers to develop their predicted ul-timate load capacity shall be dem-onstrated.

(viii) For details of high-stress con-centration, consideration shall begiven to safety against brittle fractureand to material quailty-control proce-dures.

(5) Structural response to earthquakeloads. (i) Platforms located in seis-mically active areas shall be designedto possess adequate strength and stiff-ness to withstand the effects of anearthquake which has a reasonablelikelihood of not being exceeded duringthe lifetime of the structure (see para-graph (c)(2)(iii) of this section) and re-main stable during rare motions ofgreater severity;

(ii) The adequacy of structuralstrength shall be demonstrated byanalysis to verify that no significantstructural damage occurs; and

(iii) Platforms shall also possess ade-quate ductility to withstand a rare in-tense earthquake.

(6) Fatigue assessment. (i) Structuralmembers and joints for which fatigue isa probable mode of failure and forwhich past experiences are insufficientto ensure safety from possible cumu-lative fatigue damage shall be ana-lyzed. Emphasis shall be given to jointsand members in the splash zone, thosethat are difficult to inspect and repairafter the platform is in service, andthose susceptible to corrosion-acceler-ated fatigue, and

(ii) For structural members andjoints which require a detailed analysisof cumulative fatigue damage, the re-sults of the analysis shall indicate aminimum calculated life of twice thedesign life (see § 250.906(c)(1) of thispart) of the platform if there is suffi-cient structural redundancy to preventcatastrophic failure of the platform asa result of fatigue failure of the mem-ber or joint under consideration. Ifsuch redundancy does not exist or ifthe desirable degree of redundancy issignificantly reduced as a result of fa-tigue damages, the results of a fatigueanalysis shall indicate a minimum cal-culated life of three times the designlife of the platform.

(d) Corrosion protection. All materialsshall be protected from the effects ofcorrosion by a corrosion-protectionsystem. The design of such systemsshall take into account the possible ex-istence of stress corrosion, corrosionfatigue, and galvanic corrosion. If theintended sea environment contains un-usual contaminants, any special corro-sive effects of such contaminants shallalso be considered. Protection systemsshall be designed in accordance withthe National Association of CorrosionEngineers (NACE) publication, NACEStandard RP–01–76, RecommendedPractice, Corrosion Control of Steel,Fixed Offshore Platforms AssociatedWith Petroleum Production, or othercomparable standards.

(e) Connection of piles to structure. Theattachment of the jacket structure tothe piles shall be accomplished by posi-tive, controlled means. Such attach-ments shall be capable of withstanding


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the static and long-term cyclic load-ings to which they will be subjected.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11,1988, as amended at 61 FR 60025, Nov. 26, 1996.Redesignated and amended at 63 FR 29479,29486, May 29, 1998]

§ 250.908 Concrete-gravity platforms.

(a) General. (1) This section coversthe materials, analysis, design, andconstruction of reinforced and/orprestressed concrete-gravity platforms.

(2) Materials, structural systems,methods of design, and methods of con-struction that do not conform to therequirements of this section shall notbe used unless it is shown that theywill result in a safety level at leastequivalent to that provided by the di-rect application of the requirements ofthis section.

(b) Materials—(1) General. All mate-rials shall be selected with due atten-tion to their strength and durability inthe marine environment. All materialtests shall be performed in accordancewith the latest, applicable standards ofthe American Society for Testing andMaterials (ASTM).

(2) Cement. (i) Cement must be equiv-alent to Type I, II, or III portland ce-ment as specified by ASTM Standard C150–99, Standard Specification for Port-land Cement, or portland-pozzolan ce-ment as specified by ASTM Standard C595–98, Standard Specification forBlended Hydraulic Cements. However,the suitability of Type III cement toserve its intended function must bedemonstrated.

(ii) The tricalcium aluminate con-tent of the cement shall be such as toenhance the corrosion protection of re-inforcing steel without impairing thedurability of concrete.

(iii) If oil storage is planned and theoil is expected to contain soluble sul-fates in amounts that may impair thedurability of concrete, the tricalciumcontent shall be reduced or a suitablecoating employed to protect the con-crete.

(3) Water. (i) Water used in mixingconcrete shall be clean and free frominjurious amounts of oils, acids, alka-lis, salts, organic materials, or othersubstances that may be deleterious toconcrete or steel.

(ii) If nonpotable water is used, theproportions of materials in the con-crete shall be based on test concretemixes using water from the samesource. The strength of mortar testcubes made with nonpotable watershall not be significantly below thestrength of similar cubes made withpotable water.

(iii) Water for reinforced orprestressed concrete or grout shall notcontain chlorides and sulfates inamounts detrimental to the durabilityof the platform.

(4) Aggregates. (i) Aggregates mustconform to the requirements of ASTMStandard C 33–99a, Standard Specifica-tion for Concrete Aggregates. Light-weight aggregates conforming toASTM Standard C 330–99, StandardSpecification for Lightweight Aggre-gates for Structural Concrete, will onlybe permitted if they do not pose dura-bility problems and where they areused according to the applicable provi-sions of the ACI publication, ACIStandard 318, Building Code Require-ments for Reinforced Concrete, plusCommentary.

(ii) Marine aggregates shall bewashed with fresh water before use toremove the surface and solublechlorides and sulfates so that the totalchloride and sulfate content of the con-crete mix water does not exceed thelimits of paragraph (b)(3)(iii) of thissection.

(iii) The maximum size of the aggre-gate shall be such that the concretecan be placed without voids.

(5) Admixtures. The admixture shallbe shown capable of maintaining essen-tially the same composition and per-formance throughout the work as theproduct used in establishing concreteproportions. Admixtures containingchloride ions shall not be used inprestressed concrete or in concretecontaining aluminum embedments.

(6) Reinforcing and prestressing sys-tems. (i) Reinforcing and prestressingsystems shall conform to the require-ments of ACI 318; and

(ii) Structural steel used in com-posite structures shall conform to therequirements of § 250.907 of this part.

(7) Concrete. The concrete shall be de-signed to ensure sufficient strengthand durability. The quality control of


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concrete shall conform to ACI 318. Themixing, placing, and curing of concreteshall conform to the requirements ofparagraph (e) of this section. Thewater-cement ratio shall be strictlycontrolled and in no case shall it ex-ceed 0.45.

(8) Grout for bonded tendons. (i) Groutfor bonded tendons shall conform toACI 318; and

(ii) The maximum allowable contentsof chlorides and sulfates determined inaccordance with paragraph (b)(3)(iii) ofthis section shall also apply to groutmixes.

(9) Post-tensioning ducts. Post-dentioning ducts shall conform to therequirements of ACI 318. Ducts andduct splices shall be watertight andgrout-tight and shall be of suitablethickness to prevent crushing, defor-mation, and blockage.

(10) Post-tensioning anchorages andcouplers. Post-tensioning anchoragesand couplers shall conform to the re-quirements of ACI 318.

(c) Design requirements—(1) General. (i)The strength of the platform shall beadequate to resist failure of the plat-form or its components. Among themodes of possible failure that shall beconsidered are the following:

(A) Loss of overall equilibrium,(B) Failure of critical sections, and(C) Instability (buckling).(ii) Additionally, the following items

shall be considered in relation to theirpotential influences on the platform:

(A) Cracking or spalling,(B) Deformations,(C) Corrosion of reinforcement or de-

terioration of concrete, and(D) Vibrations.(2) Required strength. The required

strength shall conform to requirementsof ACI 357R.

(3) Design strength. The designstrength shall conform to requirementsof ACI 318 and ACI 357R.

(4) Other design requirements. (i) Inconsidering those items listed in para-graph (c)(1)(ii) of this section, the abil-ity of the platform to withstandunfactored loads in the following com-bination shall be demonstrated:

D+T+L+E0

where L represents the most unfavor-able live load; D, the dead load; T, the

deformation load; and Eo, the operatingenvironmental load, and

(ii) Crack control design shall beachieved by limiting the crack widthin concrete subjected to tension or bylimiting the tensile stress in rein-forcing steel and prestressing tendons.

(5) Durability. (i) Materials, design,construction procedures, and qualitycontrol shall be such as to produce sat-isfactory durability of platforms in amarine environment, and

(ii) The following items shall be con-sidered in the four zones of exposure(see § 250.906(c)(5) of this part):

(A) Submerged zone—chemical dete-rioration of the concrete, corrosion ofthe reinforcement and hardware, andabrasion of the concrete;

(B) Splash zone—freeze-thaw dura-bility, corrosion of the reinforcementand hardware, the chemical deteriora-tion of the concrete, and fire hazards;

(C) Atmospheric zone—freeze-thawdurability, corrosion of reinforcementand hardware, and fire hazards; and

(D) Ice zone—mechanical deteriora-tion resulting from the abrasive actionof moving ice.

(6) Fatigue. Platforms for which fa-tigue is a probable mode of failureshall be designed to limit the effects ofcumulative material fatigue. The ef-fects of fatigue induced by normalstress and those resulting from shearand bond stress shall be considered.Particular attention shall be given tosubmerged areas subjected to the low-cycle, high-stress components of theanticipated loading history. If an anal-ysis of the fatigue life is performed inlieu of employing other methods to ob-viate the possibility of fatigue damage,the calculated fatigue life of the plat-form shall be at least twice the designlife (see § 250.906(c)(1) of this part).

(d) Analysis and design—(1) General. (i)The analysis of platforms shall be pur-sued under the assumptions of linearlyelastic materials and linearly elasticstructural behavior, except as listed inparagraphs (d)(1) (ii) and (iii) of thissection.

(ii) The inelastic behavior of con-crete, based on the true variation ofthe modulus of elasticity with stress,shall be taken into account wheneverits effect reduces the strength of theplatform.


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(iii) The geometric nonlinearities andthe effect of initial deviation of theplatform from the design geometryshall be taken into account whenevertheir effects reduce the strength of theplatform.

(iv) Where appropriate, dynamic ef-fects shall be taken into account. Thedynamic response shall be determinedby a defensible method that includesthe effects of the foundation—platforminteraction and the effective mass ofthe surrounding water.

(v) The material properties used inthe analysis shall be based on actuallaboratory tests or shall follow the ap-propriate sections of ACI 318.

(2) Analysis of frames. The analysis offrames shall be performed by a defen-sible method of structural mechanics.The buckling strength of the frameshall be assessed, and the safetyagainst buckling failure shall be en-sured to a degree consistent with therequirements in paragraphs (c)(2) and(c)(3) of this section.

(3) Analysis of plates, shells, and foldedplates. The buckling strength of theseplates shall be determined and a suffi-cient safety margin against instabilityshall be ensured.

(4) Determination of deflections. Deflec-tions shall be determined by a defen-sible method. In addition to the imme-diate (instantaneous) deflections, thelong-term deflections due to creepshall be accounted for.

(5) Analysis and design for bending andaxial loads. The provisions of ACI 318shall apply to the analysis and designof members subject to flexure or axialloads or to combined flexure and axialloads.

(6) Analysis and design for shear andtorsion. The provisions of ACI 318 shallapply to the analysis and design ofmembers subject to shear or torsion orto combined shear and torsion.

(7) Analysis and design of prestressedconcrete. The analysis and design ofprestressed concrete members andstructures shall comply with ACI 318.In addition, the safety requirements ofparagraph (c) of this section shall besatisfied.

(8) Details of reinforcement andprestressing systems. Details of rein-forcement and prestressing systemsshall conform to the requirements of

ACI 318 with special attention given tothe fatigue resistance and ultimate be-havior of offshore structures.

(9) Minimum reinforcement. The min-imum amount of reinforcement shallconform to the requirements of ACI318. Additionally, sufficient reinforce-ment shall be provided to control crackgrowth, especially at surfaces exposedto severe hydraulic pressures.

(10) Concrete cover of reinforcement andprestressing tendons. The concrete coverof reinforcement and prestressing ten-dons shall be sufficient to provide forcorrosion protection of the steel.

(11) Seismic analysis. A dynamic anal-ysis shall be performed to determinethe response of the platform to design-earthquake loading. The platform shallbe designed to withstand this loadingwithout damage. In addition, a duc-tility check shall also be performed toensure that the platform has sufficientductility to experience deflectionsmore severe than those resulting fromthe design-earthquake loading withoutthe collapse of the platform or its foun-dation or any primary structural com-ponent.

(12) Seismic design. The design ofstructural members and details of plat-forms subjected to seismic loadingshall ensure maximum ductility atcritically loaded sections.

(e) Construction—(1) General. (i) Con-struction methods and workmanshipshall conform to the provisions of ACI318 and to the following requirements.

(ii) At each stage of construction,i.e., fabrication, initial flotation, tow-ing, and installation in situ, the forcesacting on the platform shall be keptwithin the safety limits listed in para-graph (c) of this section. Appropriatestatic and/or dynamic analysis shall beperformed for the operating loadingconditions of each of the constructionoperations mentioned above. Buoyancyand stability shall be considered duringall phases of construction.

(2) Mixing, placing, and curing of con-crete. (i) Mixing of concrete must con-form to the requirements of ACI Stand-ard 318 and ASTM Standard C 94/C 94M–99, Standard Specification for Ready-Mixed Concrete;

(ii) When concreting in cold weather,the temperature of the fresh concreteshall be maintained sufficiently above


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freezing until the process of hardeningis well in progress;

(iii) In hot weather, the temperatureof the fresh concrete shall be con-trolled so that it does not impair at-tainment of the desired strength anddurability;

(iv) The methods for curing concreteshall ensure maximum compressiveand tensile strength, durability, and aminimum of cracking; and

(v) The location and workmanship ofconstruction joints shall not impairthe strength, crack resistance, andwatertightness of the platform.

(3) Reinforcement. (i) Reinforcementshall be free from loose rust, grease,oil, deposits of salt, or any other mate-rial that may adversely affect thestrength, durability, or bond of the re-inforcement. The specified cover of re-inforcement shall be maintained accu-rately. The cutting, bending, and fixingof reinforcement shall ensure that it iscorrectly positioned and rigidly held.

(ii) The welding of reinforcementshall conform to the requirements ofAWS publication, AWS D1.4, StructuralWelding Code— Reinforcing Steel.

(4) Prestressing tendons, ducts, andgrouting. (i) Steps shall be taken to en-sure that the achieved prestressingforce is that specified in the design.

(ii) Tendons and ducts shall be in acondition that ensures the requiredstrength, durability, and bond.

(iii) The grouting procedures shallproduce the required bond strength ofthe tendons and provide permanentcorrosion protection for the tendons.Anchorages shall also be protected ade-quately against corrosion.

[53 FR 10690, Apr. 1, 1988, as amended at 61FR 60025, Nov. 26, 1996. Redesignated andamended at 63 FR 29479, 29486, May 29, 1998; 65FR 15864, Mar. 24, 2000]

§ 250.909 Foundation.(a) General—(1) Coverage. Soil inves-

tigations, design considerations for thesupporting soil, and the influence ofthe soil on the foundation structureare addressed in this section, includingcriteria for the strength and deforma-tion characteristics of the foundationemployed by both pile founded andgravity platforms.

(2) Guidelines. (i) The degree of designconservatism shall reflect prior experi-

ence under similar conditions, themanner and extent of data collection,the scatter of design data, and the con-sequences of failure;

(ii) For cases where the limits of ap-plicability of any method of calcula-tion employed are not well defined orwhere the soil characteristics are quitevariable, the use of more than onemethod of calculation or a parametricstudy of the sensitivity of the impor-tant design variables shall be consid-ered, and

(iii) A listing of design parameters,necessary calculations, and test resultsshall be retained by the designer.

(b) Site investigation—(1) General. (i)The actual extent, depth, and degree ofprecision to be obtained in the site in-vestigation program shall reflect thetype and intended use of the platform,characteristics of the site, similarityof the area based on previous site stud-ies or platform installations as well asthe consequences of a failure of thefoundation. The site investigation pro-gram shall generally consist of threemajor phases as follows:

(A) Shallow hazards (see paragraph(b)(2) of this section) to obtain relevantgeophysical data.

(B) Geological survey (see paragraph(b)(3) of this section) to obtain data ofa regional nature concerning the site.

(C) Subsurface investigation andtesting (see paragraph (b)(4) of this sec-tion) to obtain the necessarygeotechnical data. The results of theseinvestigations shall be the basis for theadditional site related studies specifiedin paragraph (b)(5) of this section.

(ii) A complete site-investigationprogram shall be furnished for eachplatform. The positioning devices usedon the vessel employed in the site in-vestigation as well as those used dur-ing the installation of the platformshall have sufficient accuracy to en-sure that the data obtained are perti-nent to the actual final location of theplatform.

(2) Shallow hazard survey. (i) Con-sistent with the objectives of para-graph (b)(1)(i) of this section, a high-resolution or acoustic-profiling surveyshall be performed to obtain informa-tion on the conditions existing at andnear the surface of the seafloor; and


359


(ii) The information to be obtainedfrom this survey shall include the fol-lowing items, as appropriate, for theplanned platform:

(A) Contours of the sea bed,(B) Presence of any seafloor surface

or near-surface anomaly or obstruc-tions which would adversely affectplatform installation at the site,

(C) Shallow faults,(D) Gas seeps,(E) Slump blocks,(F) Occurrence of shallow gas, and(G) Ice scour of seafloor sediments.(3) Geological survey. (i) Background

geological data shall be obtained toprovide regional information that canaffect the design and siting of the plat-form. The data shall be considered inplanning the subsurface investigation.

(ii) Where necessary, the seismic ac-tivity at the site shall be assessed.Fault zones, the extent and geometryof faulting, and attenuation effects ofconditions in the vicinity of the siteshall be identified.

(iii) For platforms located in a pro-ducing area, the possibility of seafloorsubsidence shall be considered.

(4) Subsurface investigation and testing.(i) The primary objective of the sub-surface investigation and testing pro-gram shall be the attainment of reli-able geotechnical data concerning thestratigraphic and engineering prop-erties of the soil. These data shall beused to properly design the foundationto the desired structural safety level.

(ii) The subsurface investigation andsoil testing program shall consist ofadequate in situ testing, boring, andsampling to examine all important soiland rock strata. The testing programshall reveal the necessary strength,classification, and deformation prop-erties of the soil. Further tests, asneeded, shall describe the dynamiccharacteristics of the soil.

(iii) At least one borehole having aminimum depth of the anticipatedlength of the pile plus a zone of influ-ence shall be drilled at the installationsite for a pile-supported platform. Pre-viously gathered borehole data may beused on a case-by-case basis, when ap-proved by the Regional Supervisor. Thezone of influence shall be sufficient toensure that punch through failures willnot occur. Additional boreholes of a

lesser depth shall be required by theRegional Supervisor if discontinuitiesin the soil are indicated to exist in thearea of the platform.

(iv) For a gravity-type platform foun-dation, the required depth of the bore-hole shall be equal to at least the depthof the zone of influence which thestructure imposes on the supportingsoil. Where possible, in situ tests shallbe performed to a depth that will in-clude the anticipated shearing failurezone.

(v) When samples from the field aresent to a laboratory for further testing,they shall be packed carefully and ac-curately labeled, and the results of vis-ual inspections shall be recorded.

(vi) A summary report showing theresults of the soil testing programshall be prepared. The report shall de-scribe briefly the various field and lab-oratory test methods employed andshall indicate the applicability of thesemethods as they relate to the qualityof the sample, the type of soil, and theanticipated design application.

(vii) The engineering properties ofthe soil to be used in the design shallbe listed for each stratum. The selecteddesign properties shall specify the un-certainties inherent in the overall test-ing program and in the reliability andapplicability of the individual testmethods.

(5) Additional requirements. Based onthe results of the overall site investiga-tion program, studies shall be per-formed, as applicable, to assess the fol-lowing effects of the installed plat-form:

(i) Scouring potential of the seafloor,(ii) Hydraulic instability and the oc-

currence of sand waves,(iii) Instability of slopes in the area

where the platform is to be placed,(iv) Liquefaction and/or possible re-

duction of soil strength due to in-creased pore pressures, and

(v) Degradation of subsea permafrostlayers.

(c) Foundation design requirements—(1)General. (i) The loadings used in the de-sign of the foundation shall includethose defined in paragraph (c)(6)(ii) ofthis section.

(ii) Foundation displacements shallbe evaluated to ensure that they are


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30 CFR Ch. II (7–1–01 Edition)§ 250.909

within limits that do not impair the in-tended function and safety of the plat-form.

(iii) The soil and the platform shallbe considered as an interactive system,and the results of the analysis as re-quired in paragraphs (c)(2) through(c)(6) of this section shall be evaluatedfrom this point of view.

(2) Cyclic loading effects. Evaluation ofthe short-term and long-term effects ofcyclic loading with respect to changesin soil characteristics, whether causedby conditions during installation, seis-mic activity, or storms, shall be ac-complished by using defensible meth-ods.

(3) Scour. (i) For unprotected founda-tions, the depth and lateral extent ofscouring, as determined in the site in-vestigation program, shall be ac-counted for in design; and

(ii) If scour is not accounted for indesign, either effective protection shallbe furnished soon after the installationof the platform or frequent visual in-spection shall be carried out, particu-larly after major storms.

(4) Settlements and displacements. (i)Based on the type and function of theplatform, tolerable limits shall be es-tablished for settlements and lateraldeflections. Due consideration shall begiven to the effect of these movementson risers, pilings, and other compo-nents which interact with the plat-form;

(ii) Maximum allowable values ofplatform movements, as limited bythese structural considerations oroverall platform stability, shall be con-sidered in the design.

(5) Dynamic considerations. (i) For dy-namic-loading conditions, a defensiblemethod shall be employed to simulatethe interactive effects between the soiland the platform, and

(ii) The evaluation of the dynamic re-sponse of the platform shall accountfor, as appropriate, the nonlinear andinelastic characteristics of the soil, thepossible deterioration of strength, theincreased or decreased damping due tocyclic soil loading, and the influence ofnearby platforms.

(6) Loading conditions. (i) Loadingsproducing the worst effects on thefoundation during and after installa-tion shall be addressed; and

(ii) In-place platform loadings to bechecked shall include at least those re-lating to both the operating and designenvironmental conditions, combined inaccordance with the following:

(A) Operating environmental condi-tions with dead and live loads appro-priate to the function and operation ofthe platform,

(B) Design environmental conditionswith dead and live loads appropriate tothe function and operation of the plat-form, and

(C) Design environmental conditionswith dead and minimum live loads ap-propriate to the function and operationof the platform.

(d) Pile foundations—(1) General. Thefollowing requirements apply to pile-founded platforms. Pertinent parts ofthese requirements dealing with steeldesign shall be consulted regarding thedesign of the steel piles.

(i) In the design of individual pilesand piles in a group, the effects ofaxial, bending, and lateral loads shallbe addressed.

(ii) The design of a pile shall reflectthe interactive behavior between thesoil and the pile, between the pile andthe platform, and between piles in agroup.

(iii) Methods of pile installation shallbe consistent with the type of soil atthe site and the installation equipmentavailable. If unexpectedly high-drivingresistance or other conditions lead to afailure of the pile to reach the desiredpenetration, the pile’s capacities shallbe reevaluated by considering the ac-tual installation situation.

(iv) Pile driving shall be performedand supervised by qualified and experi-enced personnel. Driving records whichinclude such information asblowcounts and estimated hammer per-formance and stoppages shall be re-tained.

(v) Where necessary, the effects ofbottom instability in the vicinity ofthe platform shall be assessed.

(2) Axial piles. (i) For piles in com-pression, the axial capacity shall beconsidered to consist of the skin fric-tion, Qf, developed along the length ofthe pile and the end bearing, Qp, at thetip of the pile. The various parametersneeded to evaluate Qf and Qp shall be


361


predicted by using a defensible analyt-ical method that employs reliably ob-tained soil data consistent with theprediction method selected. The ac-ceptability of any method used to pre-dict the components of pile resistanceshall be demonstrated by showing sat-isfactory performance of the methodunder conditions similar to those exist-ing at the actual site.

(ii) The results of the dynamic piledriving analysis alone shall not be usedto predict the axial load capacity of apile.

(iii) For piles driven through clay,the estimated skin friction developedover any increment of the pile surfaceshall not exceed the shear strength ofthe clay.

(iv) The capacity of the internal plugof an open-ended pile shall be consid-ered since it may limit the estimatedend bearing to the pile.

(v) When combining side friction andend-bearing effects in determiningaxial pile capacity, the load deflectionresponse of the soil-pile system shallbe addressed.

(vi) For piles subjected to pulloutloads, the contribution of the end re-sistance of the pile to its axial capacityshall not be considered. The possiblevariation of predicted pile-skin frictionbetween the compressive and tensilemodes of the axial-pile loading shall beconsidered.

(3) Laterally loaded piles. (i) In evalu-ating the pile’s behavior when actedupon by lateral loadings, the combinedload deflection characteristics of thesoil and the pile and the pile and theplatform shall be addressed.

(ii) The representation of the soil’slateral displacement when it is sub-jected to lateral loads shall adequatelyreflect the deterioration of the lateralload capacity when the soil is subjectedto cyclic loading.

(iii) The description of the lateralload versus displacement characteris-tics for the various soil strata shall bebased on constitutive data obtainedfrom suitable soil tests. The use of em-pirical methods to provide the descrip-tion of the soil’s lateral response shallbe permitted if such methods are docu-mented.

(iv) Where applicable, the rapidly de-teriorating cyclic lateral load capacity

of stiff clays, especially those exhib-iting the presence of a secondary struc-ture, shall be addressed in the design.

(v) Calculation of pile deflection andstress induced by lateral loads shall ac-count for the nonlinear interaction be-tween the soil and the pile.

(4) Pile groups. Where applicable, theeffects of close spacing on the load anddeflection characteristics of pilegroups shall be determined. The allow-able load for a group, both axial andlateral, shall not exceed the sum of theapparent individual pile allowableloads.

(5) Plastic analysis. When the designof a platform is based on the formationcollapse mechanisms associated with aplastic analysis method, influence ofthe soil’s support on the pile shall beaddressed.

(e) Gravity platforms foundations—(1)General. The following requirementsapply to soil foundations for gravityplatforms. Section 250.138 of this partshall be consulted regarding the designof the base slab.

(i) The influence of hydraulic andslope instability, if any, shall be deter-mined for the structural loading casesthat include the design environmentalloading.

(ii) The effects of adjacent platformsand the variation of soil properties inthe horizontal direction shall be con-sidered, as appropriate.

(iii) The stability of the foundationwith regard to bearing and sliding fail-ure modes shall be investigated by em-ploying the soil shear strengths deter-mined with consideration of para-graphs (b)(4) and (c)(2) of this section.

(iv) When an underpressure or over-pressure is experienced by the seafloorunder the platform, provisions shall bemade to prevent piping that could im-pair the integrity of the foundation.

(v) Initial, consolidation, and sec-ondary settlements, as well as perma-nent horizontal displacements, shall bedetermined.

(vi) If the intended site is not level,the predicted tilt of the overall plat-form shall be based on the average bot-tom slope of the seafloor and the toler-ance of the measuring device used inthe site-investigation program. Dif-ferential settlement shall also be cal-culated and the tilting of the platform


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caused by this settlement shall be com-bined with the predicted structural tiltof the overall platform. Any increasedloading effects caused by tilting of theplatform shall be addressed in stabilityrequirements specified for the founda-tion.

(2) Stability. (i) The bearing capacityand lateral resistance shall be cal-culated by considering the most unfa-vorable combination of loads. Thelong-term redistribution of bearingpressures under the base slab shall beconsidered to ensure that the max-imum edge pressures are used in thedesign of the base.

(ii) The lateral resistance of the plat-form shall be investigated consideringvarious potential shearing planes. Thepresence of any soft layers shall re-quire special consideration.

(iii) Calculations for overturning mo-ment and vertical forces induced by thepassage of a wave shall include thevertical pressure distribution acrossthe top of the foundation and along theseafloor. The foundation shall not losecontact with the soil due to uplift cre-ated by the maximum overturning mo-ment.

(iv) The capacity of the foundation toresist a deep-seated bearing failureshall be analyzed.

(v) Where present, the additional ef-fects of penetrating walls or skirts thattransfer vertical and lateral loads tothe soil shall be investigated for theircontribution to bearing load capacityand lateral resistance.

(3) Soil reaction on the platform. (i) Forconditions during and after installa-tion, the reaction of the soil against allstructural members seated on or pene-trating into the seafloor shall be deter-mined and accounted for in the designof these members.

(ii) The distribution of soil reactionsshall be based on the results obtainedin paragraphs (b)(2) and (b)(4) of thissection, and the calculations of soil re-actions shall account for any deviationfrom a plane surface, the load-deflec-tion characteristics of the soil, and thegeometry of the platform base.

(iii) Where applicable, effects of localsoil stiffening, nonhomogeneous soilproperties, and boulders and other ob-structions shall be addressed in the de-sign. During installation, the possi-

bility of local contact pressures due toirregular contact between the base andthe seafloor shall be considered. Con-tact pressures shall be added to the hy-drostatic pressure.

(iv) The penetration resistance ofstructural elements projecting into theseafloor below the foundation structureshall be analyzed. The design of theballasting system shall reflect uncer-tainties associated with achieving therequired penetration of the platform.

§ 250.910 Marine operations.

(a) General—(1) Marine operationsmeans all activities necessary for thetransportation and installation of aplatform from the time it enters themarine environment until it is fixed inplace at its final destination. Marineoperations generally include such ac-tivities as follows:

(i) Lifting and mooring,(ii) Loadout or initial flotation,(iii) Fabrication afloat,(iv) Towing,(v) Launching and uprighting,(vi) Submergence,(vii) Pile installation, and(viii) Final field erection.(2) The requirements of this section

apply to all platforms covered by thissubpart, regardless of structural typeor material of construction.

(b) Objective. The structural strengthand integrity of a platform shall not bereduced or otherwise jeopardized by theperformance of the activities requiredto install the platform on site. Thetype and magnitude of loads and loadcombinations to which a platform willbe exposed during marine operationsshall be the subject of an analysis pur-suant to paragraph (c) of this section,except where the use of proven andwell-controlled methods of fabricationand installation are proposed and justi-fied. Sufficient equipment shall be pro-vided to ensure installation of the plat-form in a safe and well-controlled man-ner.

(c) Analysis. (1) Analyses shall be per-formed to determine the type and mag-nitude of the loads and load combina-tions to which the platform will be ex-posed during the performance of ma-rine operations.


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(2) Analyses shall be performed to en-sure that the structural design is suffi-cient to withstand the type and mag-nitude of the loads and load combina-tions determined, in accordance withparagraph (c)(1) of this section, with-out loss or degradation of structuralintegrity.

(3) Analyses shall be performed to en-sure that the platform or its means ofsupport has sufficient hydrostatic sta-bility and reserve buoyancy to allowfor successful execution of all phases ofmarine operations.

§ 250.911 Inspection during construc-tion.

(a) General—(1) Coverage. All pile-sup-ported and gravity platforms coveredby this subpart shall be inspected dur-ing the construction phase. Additionalrequirements for steel pile-supportedplatforms are contained in paragraph(b) of this section, and additional re-quirements pertaining to concrete-gravity platforms are contained inparagraph (c) of this section. Thephases of construction subject to in-spection include material manufacture,fabrication, loadout, transportation,positioning, installation, and final fielderection.

(2) Objective. Inspections during con-struction are to verify that the plat-form is constructed in accordance withthe approved construction plan. Anyunusual or innovative application ofmaterials or methods of constructionnot adequately covered by the require-ments of this section shall receive spe-cial attention during compliance in-spections relevant to its effect on theintegrity of the platform.

(3) Remedial action. If construction in-spection results reveal that materials,procedures, or workmanship deviatesignificantly from the approved design,remedial action shall be taken.

(4) Identification of materials. The ori-gin of materials used in the platformand the results of relevant materialtests for all significant structural ma-terials shall be retained and madereadily available for inspection byMMS representatives during all stagesof construction. Records shall be keptof the locations throughout the plat-form of the various heat numbers forsuch materials.

(b) Steel pile-supported platforms—(1)Scope. Inspections of steel pile-sup-ported platforms shall address the fol-lowing topics, as appropriate:

(i) Material quality and forming,(ii) Welder and welding procedure

qualifications,(iii) Weld inspection,(iv) Tolerances and alignments, and(v) Corrosion-control systems.(2) Material quality and forming. In-

spection shall verify that all materialsemployed are of good quality and suit-able for their intended service as speci-fied in the approved design. Inspectionshall ensure the compliance of mate-rials to the relevant material stand-ards selected in the design of the plat-form. Inspection shall ensure thatformed members satisfy the dimen-sional tolerances listed in the design.

(3) Welder and welding-procedure quali-fications. (i) Welders shall be tested andpossess a current welder’s certification.

(ii) All welding procedures to be em-ployed shall be tested and certified forthe production of satisfactory welds.Welding procedures previously testedand certified shall be consideredprequalified.

(4) Weld inspection. (i) Inspectionshall include, but not be limited to,visual inspection of all welds and rep-resentative magnetic particle or dyepenetrant inspection of welds of WeldClasses A and B materials (see§ 250.907(a)(4) of this part) not subjectedto ultrasonic or radiographic inspec-tion. The extent of ultrasonic or radio-graphic inspection shall be specifiedand shall emphasize, but not be con-fined to, welds of Weld Class A mate-rials.

(ii) The extent and methods of in-spection shall be consistent with theclassification of applications (see§ 250.907(a)(4) of this part) of the areabeing examined.

(iii) Any welding not meeting the ac-ceptance criteria specified in the in-spection plan shall be rejected and ap-propriate remedial action taken.

(5) Tolerances and alignments. Overalldimensional tolerances, forming toler-ances, and local alignment tolerancesshall be commensurate with those con-sidered in developing the structural de-sign. Inspections shall ensure that thedimensional tolerance criteria are


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being met. Out of roundness of struc-tural elements for which buckling isthe anticipated mode of failure shallreceive individual inspection.

(6) Corrosion-control systems. Corro-sion-control systems employed on theplatform shall be inspected to ensurethat they are installed as specified inthe approved design. Inspection shallensure that proper protection againstgalvanic effects, especially in locationswhere nonferrous materials are used inconjunction with steel, has been pro-vided in the corrosion-control system.

(7) Additional inspection items. (i) Theprovisions of paragraphs (b)(2) through(b)(6) of this section relate only to mat-ters directly affecting the onshore con-struction phases of the platform. Otheritems relating to the onshore construc-tion site and the construction phasesfrom loadout to final erection shallalso be performed.

(ii) The construction site shall be in-spected to ensure that adequate consid-eration has been given to the followingitems:

(A) Support of the platform duringconstruction,

(B) Employment of a sufficient num-ber of certified welders and inspectorsto maintain an adequate quality ofwork, and

(C) Weathertight storage of weldingconsumables under conditions specifiedby their manufacturers.

(iii) Inspection shall verify that thefollowing operations have been accom-plished in a manner conforming to ap-proved plans or drawings:

(A) Loadout,(B) Tie down,(C) Positioning at the site,(D) Installation (see § 250.909(d)(1)(iv)

of this part for piles), and(E) Final field erection.(iv) To determine if overstressing of

the platform during transportation hasoccurred, towing records shall be re-viewed to ascertain if conditions dur-ing towing operations exceeded thoseemployed in the analyses required by§ 250.910(c) of this part.

(v) When the inspections indicatethat overstressing has occurred duringloadout, transportation, or installa-tion, the affected parts of the platformshall be surveyed to determine the ex-tent of actual damage, if any. Where

necessary, a reevaluation of the struc-tural capacity shall be carried out,considering the results of the survey.

(8) Records. The following construc-tion records shall be compiled, re-tained, and made available for inspec-tion by MMS representatives:

(i) Mill certificates,(ii) Weld-procedure qualification

records,(iii) Weld inspection records,(iv) Dimensional tolerance reports,(v) Towing records, and(vi) Pile driving records.(c) Concrete-gravity platforms—(1)

Scope. Inspection of concrete-gravityplatforms shall address the followingtopics, as appropriate:

(i) Preparation for concrete produc-tion and placement;

(ii) Batching, mixing, and placingconcrete;

(iii) Form removal and concrete cur-ing;

(iv) Pretensioning and grouting;(v) Joints; and(vi) Finished concrete.(2) Preparation for concrete production

and placement. (i) Inspection shall en-sure that the pertinent physical prop-erties of cement, reinforcing steel,prestressing tendons, and appur-tenances comply with those specifiedin the approved design.

(ii) Forms and shoring supporting theforms shall be inspected to ensure thatthey are adequate in number and typeand are located correctly.

(iii) The dimensional tolerances ofthe forms shall be inspected to ensurethat the finished dimensional toler-ances are comparable to those allowedfor in the approved design.

(iv) Reinforcing steel, prestressingtendons, post-tensioning ducts, anchor-ages, and any other embedded steelshall be inspected, as appropriate, forsize, bending, spacing, location, firm-ness of installation, surface condition,vent locations, proper duct coupling,and duct capping.

(3) Batching, mixing, and placing con-crete. (i) Inspections shall be performedto ensure that the procedures for theproduction and placement of concreteprovide a well-mixed and well-com-pacted concrete. The procedures shallalso limit segregation, loss of material,


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contamination, and premature initialset during all operations.

(ii) Inspection shall verify that themix components of each batch of con-crete are properly proportioned andwithin allowable variations specified inthe approved design. Inspection shallensure that the water/cement ratio ofeach batch is within the limit specifiedin § 250.908(b)(7) of this part.

(iii) Aggregate gradation, cleanli-ness, moisture content, and unitweight shall be tested. The frequencyof testing shall be determined takinginto account the uniformity of the sup-ply source, volume of concrete used,and variations of atmospheric condi-tions.

(iv) Mix water shall be tested for pu-rity following specified methods andschedules.

(v) Testing during the production ofconcrete shall be performed to mon-itor, as a minimum, the following con-crete qualities:

(A) Consistency,(B) Air content, and(C) Strength.(4) Form removal and concrete curing.

(i) Inspection shall ensure that formsand form supports are not removeduntil the platform has attained suffi-cient strength to bear its own weight,construction loads, and anticipated en-vironmental loads without undue de-formation and that they are removedaccording to schedule.

(ii) Inspection shall ensure that cur-ing of concrete is accomplished in ac-cordance with the provisions of a pre-determined procedure.

(iii) Where the construction proce-dures require the submergence of re-cently placed concrete, inspection shallensure that methods for protecting theconcrete from the effects of salt waterare properly executed.

(5) Pretensioning and grouting. (i) In-spection shall verify that the sequenceof tendon tensioning and the resultingelongation and force are in accordancewith provisions specified in the ap-proved design.

(ii) Pretensioning or post-tensioningstress shall be determined by meas-uring both tendon elongation and ten-don force. Inspection shall verify thatthe variation of measurements doesnot exceed a specified amount.

(iii) Inspection shall verify thatgrout mix proportions and ambientconditions during mixing are in accord-ance with provisions designated in theapproved design. Tests for grout, vis-cosity expansion, bleeding, compres-sive strength, and setting time shall beperformed to ensure compliance withdesign requirements. Procedures shallbe observed to ensure that ducts arecompletely filled.

(iv) Anchorages shall be inspected toensure that they are located and sizedas specified in the design and are pro-vided with adequate cover to mitigatethe effects of corrosion.

(6) Joints. Where appropriate, leaktesting of construction joints shall beperformed by using specified proce-dures. When deciding which joints toinspect, consideration shall be given tothe hydrostatic head on the subjectjoint during normal operation, the con-sequence of a leak at the subject joint,and the ease of repair once the plat-form is in service.

(7) Finished concrete. (i) The surface ofthe hardened concrete shall be com-pletely inspected for cracks,honeycombing, popouts, spalling, andother surface imperfections.

(ii) The platform shall be examinedby using a calibrated rebound hammeror a similar nondestructive examina-tion device. Inspection shall verify thatthe results of surface inspection, cyl-inder strength test, or nondestructiveexamination are in accordance withthe approved design criteria.

(iii) The completed sections of theplatform shall be checked for compli-ance to specified design tolerances ofthickness and alignment and, to theextent practicable, the location of rein-forcing and prestressing steel and post-tensioning ducts.

(8) Additional inspection items. (i)While the provisions of paragraphs(c)(2) through (c)(7) of this section re-late only to some matters directly af-fecting the onshore or nearshore con-struction phases of the platform, otheritems relating to such phases and fromloadout to final erection shall also beconsidered.

(ii) Inspection shall ensure that ade-quate consideration has been given thefollowing items:


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(A) Support of the structure duringconstruction,

(B) Employment of a sufficient num-ber of competent workmen and inspec-tors to maintain an adequate quality ofwork,

(C) Storage of cement andprestressing tendons in weathertightareas,

(D) Storage of admixtures andepoxies according to manufacturers’specifications, and

(E) Storage of aggregates to limitsegregation, contamination by delete-rious substances, and moisture vari-ations within the stockpile.

(iii) Inspection shall verify that thefollowing operations, as applicable tothe planned platform, have been ac-complished in a manner conforming toapproved plans or drawings developedfor these operations:

(A) Loadout,(B) Towing arrangements,(C) Positioning at the site,(D) Installation, and(E) Final field erection.(iv) To determine if overstressing of

the platform during transportation hasoccurred, towing records shall be re-viewed to ascertain if conditions dur-ing the towing operations exceededthose employed in the analyses re-quired by § 250.910(c) of this part.

(9) Records. The following construc-tion records shall be compiled, re-tained, and made available for inspec-tion by MMS representatives:

(i) Material certificates and test re-ports;

(ii) Tensioning and grouting records;(iii) Concreting records including

weight, moisture content, mix propor-tions, test methods and results, ambi-ent conditions during the pour, andtest equipment calibration data;

(iv) Deviations from design or fab-rication specifications and repairs car-ried out;

(v) Towing records; and(vi) Data on initial structural settle-

ments.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11,1988. Redesignated and amended at 63 FR29479, 29486, May 29, 1998; 64 FR 9065, Feb. 24,1999]

§ 250.912 Periodic inspection andmaintenance.

(a) All platforms installed in the OCSshall be inspected periodically in ac-cordance with the provisions of API RP2A, section 14, Surveys. However, use ofan inspection interval which exceeds 5years shall require prior approval bythe Regional Supervisor. Proper main-tenance shall be performed to assurethe structural integrity of the platformas a workbase for oil and gas oper-ations.

(b) A report shall be submitted annu-ally on November 1 to the Regional Su-pervisor stating which platforms havebeen inspected in the preceding 12months, the extent and area of inspec-tion, and the type of inspection em-ployed, i.e., visual, magnetic particle,ultrasonic testing. A summary of thetesting results shall be submitted indi-cating what repairs, if any, were need-ed and the overall structural conditionof the platform.


§ 250.913 Platform removal and loca-tion clearance.

(a) The lessee shall remove all struc-tures in a manner approved by the Re-gional Supervisor to assure that the lo-cation has been cleared of all obstruc-tions to other activities in the area.

(b) All platforms (including casing,wellhead equipment, templates, andpiling) shall be removed by the lesseeto a depth of at least 15 feet below theocean floor or to a depth approved bythe Regional Supervisor based upon thetype of structure or ocean-bottom con-ditions.

(c) The lessee shall verify by appro-priate means that the location hasbeen cleared of all obstructions. Theresults of the location clearance surveyshall be submitted to the Regional Su-pervisor by means of a letter from thecompany performing the work certi-fying that the area was cleared of allobstructions, the date the work wasperformed, the extent of the area sur-veyed, and the survey method used.


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§ 250.914 Records.

The lessee shall compile, retain, andmake available to Minerals Manage-ment Service representatives for thefunctional life of all platforms, the as-built structural drawings, the designassumptions and analyses, a summaryof the nondestructive examinationrecords, and the inspection resultsfrom platform inspections required by§ 250.912 of this part.


Subpart J—Pipelines and PipelineRights-of-Way

§ 250.1000 General requirements.

(a) Pipelines and associated valves,flanges, and fittings shall be designed,installed, operated, maintained, andabandoned to provide safe and pollu-tion-free transportation of fluids in amanner which does not unduly inter-fere with other uses in the Outer Conti-nental Shelf (OCS).

(b) An application shall be submittedto the Regional Supervisor and ap-proval obtained prior to the installa-tion, modification, or abandonment ofa pipeline which qualifies as a leaseterm pipeline (see § 250.1001, Defini-tions) and prior to the installation of aright-of-way pipeline or the modifica-tion or relinquishment of a pipelineright-of-way.

(c)(1) Department of the Interior(DOI) pipelines, as defined in § 250.1001,must meet the requirements in§§ 250.1000 through 250.1008.

(2) A pipeline right-of-way grantholder must identify in writing to theRegional Supervisor the operator ofany pipeline located on its right-of-way, if the operator is different fromthe right-of-way grant holder.

(3) A producing operator must iden-tify for its own records, on all existingpipelines located on its lease or right-of-way, the specific points at which op-erating responsibility transfers to atransporting operator.

(i) Each producing operator must, ifpractical, durably mark all of itsabove-water transfer points by April 14,1999 or the date a pipeline begins serv-ice, whichever is later.

(ii) If it is not practical to durablymark a transfer point, and the transferpoint is located above water, then theoperator must identify the transferpoint on a schematic located on the fa-cility.

(iii) If a transfer point is locatedbelow water, then the operator mustidentify the transfer point on a sche-matic and provide the schematic toMMS upon request.

(iv) If adjoining producing and trans-porting operators cannot agree on atransfer point by April 14, 1999, theMMS Regional Supervisor and the De-partment of Transportation (DOT) Of-fice of Pipeline Safety (OPS) RegionalDirector may jointly determine thetransfer point.

(4) The transfer point serves as a reg-ulatory boundary. An operator maywrite to the MMS Regional Supervisorto request an exception to this require-ment for an individual facility or area.The Regional Supervisor, in consulta-tion with the OPS Regional Directorand affected parties, may grant the re-quest.

(5) Pipeline segments designed, con-structed, maintained, and operatedunder DOT regulations but transferringto DOI regulation as of October 16, 1998,may continue to operate under DOT de-sign and construction requirementsuntil significant modifications or re-pairs are made to those segments.After October 16, 1998, MMS oper-ational and maintenance requirementswill apply to those segments.

(6) Any producer operating a pipelinethat crosses into State waters withoutfirst connecting to a transporting oper-ator’s facility on the OCS must complywith this subpart. Compliance must ex-tend from the point where hydro-carbons are first produced, through andincluding the last valve and associatedsafety equipment (e.g., pressure safetysensors) on the last production facilityon the OCS.

(7) Any producer operating a pipelinethat connects facilities on the OCSmust comply with this subpart.

(8) Any operator of a pipeline thathas a valve on the OCS downstream(landward) of the last production facil-ity may ask in writing that the MMSRegional Supervisor recognize that


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30 CFR Ch. II (7–1–01 Edition)§ 250.1001

valve as the last point MMS will exer-cise its regulatory authority.

(9) A pipeline segment is not subjectto MMS regulations for design, con-struction, operation, and maintenanceif:

(i) It is downstream (generally shore-ward) of the last valve and associatedsafety equipment on the last produc-tion facility on the OCS; and

(ii) It is subject to regulation under49 CFR parts 192 and 195.

(10) DOT may inspect all upstreamsafety equipment (including valves,over-pressure protection devices, ca-thodic protection equipment, and pig-ging devices, etc.) that serve to protectthe integrity of DOT-regulated pipelinesegments.

(11) OCS pipeline segments not sub-ject to DOT regulation under 49 CFRparts 192 and 195 are subject to allMMS regulations.

(12) A producer may request that itspipeline operate under DOT regulationsgoverning pipeline design, construc-tion, operation, and maintenance.

(i) The operator’s request must be inthe form of a written petition to theMMS Regional Supervisor that statesthe justification for the pipeline to op-erate under DOT regulation.

(ii) The Regional Supervisor will de-cide, on a case-by-case basis, whetherto grant the operator’s request. In con-sidering each petition, the RegionalSupervisor will consult with the Officeof Pipeline Safety (OPS) Regional Di-rector.

(13) A transporter who operates apipeline regulated by DOT may requestto operate under MMS regulations gov-erning pipeline operation and mainte-nance. Any subsequent repairs or modi-fications will also be subject to MMSregulations governing design and con-struction.

(i) The operator’s request must be inthe form of a written petition to theOPS Regional Director and the MMSRegional Supervisor.

(ii) The MMS Regional Supervisorand the OPS Regional Director will de-cide how to act on this petition.

(d) A pipeline which qualifies as aright-of-way pipeline (see § 250.1001,Definitions) shall not be installed untila right-of-way has been requested and

granted in accordance with this sub-part.

(e)(1) The Regional Supervisor maysuspend any pipeline operation upon adetermination by the Regional Super-visor that continued activity wouldthreaten or result in serious, irrep-arable, or immediate harm or damageto life (including fish and other aquaticlife), property, mineral deposits, or themarine, coastal, or human environ-ment.

(2) The Regional Supervisor may alsosuspend pipeline operations or a right-of-way grant if the Regional Supervisordetermines that the lessee or right-of-way holder has failed to comply with aprovision of the Act or any other appli-cable law, a provision of these or otherapplicable regulations, or a conditionof a permit or right-of-way grant.

(3) The Secretary of the Interior(Secretary) may cancel a pipeline per-mit or right-of-way grant in accord-ance with 43 U.S.C. 1334(a)(2). A right-of-way grant may be forfeited in ac-cordance with 43 U.S.C. 1334(e).

[53 FR 10690, Apr. 1, 1988. Redesignated andamended at 63 FR 29479, 29486, May 29, 1998; 63FR 34597, June 25, 1998; 63 FR 43880, Aug. 17,1998; 65 FR 46095, July 27, 2000]

§ 250.1001 Definitions.Terms used in this subpart shall have

the meanings given below:DOI pipelines include:(1) Producer-operated pipelines ex-

tending upstream (generally seaward)from each point on the OCS at whichoperating responsibility transfers froma producing operator to a transportingoperator;

(2) Producer-operated pipelines ex-tending upstream (generally seaward)of the last valve (including associatedsafety equipment) on the last produc-tion facility on the OCS that do notconnect to a transporter-operated pipe-line on the OCS before crossing intoState waters;

(3) Producer-operated pipelines con-necting production facilities on theOCS;

(4) Transporter-operated pipelinesthat DOI and DOT have agreed are tobe regulated as DOI pipelines; and

(5) All OCS pipelines not subject toregulation under 49 CFR parts 192 and195.


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DOT pipelines include:(1) Transporter-operated pipelines

currently operated under DOT require-ments governing design, construction,maintenance, and operation;

(2) Producer-operated pipelines thatDOI and DOT have agreed are to be reg-ulated under DOT requirements gov-erning design, construction, mainte-nance, and operation; and

(3) Producer-operated pipelines down-stream (generally shoreward) of thelast valve (including associated safetyequipment) on the last production fa-cility on the OCS that do not connectto a transporter-operated pipeline onthe OCS before crossing into State wa-ters and that are regulated under 49CFR parts 192 and 195.

Lease term pipelines are those pipe-lines owned and operated by a lessee oroperator and are wholly containedwithin the boundaries of a single lease,unitized leases, or contiguous (not cor-nering) leases of that lessee or oper-ator.

Pipelines are the piping, risers, andappurtenances installed for the purposeof transporting oil, gas, sulphur, andproduced water. (Piping confined to aproduction platform or structure iscovered in Subpart H, Production Safe-ty Systems, and is excluded from thissubpart.)

Production facilities means OCS facili-ties that receive hydrocarbon produc-tion either directly from wells or fromother facilities that produce hydro-carbons from wells. They may includeprocessing equipment for treating theproduction or separating it into itsvarious liquid and gaseous componentsbefore transporting it to shore.

Right-of-way pipelines are those pipe-lines which—

(a) Are contained within the bound-aries of a single lease or group unitizedleases but are not owned and operatedby the lessee or operator of that leaseor unit,

(b) Are contained within the bound-aries of contiguous (not cornering)leases which do not have a common les-see or operator,

(c) Are contained within the bound-aries of contiguous (not cornering)leases which have a common lessee oroperator but are not owned and oper-

ated by that common lessee or oper-ator, or

(d) Cross any portion of an unleasedblock(s).

[53 FR 10690, Apr. 1, 1998. Redesignated at 63FR 29479, May 29, 1998, as amended at 63 FR43881, Aug. 17, 1998; 65 FR 46096, July 27, 2000]

§ 250.1002 Design requirements forDOI pipelines.

(a) The internal design pressure forsteel pipe shall be determined in ac-cordance with the following formula:

PS t

DF E T= ×2( )( )

( )( )( )

For limitations see section 841.121 ofAmerican National Standards Institute(ANSI) B31.8 where—P=Internal design pressure in pounds per

square inch (psi).S=Specified minimum yield strength, in psi,

stipulated in the specification underwhich the pipe was purchased from themanufacturer or determined in accord-ance with section 811.253(h) of ANSIB31.8.

D=Nominal outside diameter of pipe, ininches.

t=Nominal wall thickness, in inches.F=Construction design factor of 0.72 for the

submerged component and 0.60 for the risercomponent.

E=Longitudinal joint factor obtained fromTable 841.1B of ANSI B31.8. (See also sec-tion 811.253(d)).

T=Temperature derating factor obtainedfrom Table 841.1C of ANSI B31.8.

(b)(1) Pipeline valves shall meet theminimum design requirements ofAmerican Petroleum Institute (API)Spec 6A, API Spec 6D, or the equiva-lent. A valve may not be used under op-erating conditions that exceed the ap-plicable pressure-temperature ratingscontained in those standards.

(2) Pipeline flanges and flange acces-sories shall meet the minimum designrequirements of ANSI B16.5, API Spec6A, or the equivalent. Each flange as-sembly must be able to withstand themaximum pressure at which the pipe-line is to be operated and to maintainits physical and chemical properties atany temperature to which it is antici-pated that it might be subjected inservice.

(3) Pipeline fittings shall have pres-sure-temperature ratings based on


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30 CFR Ch. II (7–1–01 Edition)§ 250.1003

stresses for pipe of the same or equiva-lent material. The actual burstingstrength of the fitting shall at least beequal to the computed burstingstrength of the pipe.

(c) The maximum allowable oper-ating pressure (MAOP) shall not exceedthe least of the following:

(1) Internal design pressure of thepipeline, valves, flanges, and fittings;

(2) Eighty percent of the hydrostaticpressure test (HPT) of the pipeline; or

(3) If applicable, the MAOP of the re-ceiving pipeline when the proposedpipeline and the receiving pipeline areconnected at a subsea tie-in.

(d) If the maximum source pressure(MSP), exceeds the pipeline’s MAOP,redundant safety devices meeting therequirements of section A9 of API RP14C shall be installed and maintained.Pressure safety valves (PSV) may beused only after a determination by theRegional Supervisor that the pressurewill be relieved in a safe and pollution-free manner. The setting level at whichthe primary and redundant safetyequipment actuates shall not exceedthe pipeline’s MAOP.

(e) Pipelines shall be provided withan external protective coating capableof minimizing underfilm corrosion anda cathodic protection system designedto mitigate corrosion for at least 20years.

(f) Pipelines shall be designed andmaintained to mitigate any reasonablyanticipated detrimental effects ofwater currents, storm or ice scouring,soft bottoms, mud slides, earthquakes,subfreezing temperatures, and otherenvironmental factors.

§ 250.1003 Installation, testing, and re-pair requirements for DOI pipe-lines.

(a)(1) Pipelines greater than 8-5/8inches in diameter and installed inwater depths of less than 200 feet shallbe buried to a depth of at least 3 feetunless they are located in pipeline con-gested areas or seismically active areasas determined by the Regional Super-visor. Nevertheless, the Regional Su-pervisor may require burial of anypipeline if the Regional Supervisor de-termines that such burial will reducethe likelihood of environmental deg-radation or that the pipeline may con-

stitute a hazard to trawling operationsor other uses. A trawl test or diver sur-vey may be required to determinewhether or not pipeline burial is nec-essary or to determine whether a pipe-line has been properly buried.

(2) Pipeline valves, taps, tie-ins,capped lines, and repaired sections thatcould be obstructive shall be providedwith at least 3 feet of cover unless theRegional Supervisor determines thatsuch items present no hazard to trawl-ing or other operations. A protectivedevice may be used to cover an ob-struction in lieu of burial if it is ap-proved by the Regional Supervisorprior to installation.

(3) Pipelines shall be installed with aminimum separation of 18 inches atpipeline crossings and from obstruc-tions.

(4) Pipeline risers installed afterApril 1, 1988, shall be protected fromphysical damage that could result fromcontact with floating vessels. Riserprotection on pipelines installed on orbefore April 1, 1988, may be requiredwhen the Regional Supervisor deter-mines that significant damage poten-tial exists.

(b)(1) Pipelines shall behydrostatically tested with water at astabilized pressure of at least 1.25 timesthe MAOP for at least 8 hours when in-stalled, relocated, uprated, or reac-tivated after being out-of-service formore than 1 year.

(2) Prior to returning a pipeline toservice after a repair, the pipeline shallbe pressure tested with water or proc-essed natural gas at a minimum sta-bilized pressure of at least 1.25 timesthe MAOP for at least 2 hours.

(3) Pipelines shall not be pressuretested at a pressure which produces astress in the pipeline in excess of 95percent of the specified minimum-yieldstrength of the pipeline. A temperaturerecorder measuring test fluid tempera-ture synchronized with a pressure re-corder along with deadweight testreadings shall be employed for all pres-sure testing. When a pipeline is pres-sure tested, no observable leakage shallbe allowed. Pressure gauges and record-ers shall be of sufficient accuracy toverify that leakage is not occurring.

(4) The Regional Supervisor may re-quire pressure testing of pipelines to


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verify the integrity of the system whenthe Regional Supervisor determinesthat there is a reasonable likelihoodthat the line has been damaged orweakened by external or internal con-ditions.

(c) When a pipeline is repaired uti-lizing a clamp, the clamp shall be a fullencirclement clamp able to withstandthe anticipated pipeline pressure.

[53 FR 10690, Apr. 1, 1988; 53 FR 12227, Apr. 13,1988; 57 FR 26997, June 17, 1992. Redesignatedat 63 FR 29479, May 29, 1998]

§ 250.1004 Safety equipment require-ments for DOI pipelines.

(a) The lessee shall ensure the properinstallation, operation, and mainte-nance of safety devices required by thissection on all incoming, departing, andcrossing pipelines on platforms.

(b)(1)(i) Incoming pipelines to a plat-form shall be equipped with a flow safe-ty valve (FSV).

(ii) For sulphur operations, incomingpipelines delivering gas to the powerplant platform may be equipped withhigh- and low-pressure sensors (PSHL),which activate audible and visualalarms in lieu of requirements in para-graph (b)(1)(i) of this section. ThePSHL shall be set at 15 percent or 5 psi,whichever is greater, above and belowthe normal operating pressure range.

(2) Incoming pipelines boarding to aproduction platform shall be equippedwith an automatic shutdown valve(SDV) immediately upon boarding theplatform. The SDV shall be connectedto the automatic- and remote-emer-gency shut-in systems.

(3) Departing pipelines receiving pro-duction from production facilities shallbe protected by high- and low-pressuresensors (PSHL) to directly or indi-rectly shut in all production facilities.The PSHL shall be set not to exceed 15percent above and below the normaloperating pressure range. However,high pilots shall not be set above thepipeline’s MAOP.

(4) Crossing pipelines on productionor manned nonproduction platformswhich do not receive production fromthe platform shall be equipped with anSDV immediately upon boarding theplatform. The SDV shall be operated bya PSHL on the departing pipelines andconnected to the platform automatic-

and remote-emergency shut-in sys-tems.

(5) The Regional Supervisor may re-quire that oil pipelines be equippedwith a metering system to provide acontinuous volumetric comparison be-tween the input to the line at thestructure(s) and the deliveries onshore.The system shall include an alarm sys-tem and shall be of adequate sensi-tivity to detect variations betweeninput and discharge volumes. In lieu ofthe foregoing, a system capable of de-tecting leaks in the pipeline may besubstituted with the approval of theRegional Supervisor.

(6) Pipelines incoming to a subseatie-in shall be equipped with a blockvalve and an FSV. Bidirectional pipe-lines connected to a subsea tie-in shallbe equipped with only a block valve.

(7) Gas-lift or water-injection pipe-lines on unmanned platforms need onlybe equipped with an FSV installed im-mediately upstream of each casing an-nulus or the first inlet valve on thechristmas tree.

(8) Bidirectional pipelines shall beequipped with a PSHL and an SDV im-mediately upon boarding each plat-form.

(9) Pipeline pumps shall comply withSection A7 of API RP 14C. The settinglevels for the PSHL devices are speci-fied in paragraph (b)(3) of this section.

(c) If the required safety equipmentis rendered ineffective or removed fromservice on pipelines which are contin-ued in operation, an equivalent degreeof safety shall be provided. The safetyequipment shall be identified by theplacement of a sign on the equipmentstating that the equipment is renderedineffective or removed from service.

[53 FR 10690, Apr. 1, 1988, as amended at 54FR 50617, Dec. 8, 1989; 56 FR 32100, July 15,1991. Redesignated at 63 FR 29479, May 29,1998]

§ 250.1005 Inspection requirements forDOI pipelines.

(a) Pipeline routes shall be inspectedat time intervals and methods pre-scribed by the Regional Supervisor forindication of pipeline leakage. The re-sults of these inspections shall be re-tained for at least 2 years and be madeavailable to the Regional Supervisorupon request.


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30 CFR Ch. II (7–1–01 Edition)§ 250.1006

(b) When pipelines are protected byrectifiers or anodes for which the ini-tial life expectancy of the cathodic pro-tection system either cannot be cal-culated or calculations indicate a lifeexpectancy of less than 20 years, suchpipelines shall be inspected annuallyby taking measurements of pipe-to-electrolyte potential measurements.

§ 250.1006 Abandonment and out-of-service requirements for DOI pipe-lines.

(a)(1) A pipeline may be abandoned inplace if, in the opinion of the RegionalSupervisor, it does not constitute ahazard to navigation, commercial fish-ing operations, or unduly interferewith other uses in the OCS. Pipelinesto be abandoned in place shall beflushed, filled with seawater, cut, andplugged with the ends buried at least 3feet.

(2) Pipelines abandoned by removalshall be pigged, unless the Regional Su-pervisor determines that such proce-dure is not practical, and flushed withwater prior to removal.

(b)(1) Pipelines taken out-of-serviceshall be blind flanged or isolated with aclosed block valve at each end.

(2) Pipelines taken out-of-service fora period of more than 1 year shall beflushed and filled with inhibited sea-water.

(3) Pipelines taken out-of-serviceshall be returned to service within 5years or be abandoned in accordancewith the requirements of paragraph (a)(1) or (2) of this section.

§ 250.1007 What to include in applica-tions.

(a) Applications to install a leaseterm pipeline or for a pipeline right-of-way grant must be submitted in quad-ruplicate to the Regional Supervisor.Right-of-way grant applications mustinclude an identification of the oper-ator of the pipeline. Each applicationmust include the following:

(1) Plat(s) drawn to a scale specifiedby the Regional Supervisor showingmajor features and other pertinentdata including area, lease, and blockdesignations; water depths; route;length in Federal waters; width ofright-of-way, if applicable; connectingfacilities; size; product(s) to be trans-

ported with anticipated gravity or den-sity; burial depth; direction of flow; X-Y coordinates of key points; and the lo-cation of other pipelines that will beconnected to or crossed by the pro-posed pipeline(s). The initial and ter-minal points of the pipeline and anycontinuation into State jurisdictionshall be accurately located even if thepipeline is to have an onshore terminalpoint. A plat(s) submitted for a pipe-line right-of-way shall bear a signedcertificate upon its face by the engi-neer who made the map that certifiesthat the right-of-way is accurately rep-resented upon the map and that the de-sign characteristics of the associatedpipeline are in accordance with appli-cable regulations.

(2) A schematic drawing showing thesize, weight, grade, wall thickness, andtype of line pipe and risers; pressure-regulating devices (including back-pressure regulators); sensing deviceswith associated pressure-control lines;PSV’s and settings; SDV’s, FSV’s, andblock valves; and manifolds. This sche-matic drawing shall also show inputsource(s), e.g., wells, pumps, compres-sors, and vessels; maximum input pres-sure(s); the rated working pressure, asspecified by ANSI or API, of all valves,flanges, and fittings; the initial receiv-ing equipment and its rated workingpressure; and associated safety equip-ment and pig launchers and receivers.The schematic must indicate the pointon the OCS at which operating respon-sibility transfers between a producingoperator and a transporting operator.

(3) General information as follows:(i) Description of cathodic protection

system. If pipeline anodes are to beused, specify the type, size, weight,number, spacing, and anticipated life;

(ii) Description of external pipelinecoating system;

(iii) Description of internal protec-tive measures;

(iv) Specific gravity of the emptypipe;

(v) MSP;(vi) MAOP and calculations used in

its determination;(vii) Hydrostatic test pressure, me-

dium, and period of time that the linewill be tested;

(viii) MAOP of the receiving pipelineor facility,


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(ix) Proposed date for commencinginstallation and estimated time forconstruction; and

(x) Type of protection to be affordedcrossing pipelines, subsea valves, taps,and manifold assemblies, if applicable.

(4) The application shall include a de-scription of any additional design pre-cautions which were taken to enablethe pipeline to withstand the effects ofwater currents, storm or ice scouring,soft bottoms, mudslides, earthquakes,permafrost, and other environmentalfactors.

(5) The application shall include ashallow hazards survey report and, ifrequired by the Regional Director, anarchaeological resource report thatcovers the entire length of the pipeline.A shallow hazards analysis may be in-cluded in a lease term pipeline applica-tion in lieu of the shallow hazards sur-vey report with the approval of the Re-gional Director. The Regional Directormay require the submission of the dataupon which the report or analysis isbased.

(b) Applications to modify an ap-proved lease term pipeline or right-of-way grant shall be submitted in quad-ruplicate to the Regional Supervisor.These applications need only addressthose items in the original applicationaffected by the proposed modification.

(c) Applications to abandon a leaseterm pipeline or relinquish a right-of-way grant shall be submitted in trip-licate to the Regional Supervisor andshall include the following:

(1) Reason for operation,(2) Proposed procedures,(3) ‘‘As-built’’ location plat,(4) Length in feet of segment to be

abandoned or relinquished, and(5) Length in feet of segment remain-

ing.

[53 FR 10690, Apr. 1, 1988, as amended at 59FR 53094, Oct. 21, 1994. Redesignated at 63 FR29479, May 29, 1998, as amended at 63 FR43881, Aug. 17, 1998]

§ 250.1008 Reports.

(a) The lessee, or right-of-way holder,shall notify the Regional Supervisor atleast 48 hours prior to commencing theinstallation or relocation of a pipelineor conducting a pressure test on a pipe-line.

(b) The lessee or right-of-way holdershall submit a report to the RegionalSupervisor within 90 days after comple-tion of any pipeline construction. Thereport, submitted in triplicate, shallinclude an ‘‘as-built’’ location platdrawn to a scale specified by the Re-gional Supervisor showing the loca-tion, length in Federal waters, and X–Y coordinates of key points; the com-pletion date; the proposed date of firstoperation; and the HPT data. Pipelineright-of-way ‘‘as-built’’ location platsshall be certified by a registered engi-neer or land surveyor and show theboundaries of the right-of-way asgranted. If there is a substantial devi-ation of the pipeline route as grantedin the right-of-way, the report shall in-clude a discussion of the reasons forsuch deviation.

(c) The lessee or right-of-way holdershall report to the Regional Supervisorany pipeline taken out of service. If theperiod of time in which the pipeline isout of service is greater than 60 days,written confirmation is also required.

(d) The lessee or right-of-way holdershall report to the Regional Supervisorwhen any required pipeline safetyequipment is taken out of service formore than 12 hours. The Regional Su-pervisor shall be notified when theequipment is returned to service.

(e) The lessee or right-of-way holdershall notify the Regional Supervisorprior to the repair of any pipeline or assoon as practicable. A detailed reportof the repair of a pipeline or pipelinecomponent shall be submitted to theRegional Supervisor within 30 daysafter completion of the repairs. The re-port shall include the following:

(1) Description of repairs,(2) Results of pressure test, and(3) Date returned to service.(f) The Regional Supervisor may re-

quire that DOI pipeline failures be ana-lyzed and that samples of a failed sec-tion be examined in a laboratory to as-sist in determining the cause of thefailure. A comprehensive written re-port of the information obtained shallbe submitted by the lessee to the Re-gional Supervisor as soon as available.

(g) If the effects of scouring, soft bot-toms, or other environmental factorsare observed to be detrimentally af-fecting a pipeline, a plan of corrective


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30 CFR Ch. II (7–1–01 Edition)§ 250.1009

action shall be submitted to the Re-gional Supervisor for approval within30 days of the observation. A report ofthe remedial action taken shall be sub-mitted to the Regional Supervisor bythe lessee or right-of-way holder within30 days after completion.

(h) The results and conclusions ofmeasurements of pipe-to-electrolytepotential measurements taken annu-ally on DOI pipelines in accordancewith § 250.1005(b) of this part shall besubmitted to the Regional Supervisorby the lessee before March of eachyear.


§ 250.1009 General requirements for apipeline right-of-way grant.

(a)(1) In addition to applicable re-quirements of §§ 250.1000 through250.1008 and other regulations of thispart, regulations of the Department ofTransportation, Department of theArmy, and the Federal Energy Regu-latory Commission (FERC), when apipeline qualifies as a right-of-waypipeline, the pipeline shall not be in-stalled until a right-of-way has beenrequested and granted in accordancewith this subpart. The right-of-waygrant is issued pursuant to 43 U.S.C.1334(e) and may be acquired and heldonly by citizens and nationals of theUnited States; aliens lawfully admittedfor permanent residence in the UnitedStates as defined in 8 U.S.C. 1101(a)(20);private, public, or municipal corpora-tions organized under the laws of theUnited States or territory thereof, theDistrict of Columbia, or of any State;or associations of such citizens, nation-als, resident aliens, or private, public,or municipal corporations, States, orpolitical subdivisions of States.

(2) A right-of-way shall include thesite on which the pipeline and associ-ated structures are to be situated, shallnot exceed 200 feet in width unless safe-ty and environmental factors duringconstruction and operation of the asso-ciated right-of-way pipeline require agreater width, and shall be limited tothe area reasonably necessary forpumping stations or other accessorystructures.

(b)(1) When you apply for, or are theholder of, a right-of-way, you must:

(i) Provide and maintain a $300,000bond (in addition to the bond coveragerequired in part 256) that guaranteescompliance with all the terms and con-ditions of the rights-of-way you hold inan OCS area; and

(ii) Provide additional security if theRegional Director determines that abond in excess of $300,000 is needed.

(2) For the purpose of this paragraph,there are three areas:

(i) The areas offshore the Gulf ofMexico and Atlantic Coast;

(ii) The area offshore the PacificCoast States of California, Oregon,Washington, and Hawaii; and

(iii) The area offshore the Coast ofAlaska.

(3) If, as the result of a default, thesurety on a right-of-way grant bondmakes payment to the Government ofany indebtedness under a grant securedby the bond, the face amount of suchbond and the surety’s liability shall bereduced by the amount of such pay-ment.

(4) After a default, a new bond in theamount of $300,000 shall be posted with-in 6 months or such shorter period asthe Regional Supervisor may direct.Failure to post a new bond shall begrounds for forfeiture of all grants cov-ered by the defaulted bond.

(c) An applicant, by accepting aright-of-way grant, agrees to complywith the following requirements:

(1) The right-of-way holder shallcomply with applicable laws and regu-lations and the terms of the grant.

(2) For the first calendar year, orfraction thereof, and annually there-after, the right-of-way holder shall payMMS, in advance, an annual rental of$15 for each statute mile, or fractionthereof, traversed by the right-of-wayand $75 for each area to be used as asite for an accessory to the right-of-way pipeline including, but not limitedto, a platform. Payments may be on anannual basis, for a 5-year period, or formultiples of 5 years.

(3) The granting of the right-of-wayshall be subject to the express condi-tion that the rights granted shall notprevent or interfere in any way withthe management, administration, orthe granting of other rights by theUnited States, either prior or subse-quent to the granting of the right-of-


375


way. Moreover, the holder agrees toallow the occupancy and use by theUnited States, its lessees, or otherright-of-way holders, of any part of theright-of-way grant not actually occu-pied or necessarily incident to its usefor any necessary operations involvedin the management, administration, orthe enjoyment of such other grantedrights.

(4) If the right-of-way holder dis-covers any archaeological resourcewhile conducting operations within theright-of-way, the right-of-way holdershall immediately halt operationswithin the area of the discovery and re-port the discovery to the Regional Di-rector. If investigations determine thatthe resource is significant, the Re-gional Director will inform the lesseehow to protect it.

(5) The Regional Supervisor shall bekept informed at all times of the right-of-way holder’s address and, if a cor-poration, the address of its principalplace of business and the name and ad-dress of the officer or agent authorizedto be served with process.

(6) The right-of-way holder shall paythe United States or its lessees orright-of-way holders, as the case maybe, the full value of all damages to theproperty of the United States or itssaid lessees or right-of-way holders andshall indemnify the United Statesagainst any and all liability for dam-ages to life, person, or property arisingfrom the occupation and use of thearea covered by the right-of-way grant.

(7)(i) The holder of a right-of-way oilor gas pipeline shall transport or pur-chase oil or natural gas produced fromsubmerged lands in the vicinity of thepipeline without discrimination and insuch proportionate amounts as theFERC may, after a full hearing withdue notice thereof to the interestedparties, determine to be reasonable,taking into account, among otherthings, conservation and the preven-tion of waste.

(ii) Unless otherwise exempted byFERC pursuant to 43 U.S.C. 1334(f)(2),the holder shall—

(A) Provide open and nondiscrim-inatory access to a right-of-way pipe-line to both owner and nonowner ship-pers, and

(B) Comply with the provisions of 43U.S.C. 1334(f)(1)(B) under which FERCmay order an expansion of the through-put capacity of a right-of-way pipelinewhich is approved after September 18,1978, and which is not located in theGulf of Mexico or the Santa BarbaraChannel.

(8) The area covered by a right-of-way and all improvements thereonshall be kept open at all reasonabletimes for inspection by the MineralsManagement Service (MMS). Theright-of-way holder shall make avail-able all records relative to the design,construction, operation, maintenanceand repair, and investigations on orwith regard to such area.

(9) Upon relinquishment, forfeiture,or cancellation of a right-of-way grant,the right-of-way holder shall removeall platforms, structures, domes overvalves, pipes, taps, and valves alongthe right-of-way. All of these improve-ments shall be removed by the holderwithin 1 year of the effective date ofthe relinquishment, forfeiture, or can-cellation unless this requirement iswaived in writing by the Regional Su-pervisor. All such improvements notremoved within the time providedherein shall become the property of theUnited States but that shall not relievethe holder of liability for the cost oftheir removal or for restoration of thesite. Furthermore, the holder is respon-sible for accidents or damages whichmight occur as a result of failure totimely remove improvements andequipment and restore a site. An appli-cation for relinquishment of a right-of-way grant shall be filed in accordancewith § 250.1014 of this part.

(d) Failure to comply with the Act,regulations, or any conditions of theright-of-way grant prescribed by theRegional Supervisor shall be groundsfor forfeiture of the grant in an appro-priate judicial proceeding instituted bythe United States in any U.S. DistrictCourt having jurisdiction in accord-ance with the provisions of 43 U.S.C.1349.

(e) Any right-of-way granted underthe provisions of this subpart remainsin effect as long as the associated pipe-line is properly maintained and usedfor the purpose for which the grant was


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30 CFR Ch. II (7–1–01 Edition)§ 250.1010

made, unless otherwise expressly stat-ed in the grant. Temporary cessationor suspension of pipeline operationsshall not cause the grant to expire.However, if the purpose of the grantceases to exist or use of the associatedpipeline is permanently discontinuedfor any reason, the grant shall bedeemed to have expired.

[53 FR 10690, Apr. 1, 1988, as amended at 54FR 50617, Dec. 8, 1989; 55 FR 47753, Nov. 15,1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955,May 22, 1997. Redesignated and amended at 63FR 29479, 29486, May 29, 1998; 63 FR 34597,June 25, 1998; 64 FR 9065, Feb. 24, 1999]

§ 250.1010 Applications for a pipelineright-of-way grant.

(a) You must submit an original andthree copies of an application for a newor modified pipeline right-of-way grantto the Regional Supervisor. The appli-cation must address those items re-quired by § 250.1007 (a) or (b) of this sub-part, as applicable. It must also statethe primary purpose for which you willuse the right-of-way grant. If the right-of-way has been used before the appli-cation is made, the application muststate the date such use began, bywhom, and the date the applicant ob-tained control of the improvement.When you file your application, youmust pay the rental required under§ 250.1009(c)(2) of this subpart and anon-refundable filing fee of $2,350 for apipeline right-of-way grant to install anew pipeline or a non-refundable filingfee of $300 for a pipeline right-of-waygrant to convert an existing lease termpipeline into a right-of-way pipe-line. MMS periodically will amend thefiling fee based on its experience withthe costs for administering pipelineright-of-way applications. If the costschange by a percentage of not morethan the percentage change in the CPI‘‘U’’ since the last change to the filingfee, MMS will amend the applicationfee by the percentage of the change incosts without notice and opportunityfor comment. If costs increase by a per-centage more than the percentagechange in the CPI ‘‘U’’ since the lastchange to the filing fee, MMS will pro-vide notice and an opportunity to com-ment before it changes the filing fee.An application to modify an approvedright-of-way grant shall be accom-

panied by the additional rental re-quired under § 250.1009(c)(2), if applica-ble. A separate application shall befiled for each right-of-way.

(b)(1) An individual applicant shallsubmit a statement of citizenship ornationality with the application. Anapplicant who is an alien lawfully ad-mitted for permanent residence in theUnited States shall also submit evi-dence of such status with the applica-tion.

(2) If the applicant is an association(including a partnership), the applica-tion shall also be accompanied by acertified copy of the articles of associa-tion or appropriate reference to a copyof such articles already filed with MMSand a statement as to any subsequentamendments.

(3) If the applicant is a corporation,the application shall also include thefollowing:

(i) A statement certified by the Sec-retary or Assistant Secretary of thecorporation with the corporate sealshowing the State in which it is incor-porated and the name of the person(s)authorized to act on behalf of the cor-poration, or

(ii) In lieu of such a statement, anappropriate reference to statements orrecords previously submitted to MMS(including material submitted in com-pliance with prior regulations).

(c) The application shall include alist of every lessee and right-of-wayholder whose lease or right-of-way isintersected by the proposed right-of-way. The application shall also includea statement that a copy of the applica-tion has been sent by registered or cer-tified mail to each such lessee or right-of-way holder.

(d) The applicant shall include in theapplication an original and three cop-ies of a completed Nondiscriminationin Employment form (YN 3341-1 datedJuly 1982). These forms are available ateach MMS regional office.

[53 FR 10690, Apr. 1, 1988, as amended at 62FR 39775, July 24, 1997. Redesignated andamended at 63 FR 29479, 29486, May 29, 1998; 64FR 42598, Aug. 5, 1999]

§ 250.1011 Granting a pipeline right-of-way.

(a) In considering an application for aright-of-way, the Regional Supervisor


377


shall consider the potential effect ofthe associated pipeline on the human,marine, and coastal environments, life(including aquatic life), property, andmineral resources in the entire areaduring construction and operationalphases. The Regional Supervisor shallprepare an environmental analysis inaccordance with applicable policies andguidelines. To aid in the evaluationand determinations, the Regional Su-pervisor may request and considerviews and recommendations of appro-priate Federal Agencies, hold publicmeetings after appropriate notice, andconsult, as appropriate, with Stateagencies, organizations, industries, andindividuals. Before granting a pipelineright-of-way, the Regional Supervisorshall give consideration to any rec-ommendation by the intergovern-mental planning program, or similarprocess, for the assessment and man-agement of OCS oil and gas transpor-tation.

(b) Should the proposed route of aright-of-way adjoin and subsequentlycross any State submerged lands, theapplicant shall submit evidence to theRegional Supervisor that the State(s)so affected has reviewed the applica-tion. The applicant shall also submitany comment received as a result ofthat review. In the event of a Staterecommendation to relocate the pro-posed route, the Regional Supervisormay consult with the appropriateState officials.

(c)(1) The applicant shall submit pho-tocopies of return receipts to the Re-gional Supervisor that indicate thedate that each lessee or right-of-wayholder referenced in § 250.1010(c) of thispart has received a copy of the applica-tion. Letters of no objection may besubmitted in lieu of the return re-ceipts.

(2) The Regional Supervisor shall nottake final action on a right-of-way ap-plication until the Regional Supervisoris satisfied that each such lessee orright-of-way holder has been affordedat least 30 days from the date deter-mined in paragraph (c)(1) of this sec-tion in which to submit comments.

(d) If a proposed right-of-way crossesany lands not subject to disposition bymineral leasing or restricted from oiland gas activities, it shall be rejected

by the Regional Supervisor unless theFederal Agency with jurisdiction oversuch excluded or restricted area givesits consent to the granting of theright-of-way. In such case, the appli-cant, upon a request filed within 30days after receipt of the notification ofsuch rejection, shall be allowed an op-portunity to eliminate the conflict.

(e)(1) If the application and other re-quired information are found to be incompliance with applicable laws andregulations, the right-of-way may begranted. The Regional Supervisor mayprescribe, as conditions to the right-of-way grant, stipulations necessary toprotect human, marine, and coastal en-vironments, life (including aquaticlife), property, and mineral resourceslocated on or adjacent to the right-of-way.

(2) If the Regional Supervisor deter-mines that a change in the applicationshould be made, the Regional Super-visor shall notify the applicant that anamended application shall be filed sub-ject to stipulated changes. The Re-gional Supervisor shall determinewhether the applicant shall delivercopies of the amended application toother parties for comment.

(3) A decision to reject an applicationshall be in writing and shall state thereasons for the rejection.

[53 FR 10690, Apr. 1, 1988, as amended at 54FR 50617, Dec. 8, 1988. Redesignated andamended at 63 FR 29479, 29486, May 29, 1998]

§ 250.1012 Requirements for construc-tion under a right-of-way grant.

(a) Failure to construct the associ-ated right-of-way pipeline within 5years of the date of the granting of aright-of-way shall cause the grant toexpire.

(b)(1) A right-of-way holder shall en-sure that the right-of-way pipeline isconstructed in a manner that mini-mizes deviations from the right-of-wayas granted.

(2) If, after constructing the right-of-way pipeline, it is determined that adeviation from the proposed right-of-way as granted has occurred, the right-of-way holder shall—

(i) Notify the operators of all leasesand holders of all right-of-way grantsin which a deviation has occurred, and


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30 CFR Ch. II (7–1–01 Edition)§ 250.1013

within 60 days of the date of the ac-ceptance by the Regional Supervisor ofthe completion of pipeline constructionreport, provide the Regional Supervisorwith evidence of such notification; and

(ii) Relinquish any unused portion ofthe right-of-way.

(3) Substantial deviation of a right-of-way pipeline as constructed from theproposed right-of-way as granted maybe grounds for forfeiture of the right-of-way.

(c) If the Regional Supervisor deter-mines that a significant change in con-ditions has occurred subsequent to thegranting of a right-of-way but prior tothe commencement of construction ofthe associated pipeline, the RegionalSupervisor may suspend or temporarilyprohibit the commencement of con-struction until the right-of-way grantis modified to the extent necessary toaddress the changed conditions.

§ 250.1013 Assignment of a right-of-way grant.

(a) Assignment may be made of aright-of-way grant, in whole or of anylineal segment thereof, subject to theapproval of the Regional Supervisor.An application for approval of an as-signment of a right-of-way or of a lin-eal segment thereof, shall be filed intriplicate with the Regional Super-visor.

(b) Any application for approval foran assignment, in whole or in part, ofany right, title, or interest in a right-of-way grant shall be accompanied bythe same showing of qualifications ofthe assignees as is required of an appli-cant for a right-of-way in § 250.1010 ofthis subpart and shall be supported bya statement that the assignee agrees tocomply with and to be bound by theterms and conditions of the right-of-way grant. The assignee shall satisfythe bonding requirements in§ 250.1009(b) of this part. No transfershall be recognized unless and until itis first approved, in writing, by the Re-gional Supervisor. A nonrefundable fil-ing fee of $60 must accompany the ap-plication for the approval of an assign-ment. MMS periodically will amendthe filing fee based on its experiencewith the costs for administering pipe-line right-of-way assignment applica-tions. If the costs increase by more

than the CPI ‘‘U,’’ MMS will providenotice and opportunity for commentbefore changing the filing fee. For less-er cost increases or cost reductionsMMS will change the fee without suchprocedures.

[53 FR 10690, Apr. 1, 1988, as amended at 62FR 39775, July 24, 1997. Redesignated andamended at 63 FR 29479, 29486, May 29, 1998]

§ 250.1014 Relinquishment of a right-of-way grant.

A right-of-way grant or a portionthereof may be surrendered by theholder by filing a written relinquish-ment in triplicate with the RegionalSupervisor. It shall contain thoseitems addressed in § 250.1007(c) of thispart. A relinquishment shall take ef-fect on the date it is filed subject tothe satisfaction of all outstandingdebts, fees, or fines and the require-ments in § 250.1009(c)(9) of this part.


Subpart K—Oil and GasProduction Rates

§ 250.1100 Definitions for productionrates.

Terms used in this subpart shall havemeanings given below:

Enhanced recovery operations meanspressure maintenance operations, sec-ondary and tertiary recovery, cycling,and similar recovery operations whichalter the natural forces in a reservoirto increase the ultimate recovery of oilor gas.

Gas reservoir means a reservoir thatcontains hydrocarbons predominantlyin a gaseous (single-phase) state.

Gas-well completion means a well com-pleted in a gas reservoir or in the gascap of an oil reservoir with an associ-ated gas cap.

Maximum Efficient Rate (MER) meansthe maximum sustainable daily oil orgas withdrawal rate from a reservoirwhich will permit economic develop-ment and depletion of that reservoirwithout detriment to ultimate recov-ery.

Maximum Production Rate (MPR)means the approved maximum daily


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rate at which oil or gas may be pro-duced from a specified oil-well or gas-well completion.

Nonsensitive reservoir means a res-ervoir in which ultimate recovery isnot decreased by high reservoir produc-tion rates.

Oil reservoir means a reservoir thatcontains hydrocarbons predominantlyin a liquid (single-phase) state.

Oil reservoir with an associated gas capmeans a reservoir that contains hydro-carbons in both a liquid and gaseous(two-phase) state.

Oil-well completion means a well com-pleted in an oil reservoir or in the oilaccumulation of an oil reservoir withan associated gas cap.

Sensitive reservoir means a reservoirin which ultimate recovery is de-creased by high reservoir productionrates. A high reservoir production rateis one which exceeds the MER.

Waste of oil and gas means: (1) Thephysical waste of oil and gas; (2) the in-efficient, excessive, or improper use of,or the unnecessary dissipation of res-ervoir energy; (3) the locating, spacing,drilling, equipping, operating, or pro-ducing of any oil or gas well(s) in amanner which causes or tends to causea reduction in the quantity of oil orgas ultimately recoverable from a poolunder prudent and proper operations orwhich causes or tends to cause unnec-essary or excessive surface loss or de-struction of oil or gas; or (4) the ineffi-cient storage of oil.

§ 250.1101 General requirements andclassification of reservoirs.

(a) Wells and reservoirs shall be pro-duced at rates that will provide eco-nomic development and depletion ofthe hydrocarbon resources in a mannerthat would maximize the ultimate re-covery without adversely affecting cor-relative rights.

(b) For directionally drilled wells inwhich the completed interval is closerthan 500 feet from a unit or lease lineor for vertically drilled wells in whichthe surface location is closer than 500feet from a unit or lease line, for whichthe unit, lease, or royalty interests arenot the same, the prior approval by theRegional Supervisor is required beforeproduction is commenced. An operatorrequesting such an approval shall fur-

nish the Regional Supervisor with let-ters expressing acceptance or objectionfrom operators of offset properties.

(c) The lessee shall propose a classi-fication for each reservoir as an oil res-ervoir, an oil reservoir with an associ-ated gas cap or a gas reservoir, and assensitive or nonsensitive.

(d) All oil reservoirs with associatedgas caps shall be initially classified assensitive and shall require establishinga maximum efficient production rateand balancing of production in accord-ance with § 250.1102(a) (1) and (5) of thispart. All other oil reservoirs and allgas reservoirs shall be initially classi-fied as nonsensitive.

(e) A reservoir may be reclassified bythe Minerals Management Service(MMS) as to type and sensitivity atany time during its productive lifewhen information becomes availableshowing that reclassification is war-ranted.


§ 250.1102 Oil and gas productionrates.

(a) MER. (1) The lessee shall submit aproposed MER for each producing sen-sitive reservoir on Form MMS–127, Re-quest for Reservoir Maximum EfficientRate (MER), along with appropriatesupporting information to the RegionalSupervisor within 45 days after discov-ering that a reservoir is sensitive.

(2) The lessee may propose to revisean MER by submitting Form MMS–127with appropriate supporting informa-tion.

(3) The effective date of an MER fora reservoir or revision thereof shall bethe first day of the month in whichForm MMS–127 is submitted.

(4) When approved, the MER shall notbe exceeded, except as provided inparagraph (a)(5) of this section.

(5) If a reservoir is produced at a ratein excess of the MER for any month,the lessee should initiate measuresnecessary to balance production (offsetoverproduction by underproduction)during the next succeeding month. Alloverproduction shall be balanced bythe end of the next succeeding calendarquarter following the quarter in whichthe overproduction occurred. Any oper-ation in an overproduction status in


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any reservoir for two successive cal-endar quarters shall be shut in fromthat reservoir until the actual produc-tion is equal to that which would haveoccurred under the approved MER, un-less an alternative plan is approved bythe Regional Supervisor.

(6) The lessee shall review the MERfor each producing sensitive reservoirat least once a year and submit FormMMS–127 with appropriate supportinginformation.

(7) The lessee may request the reclas-sification of a reservoir from sensitiveto nonsensitive and request approvalfor termination of an MER by submit-ting Form MMS–127 with informationsupporting the reclassification and ter-mination.

(8) At the request of the Regional Su-pervisor, the lessee shall furnish the in-formation specified on Form MMS–127for any producing nonsensitive res-ervoir.

(9) Public information copies of FormMMS–127 shall be submitted in accord-ance with § 250.190.

(b) MPR. (1) The lessee shall proposean MPR for each producing well com-pletion together with full informationon the method used in its determina-tion. The MPR shall be based on welltests and any limitations imposed bywell and surface equipment, sand pro-duction, gas-oil and water-oil ratios,location of perforated intervals, andprudent operating practices. The sumof the MPR’s of wells completed in asensitive reservoir shall not exceed theapproved MER.

(2) The lessee shall conduct a well-flow potential test within 30 days ofthe date of first continuous productionon all new, recompleted, and reworkedwell completions. Within 15 days afterthe end of the test period, the lesseemust submit a proposed MPR with wellpotential test for the individual wellcompletion on Form MMS–126, WellPotential Test Report. The initial MPRshall not exceed 110 percent of the testrate submitted and shall be effectiveon the first day of the month followingthe end of the test period if approvedby the Regional Supervisor. During the30-day period allowed for testing, thelessee may produce a new, recom-pleted, or reworked completion at ratesnecessary to establish the MPR. After

the 30-day period and prior to approvalof the initial MPR, a well completionmay be produced at a rate not to ex-ceed the proposed rate. The lessee shallreport the total production obtainedduring the test period and shall iden-tify all other wells completed in thereservoir on Form MMS–126.

(3) At least one well test shall be con-ducted during a calendar half for pro-ducing oil-well and gas-well comple-tions and results submitted on FormMMS–128, Semiannual Well Test Re-port. Well tests shall be submittedwithin 45 days of the day the test wasconducted.

(4) Unless otherwise ordered by theRegional Supervisor, a revised MPRshall automatically be approved foreach well completion for each well testsubmitted equal to 110 percent of thetest rate. The revised MPR will be ef-fective on the first day of the monthfollowing the date the well test wasconducted. Prior to the approval of aproposed increase of the MPR, a wellcompletion may be produced at a ratenot to exceed the proposed increasedrate.

(5) When a well test is not submittedduring a calendar half for a producingoil-well or gas-well completion, theMPR will be automatically canceled ef-fective on the first day of the appro-priate following calendar half.

(6) When the results of a semiannualwell test for an oil-well or gas-wellcompletion cannot be submitted withinthe specified time, the lessee shall re-quest an extension of time for submit-ting those test results. The extensionmust be approved in advance by theRegional Supervisor to continue pro-duction under the last approved MPR.

(7) When approved by the RegionalSupervisor, an MPR shall not be ex-ceeded, except as provided in para-graphs (b)(4) and (c) of this section.

(8) Public Information copies of FormMMS–126 shall be submitted in accord-ance with § 250.190.

(9) Public information copies of FormMMS–128 shall be submitted in accord-ance with § 250.190.

(c) Temporary rates. Temporary pro-duction rates resulting from normalvariations and fluctuations exceeding awell MPR or reservoir MER shall notbe considered a violation, provided that


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such production in excess of an ap-proved MER is balanced by productionin accordance with the provisions ofparagraph (a)(5) of this section.

[53 FR 10690, Apr. 1, 1988, as amended at 58FR 49928, Sept. 24, 1993. Redesignated andamended at 63 FR 29479, 29486, May 29, 1998; 64FR 72794, Dec. 28, 1999; 65 FR 2875, Jan. 19,2000]

§ 250.1103 Well production testing.(a) The required well testing shall be

conducted for a period of not less thanfour consecutive hours. Immediatelyprior to the 4-hour test period, the wellcompletion shall have produced understabilized conditions for a period of notless than six consecutive hours. The 6-hour pretest period shall not beginuntil after the recovery of a volume offluid equivalent to the amount of fluidsintroduced into the formation duringcompletion, recompletion, reworking,or treatment operations. Measured gasvolumes shall be adjusted to the stand-ard conditions of 14.73 pounds persquare inch absolute (psia) (15.025 psiain the Gulf of Mexico OCS Region) and60 °F for all tests. When orifice metersare used, a specific gravity for the gasshall be obtained or estimated, and aspecific gravity-correction factor shallbe applied to the orifice coefficient.The Regional Supervisor may require aprolonged test or retest of a well com-pletion if the test is determined to benecessary for the establishment of awell MPR or a reservoir MER. The Re-gional Supervisor may approve test pe-riods of less than 4 hours and preteststabilization periods of less than 6hours for well completions providedthat test reliability can be dem-onstrated under such procedures.

(b) At the request of the Regional Su-pervisor, the lessee shall conduct amultipoint back-pressure test to deter-mine the theoretical open-flow poten-tial of a gas well. The test shall be con-ducted within 30 days of the RegionalSupervisor’s request or within the timeperiod specified by the Regional Super-visor.

(c) An MMS representative may wit-ness any well test of oil-well and gas-well completions. Upon request, a les-see shall provide advance notice to theRegional Supervisor of the time anddate of well tests.

§ 250.1104 Bottomhole pressure survey.

(a) For each new reservoir, the lesseeshall conduct a static bottomhole pres-sure survey within 3 months after thedate of first continuous production.

(b) For each producing reservoir withthree or more producing completions,the lessee shall conduct annual staticbottomhole pressure surveys in a suffi-cient number of key wells to establishan average reservoir pressure. The Re-gional Supervisor may require that asurvey be performed on specific wells.

(c) The results of all staticbottomhole pressure surveys obtainedby the lessee shall be filed with the Re-gional Supervisor within 60 days afterthe date of the survey.

§ 250.1105 Flaring or venting gas andburning liquid hydrocarbons.

(a) Lessees may flare or vent oil-wellgas or gas-well gas without receivingprior approval from the Regional Su-pervisor only in the following situa-tions:

(1) When gas vapors are flared orvented in small volumes from storagevessels or other low-pressure produc-tion vessels and cannot be economi-cally recovered.

(2) During an equipment failure or torelieve system pressures. The lesseemust comply with the following condi-tions:

(i) Lessees must not flare or vent oil-well gas for more than 48 continuoushours unless the Regional Supervisorapproves. The Regional Supervisor mayspecify a limit of less than 48 hours toprevent air quality degradation.

(ii) Lessees must not flare or vent gasfrom a facility for more than 144 cumu-lative hours during any calendarmonth unless the Regional Supervisorapproves.

(iii) Lessees must not flare or ventgas-well gas beyond the time requiredto eliminate an emergency unless theRegional Supervisor approves.

(3) During the unloading or cleaningof a well, drill-stem testing, productiontesting, or other well-evaluation test-ing. Flaring or venting must not ex-ceed 48 cumulative hours per testingoperation on a single completion. TheRegional Supervisor may allow lesstime to prevent air quality degradation


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or more time if lessees need additionaltime to evaluate reservoir parameters.

(b) Lessees may flare or vent oil-wellgas for up to 1 year when the RegionalSupervisor approves the request for oneof the following reasons:

(1) The lessee initiated an actionwhich, when completed, will eliminateflaring and venting; or

(2) The lessee submitted an evalua-tion supported by engineering, geo-logic, and economic data indicatingthat either:

(i) The oil and gas produced from thewell(s) will not economically supportthe facilities necessary to save and/orsell the gas; or

(ii) There is not enough gas to mar-ket.

(c) Lessees may burn produced liquidhydrocarbons only if the Regional Su-pervisor approves. To burn producedliquid hydrocarbons, the lessee mustdemonstrate that the amounts to burnwould be minimal, or that the alter-natives are infeasible or pose a signifi-cant risk that may harm offshore per-sonnel or the environment. Alter-natives to burning liquid hydrocarbonsinclude transporting the liquids orstoring and re-injecting them into aproducible zone.

(d) Lessees must prepare records de-tailing gas flaring or venting and liquidhydrocarbon burning for each facility.The records must include, at a min-imum:

(1) Daily volumes of gas flared orvented and liquid hydrocarbons burned;

(2) Number of hours of flaring, vent-ing, or burning on a daily basis;

(3) Reasons for flaring, venting, orburning; and

(4) A list of the wells contributing toflaring, venting, or burning, along withthe gas-oil ratio data.

(e) Lessees must keep these recordsfor at least 2 years. Lessees must allowMinerals Management Service rep-resentatives to inspect the records atthe lessees’ field office that is nearestthe Outer Continental Shelf facility, orat another location agreed to by theRegional Supervisor. If the RegionalSupervisor requests to see the records,lessees must provide a copy.

(f) Requirements for flaring and ventingof gas containing H2S—(1) Flaring of gascontaining H2S. (i) The Regional Super-

visor may, for safety or air pollutionprevention purposes, further restrictthe flaring of gas containing H2S. TheRegional Supervisor will use informa-tion provided in the lessee’s H2S Con-tingency Plan (§ 250.417(f)), ExplorationPlan or Development and ProductionPlan, and associated documents in de-termining the need for such restric-tions.

(ii) If the Regional Supervisor deter-mines that flaring at a facility orgroup of facilities may significantly af-fect the air quality of an onshore area,the Regional Supervisor may requirethe operator(s) to conduct an air qual-ity modeling analysis to determine thepotential effect of facility emissions ononshore ambient concentrations of SO2.The Regional Supervisor may requiremonitoring and reporting or may re-strict or prohibit flaring pursuant to§§ 250.303 and 250.304.

(2) Venting of gas containing H2S. Youmust not vent gas containing H2S ex-cept for minor releases during mainte-nance and repair activities that do notresult in a 15-minute time weighted av-erage atmospheric concentration ofH2S of 20 ppm or higher anywhere onthe platform.

(3) Reporting flared gas containing H2S.In addition to the recordkeeping re-quirements of paragraphs (d) and (e) ofthis section, when required by the Re-gional Supervisor, the operator mustsubmit to the Regional Supervisor amonthly report of flared and ventedgas containing H2S. The report mustcontain the following information:

(i) On a daily basis, the volume andduration of each flaring episode;

(ii) H2S concentration in the flaredgas; and

(iii) Calculated amount of SO2 emit-ted.

[61 FR 25148, May 20, 1996, as amended at 62FR 3800, Jan. 27, 1997. Redesignated andamended at 63 FR 29479, 29486, May 29, 1998]

§ 250.1106 Downhole commingling.(a) An application to commingle hy-

drocarbons produced from multiple res-ervoirs within a common wellbore shallbe submitted to the Regional Super-visor for approval and shall include allpertinent well information, geologicand reservoir engineering data, and aschematic diagram of well equipment.


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The application shall provide the esti-mated recoverable reserves as well asany available alternate drainage pointswhich might be used to produce thereservoirs separately.

(b) For a competitive reservoir, no-tice of intent to submit the applicationshall be sent by the applicant to allother lessees having an interest in thereservoir prior to submitting the appli-cation to the Regional Supervisor.

(c) The application shall specify thewell-completion number to be used forsubsequent reporting purposes.

§ 250.1107 Enhanced oil and gas recov-ery operations.

(a) The lessee shall timely initiateenhanced oil and gas recovery oper-ations for all competitive and non-competitive reservoirs where such op-erations would result in an increasedultimate recovery of oil or gas undersound engineering and economic prin-ciples.

(b) A proposed plan for pressuremaintenance, secondary and tertiary

recovery, cycling, and similar recoveryoperations to increase the ultimate re-covery of oil and/or gas from a res-ervoir shall be submitted to the Re-gional Supervisor for approval beforesuch operations are initiated.

(c) Periodic reports of the volumes ofoil, gas, or other substances injected,produced, or reproduced shall be sub-mitted as required by the Regional Su-pervisor.

Subpart L—Oil and Gas Produc-tion Measurement, SurfaceCommingling, and Security

SOURCE: 63 FR 26370, May 12, 1998, unlessotherwise noted. Redesignated at 63 FR 29479,May 29, 1998.

§ 250.1200 Question index table.

The table in this section lists ques-tions concerning Oil and Gas Produc-tion Measurement, Surface Commin-gling, and Security.

Frequently asked questions CFR citation

1. What are the requirements for measuring liquid hydrocarbons? ................................................................. § 250.1202(a)2. What are the requirements for liquid hydrocarbon royalty meters? ............................................................. § 250.1202(b)3. What are the requirements for run tickets? .................................................................................................. § 250.1202(c)4. What are the requirements for liquid hydrocarbon royalty meter provings? ................................................ § 250.1202(d)5. What are the requirements for calibrating a master meter used in royalty meter provings? ...................... § 250.1202(e)6. What are the requirements for calibrating mechanical-displacement provers and tank provers? ............... § 250.1202(f)7. What correction factors must a lessee use when proving meters with a mechanical displacement prover,tank prover, or master meter? ......................................................................................................................... § 250.1202(g)

8. What are the requirements for establishing and applying operating meter factors for liquid hydro-carbons? .......................................................................................................................................................... § 250.1202(h)

9. Under what circumstances does a liquid hydrocarbon royalty meter need to be taken out of service, andwhat must a lessee do? .................................................................................................................................. § 250.1202(i)

10. How must a lessee correct gross liquid hydrocarbon volumes to standard conditions? ............................. § 250.1202(j)11. What are the requirements for liquid hydrocarbon allocation meters? ........................................................ § 250.1202(k)12. What are the requirements for royalty and inventory tank facilities? ........................................................... § 250.1202(l)13. To which meters do MMS requirements for gas measurement apply? ....................................................... § 250.1203(a)14. What are the requirements for measuring gas? ........................................................................................... § 250.1203(b)15. What are the requirements for gas meter calibrations? ............................................................................... § 250.1203(c)16. What must a lessee do if a gas meter is out of calibration or malfunctioning? ........................................... § 250.1203(d)17. What are the requirements when natural gas from a Federal lease is transferred to a gas plant before

royalty determination? ..................................................................................................................................... § 250.1203(e)18. What are the requirements for measuring gas lost or used on a lease? .................................................... § 250.1203(f)19. What are the requirements for the surface commingling of production? ..................................................... § 250.1204(a)20. What are the requirements for a periodic well test used for allocation? ...................................................... § 250.1204(b)21. What are the requirements for site security? ............................................................................................... § 250.1205(a)22. What are the requirements for using seals? ................................................................................................ § 250.1205(b)

[63 FR 26370, May 12, 1998. Redesignated andamended at 63 FR 29479, 29487, May 29, 1998]

§ 250.1201 Definitions.

Terms not defined in this sectionhave the meanings given in the appli-cable chapter of the API MPMS, which

is incorporated by reference in 30 CFR250.198. Terms used in Subpart L havethe following meaning:

Allocation meter—a meter used to de-termine the portion of hydrocarbonsattributable to one or more platforms,leases, units, or wells, in relation to


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the total production from a royalty orallocation measurement point.

API MPMS—the American PetroleumInstitute’s Manual of Petroleum Meas-urement Standards, chapters 1, 20, and21.

British Thermal Unit (Btu)—theamount of heat needed to raise thetemperature of one pound of waterfrom 59.5 degrees Fahrenheit (59.5 °F)to 60.5 degrees Fahrenheit (60.5 °F) atstandard pressure base (14.73 poundsper square inch absolute (psia)).

Calibration—testing (verifying) andcorrecting, if necessary, a measuringdevice to industry accepted, manufac-turer’s recommended, or regulatory re-quired standard of accuracy.

Compositional Analysis—separatingmixtures into identifiable componentsexpressed in mole percent.

Gas lost—gas that is neither sold norused on the lease or unit nor used in-ternally by the producer.

Gas processing plant—an installationthat uses any process designed to re-move elements or compounds (hydro-carbon and non-hydrocarbon) from gas,including absorption, adsorption, or re-frigeration. Processing does not in-clude treatment operations, includingthose necessary to put gas into mar-ketable conditions such as naturalpressure reduction, mechanical separa-tion, heating, cooling, dehydration,desulphurization, and compression. Thechanging of pressures or temperaturesin a reservoir is not processing.

Gas processing plant statement—amonthly statement showing the vol-ume and quality of the inlet or fieldgas stream and the plant products re-covered during the period, volume ofplant fuel, flare and shrinkage, and theallocation of these volumes to thesources of the inlet stream.

Gas royalty meter malfunction—anerror in any component of the gasmeasurement system which exceedscontractual tolerances.

Gas volume statement—a monthlystatement showing gas measurementdata, including the volume (Mcf) andquality (Btu) of natural gas whichflowed through a meter.

Inventory tank—a tank in which liq-uid hydrocarbons are stored prior toroyalty measurement. The measured

volumes are used in the allocationprocess.

Liquid hydrocarbons (free liquids)—hy-drocarbons which exist in liquid format standard conditions after passingthrough separating facilities.

Malfunction factor—a liquid hydro-carbon royalty meter factor that dif-fers from the previous meter factor byan amount greater than 0.0025.

Natural gas—a highly compressible,highly expandable mixture of hydro-carbons which occurs naturally in agaseous form and passes a meter invapor phase.

Operating meter—a royalty or alloca-tion meter that is used for gas or liquidhydrocarbon measurement for any pe-riod during a calibration cycle.

Pressure base—the pressure at whichgas volumes and quality are reported.The standard pressure base is 14.73 psia.

Prove—to determine (as in meterproving) the relationship between thevolume passing through a meter at oneset of conditions and the indicated vol-ume at those same conditions.

Pipeline (retrograde) condensate—liq-uid hydrocarbons which drop out of theseparated gas stream at any point in apipeline during transmission to shore.

Royalty meter—a meter approved forthe purpose of determining the volumeof gas, oil, or other components re-moved, saved, or sold from a Federallease.

Royalty tank—an approved tank inwhich liquid hydrocarbons are meas-ured and upon which royalty volumesare based.

Run ticket—the invoice for liquid hy-drocarbons measured at a royaltypoint.

Sales meter—a meter at which custodytransfer takes place (not necessarily aroyalty meter).

Seal—a device or approved methodused to prevent tampering with royaltymeasurement components.

Standard conditions—atmosphericpressure of 14.73 pounds per square inchabsolute (psia) and 60 °F.

Surface commingling—the surface mix-ing of production from two or moreleases or units prior to measurementfor royalty purposes.


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Temperature base—the temperature atwhich gas and liquid hydrocarbon vol-umes and quality are reported. Thestandard temperature base is 60 °F.

You or your—the lessee or the oper-ator or other lessees’ representativeengaged in operations in the OuterContinental Shelf (OCS).

[63 FR 26370, May 12, 1998. Redesignated andamended at 63 FR 29479, 29486, May 29, 1998; 64FR 72794, Dec. 28, 1999]

§ 250.1202 Liquid hydrocarbon meas-urement.

(a) What are the requirements for meas-uring liquid hydrocarbons? You must:

(1) Submit a written application to,and obtain approval from, the RegionalSupervisor before commencing liquidhydrocarbon production or makingchanges to previously approved meas-urement procedures;

(2) Use measurement equipment thatwill accurately measure the liquid hy-drocarbons produced from a lease orunit;

(3) Use procedures and correction fac-tors according to the applicable chap-ters of the API MPMS as incorporatedby reference in 30 CFR 250.198, when ob-taining net standard volume and asso-ciated measurement parameters; and

(4) When requested by the RegionalSupervisor, provide the pipeline (retro-grade) condensate volumes as allocatedto the individual leases or units.

(b) What are the requirements for liquidhydrocarbon royalty meters? You must:

(1) Ensure that the royalty meter fa-cilities include the following approvedcomponents (or other MMS-approvedcomponents) which must be compatiblewith their connected systems:

(i) A meter equipped with a nonresettotalizer;

(ii) A calibrated mechanical displace-ment (pipe) prover, master meter, ortank prover;

(iii) A proportional-to-flow samplingdevice pulsed by the meter output;

(iv) A temperature measurement ortemperature compensation device; and

(v) A sediment and water monitorwith a probe located upstream of thedivert valve.

(2) Ensure that the royalty meter fa-cilities accomplish the following:

(i) Prevent flow reversal through themeter;

(ii) Protect meters subjected to pres-sure pulsations or surges;

(iii) Prevent the meter from beingsubjected to shock pressures greaterthan the maximum working pressure;and

(iv) Prevent meter bypassing.(3) Maintain royalty meter facilities

to ensure the following:(i) Meters operate within the gravity

range specified by the manufacturer;(ii) Meters operate within the manu-

facturer’s specifications for maximumand minimum flow rate for linear accu-racy; and

(iii) Meters are reproven whenchanges in metering conditions affectthe meters’ performance such aschanges in pressure, temperature, den-sity (water content), viscosity, pres-sure, and flow rate.

(4) Ensure that sampling devices con-form to the following:

(i) The sampling point is in theflowstream immediately upstream ordownstream of the meter or divertvalve (in accordance with the APIMPMS as incorporated by reference in30 CFR 250.198);

(ii) The sample container is vapor-tight and includes a power mixing de-vice to allow complete mixing of thesample before removal from the con-tainer; and

(iii) The sample probe is in the centerhalf of the pipe diameter in a verticalrun and is located at least three pipediameters downstream of any pipe fit-ting within a region of turbulent flow.The sample probe can be located in ahorizontal pipe if adequate stream con-ditioning such as power mixers or stat-ic mixers are installed upstream of theprobe according to the manufacturer’sinstructions.

(c) What are the requirements for runtickets? You must:

(1) For royalty meters, ensure thatthe run tickets clearly identify all ob-served data, all correction factors notincluded in the meter factor, and thenet standard volume.

(2) For royalty tanks, ensure that therun tickets clearly identify all ob-served data, all applicable correctionfactors, on/off seal numbers, and thenet standard volume.


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(3) Pull a run ticket at the beginningof the month and immediately after es-tablishing the monthly meter factor ora malfunction meter factor.

(4) Send all run tickets for royaltymeters and tanks to the Regional Su-pervisor within 15 days after the end ofthe month;

(d) What are the requirements for liquidhydrocarbon royalty meter provings? Youmust:

(1) Permit MMS representatives towitness provings;

(2) Ensure that the integrity of theprover calibration is traceable to testmeasures certified by the National In-stitute of Standards and Technology;

(3) Prove each operating royaltymeter to determine the meter factormonthly, but the time between meterfactor determinations must not exceed42 days;

(4) Obtain approval from the Re-gional Supervisor before proving on aschedule other than monthly; and

(5) Submit copies of all meter prov-ing reports for royalty meters to theRegional Supervisor monthly within 15days after the end of the month.

(e) What are the requirements for cali-brating a master meter used in royaltymeter provings? You must:

(1) Calibrate the master meter to ob-tain a master meter factor before usingit to determine operating meter fac-tors;

(2) Use a fluid of similar gravity, vis-cosity, temperature, and flow rate asthe liquid hydrocarbons that flowthrough the operating meter to cali-brate the master meter;

(3) Calibrate the master metermonthly, but the time between calibra-tions must not exceed 42 days;

(4) Calibrate the master meter by re-cording runs until the results of twoconsecutive runs (if a tank prover isused) or five out of six consecutive runs(if a mechanical-displacement prover isused) produce meter factor differencesof no greater than 0.0002. Lessees mustuse the average of the two (or the five)runs that produced acceptable resultsto compute the master meter factor;

(5) Install the master meter upstreamof any back-pressure or reverse flowcheck valves associated with the oper-ating meter. However, the mastermeter may be installed either up-

stream or downstream of the operatingmeter; and

(6) Keep a copy of the master metercalibration report at your field loca-tion for 2 years.

(f) What are the requirements for cali-brating mechanical-displacement proversand tank provers? You must:

(1) Calibrate mechanical-displace-ment provers and tank provers at leastonce every 5 years according to theAPI MPMS as incorporated by ref-erence in 30 CFR 250.101; and

(2) Submit a copy of each calibrationreport to the Regional Supervisor with-in 15 days after the calibration.

(g) What correction factors must I usewhen proving meters with a mechanical-displacement prover, tank prover, or mas-ter meter? Calculate the following cor-rection factors using the API MPMS asreferenced in 30 CFR 250.198:

(1) The change in prover volume dueto the effect of temperature on steel(Cts);

(2) The change in prover volume dueto the effect of pressure on steel (Cps);

(3) The change in liquid volume dueto the effect of temperature on a liquid(Ctl); and

(4) The change in liquid volume dueto the effect of pressure on a liquid(Cpl).

(h) What are the requirements for estab-lishing and applying operating meter fac-tors for liquid hydrocarbons? (1) If youuse a mechanical-displacement prover,you must record proof runs until fiveout of six consecutive runs produce adifference between individual runs ofno greater than .05 percent. You mustuse the average of the five acceptedruns to compute the meter factor.

(2) If you use a master meter, youmust record proof runs until three con-secutive runs produce a total meterfactor difference of no greater than0.0005. The flow rate through the me-ters during the proving must be within10 percent of the rate at which the linemeter will operate. The final meterfactor is determined by averaging themeter factors of the three runs;

(3) If you use a tank prover, you mustrecord proof runs until two consecutiveruns produce a meter factor differenceof no greater than .0005. The final


387


meter factor is determined by aver-aging the meter factors of the tworuns; and

(4) You must apply operating meterfactors forward starting with the dateof the proving.

(i) Under what circumstances does a liq-uid hydrocarbon royalty meter need to betaken out of service, and what must I do?(1) If the difference between the meterfactor and the previous factor exceeds0.0025 it is a malfunction factor, andyou must:

(i) Remove the meter from serviceand inspect it for damage or wear;

(ii) Adjust or repair the meter, andreprove it;

(iii) Apply the average of the mal-function factor and the previous factorto the production measured throughthe meter between the date of the pre-vious factor and the date of the mal-function factor; and

(iv) Indicate that a meter malfunc-tion occurred and show all appropriateremarks regarding subsequent repairsor adjustments on the proving report.

(2) If a meter fails to register produc-tion, you must:

(i) Remove the meter from service,repair and reprove it;

(ii) Apply the previous meter factorto the production run between the dateof that factor and the date of the fail-ure; and

(iii) Estimate and report unregisteredproduction on the run ticket.

(3) If the results of a royalty meterproving exceed the run tolerance cri-teria and all measures excluding theadjustment or repair of the meter can-not bring results within tolerance, youmust:

(i) Establish a factor using provingresults made before any adjustment orrepair of the meter; and

(ii) Treat the established factor likea malfunction factor (see paragraph(i)(1) of this section).

(j) How must I correct gross liquid hy-drocarbon volumes to standard condi-tions? To correct gross liquid hydro-carbon volumes to standard conditions,you must:

(1) Include Cpl factors in the meterfactor calculation or list and applythem on the appropriate run ticket.

(2) List Ctl factors on the appropriaterun ticket when the meter is not auto-matically temperature compensated.

(k) What are the requirements for liquidhydrocarbon allocation meters? For liq-uid hydrocarbon allocation meters youmust:

(1) Take samples continuously pro-portional to flow or daily (use the pro-cedure in the applicable chapter of theAPI MPMS as incorporated by ref-erence in 30 CFR 250.198;

(2) For turbine meters, take the sam-ple proportional to the flow only;

(3) Prove allocation meters monthlyif they measure 50 or more barrels perday per meter; or

(4) Prove allocation meters quarterlyif they measure less than 50 barrels perday per meter;

(5) Keep a copy of the proving reportsat the field location for 2 years;

(6) Adjust and reprove the meter ifthe meter factor differs from the pre-vious meter factor by more than 2 per-cent and less than 7 percent;

(7) For turbine meters, remove fromservice, inspect and reprove the meterif the factor differs from the previousmeter factor by more than 2 percentand less than 7 percent;

(8) Repair and reprove, or replace andprove the meter if the meter factor dif-fers from the previous meter factor by7 percent or more; and

(9) Permit MMS representatives towitness provings.

(l) What are the requirements for roy-alty and inventory tank facilities? Youmust:

(1) Equip each royalty and inventorytank with a vapor-tight thief hatch, avent-line valve, and a fill line designedto minimize free fall and splashing;

(2) For royalty tanks, submit a com-plete set of calibration charts (tank ta-bles) to the Regional Supervisor beforeusing the tanks for royalty measure-ment;

(3) For inventory tanks, retain thecalibration charts for as long as thetanks are in use and submit them tothe Regional Supervisor upon request;and

(4) Obtain the volume and othermeasurement parameters by using cor-rection factors and procedures in the


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30 CFR Ch. II (7–1–01 Edition)§ 250.1203

API MPMS as incorporated by ref-erence in 30 CFR 250.198.

[63 FR 26370, May 12, 1998. Redesignated andamended at 63 FR 29479, 29486, May 29, 1998; 63FR 33853, June 22, 1998; 64 FR 72794, Dec. 281999]

§ 250.1203 Gas measurement.(a) To which meters do MMS require-

ments for gas measurement apply? MMSrequirements for gas measurementsapply to all OCS gas royalty and allo-cation meters.

(b) What are the requirements for meas-uring gas? You must:

(1) Submit a written application to,and obtain approval from, the RegionalSupervisor before commencing gas pro-duction or making changes to pre-viously approved measurement proce-dures.

(2) Design, install, use, maintain, andtest measurement equipment to ensureaccurate and verifiable measurement.You must follow the recommendationsin API MPMS as incorporated by ref-erence in 30 CFR 250.198.

(3) Ensure that the measurementcomponents demonstrate consistentlevels of accuracy throughout the sys-tem.

(4) Equip the meter with a chart orelectronic data recorder. If an elec-tronic data recorder is used, you mustfollow the recommendations in APIMPMS as referenced in 30 CFR 250.198.

(5) Take proportional-to-flow or spotsamples upstream or downstream ofthe meter at least once every 6 months.

(6) When requested by the RegionalSupervisor, provide available informa-tion on the gas quality.

(7) Ensure that standard conditionsfor reporting gross heating value (Btu)are at a base temperature of 60 °F andat a base pressure of 14.73 psia and re-flect the same degree of water satura-tion as in the gas volume.

(8) When requested by the RegionalSupervisor, submit copies of gas vol-ume statements for each requested gasmeter. Show whether gas volumes andgross Btu heating values are reportedat saturated or unsaturated conditions;and

(9) When requested by the RegionalSupervisor, provide volume and qualitystatements on dispositions other thanthose on the gas volume statement.

(c) What are the requirements for gasmeter calibrations? You must:

(1) Calibrate meters monthly, but donot exceed 42 days between calibra-tions;

(2) Calibrate each meter by using themanufacturer’s specifications;

(3) Conduct calibrations as close aspossible to the average hourly rate offlow since the last calibration;

(4) Retain calibration reports at thefield location for 2 years, and send thereports to the Regional Supervisorupon request; and

(5) Permit MMS representatives towitness calibrations.

(d) What must I do if a gas meter is outof calibration or malfunctioning? If a gasmeter is out of calibration or malfunc-tioning, you must:

(1) If the readings are greater thanthe contractual tolerances, adjust themeter to function properly or removeit from service and replace it.

(2) Correct the volumes to the lastacceptable calibration as follows:

(i) If the duration of the error can bedetermined, calculate the volume ad-justment for that period.

(ii) If the duration of the error can-not be determined, apply the volumeadjustment to one-half of the timeelapsed since the last calibration or 21days, whichever is less.

(e) What are the requirements whennatural gas from a Federal lease on theOCS is transferred to a gas plant beforeroyalty determination? If natural gasfrom a Federal lease on the OCS istransferred to a gas plant before roy-alty determination:

(1) You must provide the following tothe Regional Supervisor upon request:

(i) A copy of the monthly gas proc-essing plant allocation statement; and

(ii) Gross heating values of the inletand residue streams when not reportedon the gas plant statement.

(2) You must permit MMS to inspectthe measurement and sampling equip-ment of natural gas processing plantsthat process Federal production.

(f) What are the requirements for meas-uring gas lost or used on a lease? (1) Youmust either measure or estimate thevolume of gas lost or used on a lease.

(2) If you measure the volume, docu-ment the measurement equipment usedand include the volume measured.


389


(3) If you estimate the volume, docu-ment the estimating method, the dataused, and the volumes estimated.

(4) You must keep the documenta-tion, including the volume data, easilyobtainable for inspection at the fieldlocation for at least 2 years, and mustretain the documentation at a locationof your choosing for at least 7 yearsafter the documentation is generated,subject to all other document retentionand production requirements in 30U.S.C. 1713 and 30 CFR part 212.

(5) Upon the request of the RegionalSupervisor, you must provide copies ofthe records.

[63 FR 26370, May 12, 1998. Redesignated andamended at 63 FR 29479, 29486, May 29, 1998; 63FR 33853, June 22, 1998; 64 FR 72794, Dec. 28,1999]

§ 250.1204 Surface commingling.(a) What are the requirements for the

surface commingling of production? Youmust:

(1) Submit a written application to,and obtain approval from, the Regionalsupervisor before commencing thecommingling of production or makingchanges to previously approved com-mingling applications.

(2) Upon the request of the RegionalSupervisor, lessees who deliver Statelease production into a Federal com-mingling system must provide volu-metric or fractional analysis data onthe State lease production through thedesignated system operator.

(b) What are the requirements for aperiodic well test used for allocation? Youmust:

(1) Conduct a well test at least onceevery 2 months unless the Regional Su-pervisor approves a different fre-quency;

(2) Follow the well test procedures in30 CFR part 250, Subpart K; and

(3) Retain the well test data at thefield location for 2 years.

[63 FR 26370, May 12, 1998. Redesignated at 63FR 29479, May 29, 1998; 63 FR 33853, June 22,1998]

§ 250.1205 Site security.(a) What are the requirements for site

security? You must:(1) Protect Federal production

against production loss or theft;

(2) Post a sign at each royalty or in-ventory tank which is used in the roy-alty determination process. The signmust contain the name of the facilityoperator, the size of the tank, and thetank number;

(3) Not bypass MMS-approved liquidhydrocarbon royalty meters and tanks;and

(4) Report the following to the Re-gional Supervisor as soon as possible,but no later than the next business dayafter discovery:

(i) Theft or mishandling of produc-tion;

(ii) Tampering or bypassing any com-ponent of the royalty measurement fa-cility; and

(iii) Falsifying production measure-ments.

(b) What are the requirements for usingseals? You must:

(1) Seal the following components ofliquid hydrocarbon royalty meter in-stallations to ensure that tamperingcannot occur without destroying theseal:

(i) Meter component connectionsfrom the base of the meter up to andincluding the register;

(ii) Sampling systems includingpacking device, fittings, sight glass,and container lid;

(iii) Temperature and gravity com-pensation device components;

(iv) All valves on lines leaving a roy-alty or inventory storage tank, includ-ing load-out line valves, drain-linevalves, and connection-line valves be-tween royalty and non-royalty tanks;and

(v) Any additional components re-quired by the Regional Supervisor.

(2) Seal all bypass valves of gas roy-alty and allocation meters.

(3) Number and track the seals andkeep the records at the field locationfor at least 2 years; and

(4) Make the records of seals avail-able for MMS inspection.

Subpart M—Unitization

SOURCE: 62 FR 5331, Feb. 5, 1997, unless oth-erwise noted. Redesignated at 63 FR 29479,May 29, 1998.


390

30 CFR Ch. II (7–1–01 Edition)§ 250.1300

§ 250.1300 What is the purpose of thissubpart?

This subpart explains how Outer Con-tinental Shelf (OCS) leases are unit-ized. If you are an OCS lessee, use theregulations in this subpart for bothcompetitive reservoir and unitizationsituations. The purpose of joint devel-opment and unitization is to:

(a) Conserve natural resources;(b) Prevent waste; and/or(c) Protect correlative rights, includ-

ing Federal royalty interests.

§ 250.1301 What are the requirementsfor unitization?

(a) Voluntary unitization. You andother OCS lessees may ask the Re-gional Supervisor to approve a requestfor voluntary unitization. The Re-gional Supervisor may approve the re-quest for voluntary unitization if unit-ized operations:

(1) Promote and expedite explorationand development; or

(2) Prevent waste, conserve naturalresources, or protect correlative rights,including Federal royalty interests, ofa reasonably delineated and productivereservoir.

(b) Compulsory unitization. The Re-gional Supervisor may require you andother lessees to unitize operations ifunitized operations are necessary to:

(1) Prevent waste;(2) Conserve natural resources; or(3) Protect correlative rights, includ-

ing Federal royalty interests, of a rea-sonably delineated and productive res-ervoir.

(c) Unit area. The area that a unit in-cludes is the minimum number ofleases that will allow the lessees tominimize the number of platforms, fa-cility installations, and wells nec-essary for efficient exploration, devel-opment, and production of mineral de-posits, oil and gas reservoirs, or poten-tial hydrocarbon accumulations. Aunit may include whole leases or por-tions of leases.

(d) Unit agreement. You, the other les-sees, and the unit operator must enterinto a unit agreement. The unit agree-ment must: allocate benefits to unit-ized leases, designate a unit operator,and specify the effective date of theunit agreement. The unit agreementmust terminate when: the unit no

longer produces unitized substances,and the unit operator no longer con-ducts drilling or well-workover oper-ations (§ 250.180) under the unit agree-ment, unless the Regional Supervisororders or approves a suspension of pro-duction under § 250.170.

(e) Unit operating agreement. The unitoperator and the owners of working in-terests in the unitized leases mustenter into a unit operating agreement.The unit operating agreement must de-scribe how all the unit participantswill apportion all costs and liabilitiesincurred maintaining or conducting op-erations. When a unit involves one ormore net-profit-share leases, the unitoperating agreement must describehow to attribute costs and credits tothe net-profit-share lease(s), and thispart of the agreement must be ap-proved by the Regional Supervisor.Otherwise, you must provide a copy ofthe unit operating agreement to theRegional Supervisor, but the RegionalSupervisor does not need to approvethe unit operating agreement.

(f) Extension of a lease covered by unitoperations. If your unit agreement ex-pires or terminates, or the unit areaadjusts so that no part of your lease re-mains within the unit boundaries, yourlease expires unless:

(1) Its initial term has not expired;(2) You conduct drilling, production,

or well-reworking operations on yourlease consistent with applicable regula-tions; or

(3) MMS orders or approves a suspen-sion of production or operations foryour lease.

(g) Unit operations. If your lease, orany part of your lease, is subject to aunit agreement, the entire lease con-tinues for the term provided in thelease, and as long thereafter as anyportion of your lease remains part ofthe unit area, and as long as operationscontinue the unit in effect.

(1) If you drill, produce or performwell-workover operations on a leasewithin a unit, each lease, or part of alease, in the unit will remain active inaccordance with the unit agreement.Following a discovery, if your unitceases drilling activities for a reason-able time period between the delinea-tion of one or more reservoirs and the


391


initiation of actual development drill-ing or production operations and thattime period would extend beyond yourlease’s primary term or any extensionunder § 250.180, the unit operator mustrequest and obtain MMS approval of asuspension of production under § 250.170in order to keep the unit from termi-nating.

(2) When a lease in a unit agreementis beyond the primary term and thelease or unit is not producing, the leasewill expire unless:

(i) You conduct a continuous drillingor well reworking program designed todevelop or restore the lease or unit pro-duction; or

(ii) MMS orders or approves a suspen-sion of operations under § 250.170.

[62 FR 5331, Feb. 5, 1997. Redesignated andamended at 63 FR 29479, 29486, May 29, 1998; 64FR 72794, Dec. 28, 1999]

§ 250.1302 What if I have a competitivereservoir on a lease?

(a) The Regional Supervisor may re-quire you to conduct development andproduction operations in a competitivereservoir under either a joint Develop-ment and Production Plan or a unitiza-tion agreement. A competitive res-ervoir has one or more producing orproducible well completions on each oftwo or more leases, or portions ofleases, with different lease operatinginterests. For purposes of this para-graph, a producible well completion isa well which is capable of productionand which is shut in at the well head orat the surface but not necessarily con-nected to production facilities andfrom which the operator plans futureproduction.

(b) You may request that the Re-gional Supervisor make a preliminarydetermination whether a reservoir iscompetitive. When you receive the pre-liminary determination, you have 30days (or longer if the Regional Super-visor allows additional time) to concuror to submit an objection with sup-porting evidence if you do not concur.The Regional Supervisor will make afinal determination and notify you andthe other lessees.

(c) If you conduct drilling or produc-tion operations in a reservoir deter-mined competitive by the Regional Su-pervisor, you and the other affected

lessees must submit for approval ajoint plan of operations. You must sub-mit the joint plan within 90 days afterthe Regional Supervisor makes a finaldetermination that the reservoir iscompetitive. The joint plan must pro-vide for the development and/or pro-duction of the reservoir. You may sub-mit supplemental plans for the Re-gional Supervisor’s approval.

(d) If you and the other affected les-sees cannot reach an agreement on ajoint Development and ProductionPlan within the approved period oftime, each lessee must submit a sepa-rate plan to the Regional Supervisor.The Regional Supervisor will hold ahearing to resolve differences in theseparate plans. If the differences in theseparate plans are not resolved at thehearing and the Regional Supervisordetermines that unitization is nec-essary under § 250.1301(b), MMS will ini-tiate unitization under § 250.1304.

[62 FR 5331, Feb. 5, 1997. Redesignated andamended at 63 FR 29479, 29486, May 29, 1998]

§ 250.1303 How do I apply for vol-untary unitization?

(a) You must file a request for a vol-untary unit with the Regional Super-visor. Your request must include:

(1) A draft of the proposed unit agree-ment;

(2) A proposed initial plan of oper-ation;

(3) Supporting geological, geo-physical, and engineering data; and

(4) Other information that may benecessary to show that the unitizationproposal meets the criteria of § 250.1300.

(b) The unit agreement must complywith the requirements of this part.MMS will maintain and provide amodel unit agreement for you to fol-low. If MMS revises the model, MMSwill publish the revised model in theFEDERAL REGISTER. If you vary yourunit agreement from the model agree-ment, you must obtain the approval ofthe Regional Supervisor.

(c) After the Regional Supervisor ac-cepts your unitization proposal, you,the other lessees, and the unit operatormust sign and file copies of the unitagreement, the unit operating agree-ment, and the initial plan of operation


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30 CFR Ch. II (7–1–01 Edition)§ 250.1304

with the Regional Supervisor for ap-proval.


§ 250.1304 How will MMS require unit-ization?

(a) If the Regional Supervisor deter-mines that unitization of operationswithin a proposed unit area is nec-essary to prevent waste, conserve nat-ural resources of the OCS, or protectcorrelative rights, including Federalroyalty interests, the Regional Super-visor may require unitization.

(b) If you ask MMS to require unit-ization, you must file a request withthe Regional Supervisor. You must in-clude a proposed unit agreement as de-scribed in §§ 250.1301(d) and 250.1303(b); aproposed unit operating agreement; aproposed initial plan of operation; sup-porting geological, geophysical, andengineering data; and any other infor-mation that may be necessary to showthat unitization meets the criteria of§ 250.1300. The proposed unit agreementmust include a counterpart executedby each lessee seeking compulsoryunitization. Lessees who seek compul-sory unitization must simultaneouslyserve on the nonconsenting lessees cop-ies of:

(1) The request;(2) The proposed unit agreement with

executed counterparts;(3) The proposed unit operating

agreement; and(4) The proposed initial plan of oper-

ation.(c) If the Regional Supervisor initi-

ates compulsory unitization, MMS willserve all lessees of the proposed unitarea with a proposed unitization planand a statement of reasons for the pro-posed unitization.

(d) The Regional Supervisor will notrequire unitization until MMS providesall lessees of the proposed unit areawritten notice and an opportunity for ahearing. If you want MMS to hold ahearing, you must request it within 30days after you receive written noticefrom the Regional Supervisor or afteryou are served with a request for com-pulsory unitization from another les-see.

(e) MMS will not hold a hearingunder this paragraph until at least 30

days after MMS provides written no-tice of the hearing date to all partiesowning interests that would be madesubject to the unit agreement. The Re-gional Supervisor must give all lesseesof the proposed unit area an oppor-tunity to submit views orally and inwriting and to question both thoseseeking and those opposing compulsoryunitization. Adjudicatory proceduresare not required. The Regional Super-visor will make a decision based upon arecord of the hearing, including anywritten information made a part of therecord. The Regional Supervisor willarrange for a court reporter to make averbatim transcript. The party seekingcompulsory unitization must pay forthe court reporter and pay for and pro-vide to the Regional Supervisor within10 days after the hearing three copiesof the verbatim transcript.

(f) The Regional Supervisor will issuean order that requires or rejects com-pulsory unitization. That order mustinclude a statement of reasons for theaction taken and identify those partsof the record which form the basis ofthe decision. Any adversely affectedparty may appeal the final order of theRegional Supervisor under 30 CFR part290.


Subpart N—Outer ContinentalShelf (OCS) Civil Penalties

SOURCE: 62 FR 42668, Aug. 8, 1997, unlessotherwise noted. Redesignated at 63 FR 29479,May 29, 1998.

§ 250.1400 How does MMS begin thecivil penalty process?

This subpart explains MMS’s civilpenalty procedures whenever a lessee,operator or other person engaged in oil,gas, sulphur or other minerals oper-ations in the OCS has a violation.Whenever MMS determines, on thebasis of available evidence, that a vio-lation occurred and a civil penalty re-view is appropriate, it will prepare acase file. MMS will appoint a Review-ing Officer.


393


§ 250.1401 Index table.The following table is an index of the

sections in this subpart:

§ 250.1401 TABLE

Definitions .................................................................................................................................. § 250.1402What is the maximum civil penalty? .......................................................................................... § 250.1403Which violations will MMS review for potential civil penalties? ................................................. § 250.1404When is a case file developed? ................................................................................................. § 250.1405When will MMS notify me and provide penalty information? .................................................... § 250.1406How do I respond to the letter of notification? .......................................................................... § 250.1407When will I be notified of the Reviewing Officer’s decision? ..................................................... § 250.1408What are my appeal rights? ....................................................................................................... § 250.1409

[62 FR 42668, Aug. 8, 1997. Redesignated andamended at 63 FR 29479, 29487, May 29, 1998]

§ 250.1402 Definitions.

Terms used in this subpart have thefollowing meaning:

Case file means an MMS documentfile containing information and therecord of evidence related to the al-leged violation.

Civil penalty means a fine. It is anMMS regulatory enforcement tool usedin addition to Notices of Incidents ofNoncompliance and directed suspen-sions of production or other operations.

I, me in a question or you in a re-sponse means the person, or agent of aperson engaged in oil, gas, sulphur, orother minerals operations in the OuterContinental Shelf (OCS).

Person means, in addition to a nat-ural person, an association (includingpartnerships and joint ventures), aState, a political subdivision of aState, or a private, public, or munic-ipal corporation.

Reviewing Officer means an MMS em-ployee assigned to review case files andassess civil penalties.

Violation means failure to complywith the Outer Continental ShelfLands Act (OCSLA) or any other appli-cable laws, with any regulations issuedunder the OCSLA, or with the terms orprovisions of leases, licenses, permits,rights-of-way, or other approvalsissued under the OCSLA.

Violator means a person responsiblefor a violation.

§ 250.1403 What is the maximum civilpenalty?

The maximum civil penalty is $25,000per day per violation.

[64 FR 9065, Feb. 24, 1999]

§ 250.1404 Which violations will MMSreview for potential civil penalties?

MMS will review each of the fol-lowing violations for potential civilpenalties:

(a) Violations that you do not correctwithin the period MMS grants;

(b) Violations that MMS determinesmay constitute, or constituted, athreat of serious, irreparable, or imme-diate harm or damage to life (includingfish and other aquatic life), property,any mineral deposit, or the marine,coastal, or human environment; or

(c) Violations that cause serious, ir-reparable, or immediate harm or dam-age to life (including fish and otheraquatic life), property, any mineral de-posit, or the marine, coastal, or humanenvironment.

(d) Violations of the oil spill finan-cial responsibility requirements at 30CFR part 253.

[62 FR 5331, Feb. 5, 1997. Redesignated andamended at 63 FR 29479, 29487, May 29, 1998; 63FR 42711, Aug. 11, 1998; 64 FR 9066, Feb. 24,1999]

§ 250.1405 When is a case file devel-oped?

MMS will develop a case file duringits investigation of the violation, andforward it to a Reviewing Officer if anyof the conditions in § 250.1404 exist. TheReviewing Officer will review the casefile and determine if a civil penalty is


394

30 CFR Ch. II (7–1–01 Edition)§ 250.1406

appropriate. The Reviewing Officermay administer oaths and issue sub-poenas requiring witnesses to attendmeetings, submit depositions, orproduce evidence.

[62 FR 42668, Aug. 8, 1997. Redesignated andamended at 63 FR 29479, 29487, May 29, 1998]

§ 250.1406 When will MMS notify meand provide penalty information?

If the Reviewing Officer determinesthat a civil penalty should be assessed,the Reviewing Officer will send the vio-lator a letter of notification. The letterof notification will include:

(a) The amount of the proposed civilpenalty;

(b) Information on the violation(s);and

(c) Instruction on how to obtain acopy of the case file, schedule a meet-ing, submit information, or pay thepenalty.

[62 FR 42668, Aug. 8, 1997. Redesignated at 63FR 29479, May 29, 1998; 64 FR 9066, Feb. 24,1999]

§ 250.1407 How do I respond to the let-ter of notification?

You have 30 calendar days after youreceive the Reviewing Officer’s letterto either:

(a) Request, in writing, a meetingwith the Reviewing Officer;

(b) Submit additional information; or(c) Pay the proposed civil penalty.

§ 250.1408 When will I be notified ofthe Reviewing Officer’s decision?

At the end of the 30 calendar days orafter the meeting and submittal of ad-ditional information, the ReviewingOfficer will review the case file, includ-ing all information you submitted, andsend you a decision. The decision willinclude the amount of any final civilpenalty, the basis for the civil penalty,and instructions for paying or appeal-ing the civil penalty.

§ 250.1409 What are my appeal rights?(a) When you receive the Reviewing

Officer’s final decision, you have 60days to either pay the penalty or filean appeal in accordance with 30 CFRpart 290, subpart A.

(b) If you file an appeal, you must ei-ther:

(1) Submit a surety bond in theamount of the penalty to the RegionalAdjudication Office in the Regionwhere the penalty was assessed, fol-lowing instructions that the ReviewingOfficer will include in the final deci-sion; or

(2) Notify the Regional AdjudicationOffice, in the Region where the penaltywas assessed, that you want your lease-specific/area-wide bond on file to beused as the bond for the penaltyamount.

(c) If you choose the alternative inparagraph (b)(2) of this section, the Re-gional Director may require additionalsecurity (i.e., security in excess of yourexisting bond) to ensure sufficient cov-erage during an appeal. In that event,the Regional Director will require youto post the supplemental bond with theregional office in the same manner asunder §§ 256.53(d) through (f) of thischapter. If the Regional Director deter-mines the appeal should be covered bya lease-specific abandonment accountthen you must establish an accountthat meets the requirements of § 256.56.

(d) If you do not either pay the pen-alty or file a timely appeal, MMS willtake one or more of the following ac-tions:

(1) We will collect the amount youwere assessed, plus interest, late pay-ment charges, and other fees as pro-vided by law, from the date you re-ceived the Reviewing Officer’s final de-cision until the date we receive pay-ment;

(2) We may initiate additional en-forcement, including, if appropriate,cancellation of the lease, right-of-way,license, permit, or approval, or the for-feiture of a bond under this part; or

(3) We may bar you from doing fur-ther business with the Federal Govern-ment according to Executive Orders12549 and 12689, and section 2455 of theFederal Acquisition Streamlining Actof 1994, 31 U.S.C. 6101. The Departmentof the Interior’s regulations imple-menting these authorities are found at43 CFR part 12, subpart D.

[64 FR 26257, May 13, 1999, as amended at 65FR 2875, Jan. 19, 2000]


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Subpart O—Well Control andProduction Safety Training

SOURCE: 65 FR 49490, Aug. 14, 2000, unlessotherwise noted.

§ 250.1500 Definitions.Terms used in this subpart have the

following meaning:Employee means direct employees of

the lessees who are assigned well con-trol or production safety duties.

I or you means the lessee engaged inoil, gas, or sulphur operations in theOuter Continental Shelf (OCS).

Lessee means a person who has en-tered into a lease with the UnitedStates to explore for, develop, andproduce the leased minerals. The termlessee also includes an owner of oper-ating rights for that lease and theMMS-approved assignee of that lease.

Production safety means productionoperations as well as the installation,repair, testing, maintenance, or oper-ation of surface or subsurface safetydevices.

Well control means drilling, well com-pletion, well workover, and well serv-icing operations. For purposes of thissubpart, well completion/well workovermeans those operations following thedrilling of a well that are intended toestablish or restore production to awell. It includes small tubing oper-ations but does not include well serv-icing. Well servicing means snubbing,coil tubing, and wireline operations.

§ 250.1501 What is the goal of my train-ing program?

The goal of your training programmust be safe and clean OCS operations.To accomplish this, you must ensurethat your employees and contract per-sonnel engaged in well control or pro-duction safety operations understandand can properly perform their duties.

§ 250.1502 Is there a transition periodfor complying with the regulationsin this subpart?

(a) During the period October 13, 2000until October 15, 2002 you may either:

(1) Comply with the provisions of thissubpart. If you elect to do so, you mustnotify the Regional Supervisor; or

(2) Comply with the training regula-tions in 30 CFR 250.1501 through 250.1524

that were in effect on June 1, 2000 andare contained in the 30 CFR, parts 200to 699, edition revised as of July 1, 1999,as amended on December 28, 1999 (64 FR72794).

(b) After October 15, 2002, you mustcomply with the provisions of this sub-part.

§ 250.1503 What are my general re-sponsibilities for training?

(a) You must establish and imple-ment a training program so that all ofyour employees are trained to com-petently perform their assigned wellcontrol and production safety duties.You must verify that your employeesunderstand and can perform the as-signed well control or production safe-ty duties.

(b) You must have a training planthat specifies the type, method(s),length, frequency, and content of thetraining for your employees. Yourtraining plan must specify the meth-od(s) of verifying employee under-standing and performance. This planmust include at least the following in-formation:

(1) Procedures for training employeesin well control or production safetypractices;

(2) Procedures for evaluating thetraining programs of your contractors;

(3) Procedures for verifying that allemployees and contractor personnelengaged in well control or productionsafety operations can perform their as-signed duties;

(4) Procedures for assessing the train-ing needs of your employees on a peri-odic basis;

(5) Recordkeeping and documenta-tion procedures; and

(6) Internal audit procedures.(c) Upon request of the Regional or

District Supervisor, you must provide:(1) Copies of training documentation

for personnel involved in well controlor production safety operations duringthe past 5 years; and

(2) A copy of your training plan.

§ 250.1504 May I use alternative train-ing methods?

You may use alternative trainingmethods. These methods may includecomputer-based learning, films, ortheir equivalents. This training should


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be reinforced by appropriate dem-onstrations and ‘‘hands-on’’ training.Alternative training methods must beconducted according to, and meet theobjectives of, your training plan.

§ 250.1505 Where may I get training formy employees?

You may get training from anysource that meets the requirements ofyour training plan.

§ 250.1506 How often must I train myemployees?

You determine the frequency of thetraining you provide your employees.You must do all of the following:

(a) Provide periodic training to en-sure that employees maintain under-standing of, and competency in, wellcontrol or production safety practices;

(b) Establish procedures to verifyadequate retention of the knowledgeand skills that employees need to per-form their assigned well control or pro-duction safety duties; and

(c) Ensure that your contractors’training programs provide for periodictraining and verification of well con-trol or production safety knowledgeand skills.

§ 250.1507 How will MMS measuretraining results?

MMS may periodically assess yourtraining program, using one or more ofthe methods in this section.

(a) Training system audit. MMS or itsauthorized representative may conducta training system audit at your office.The training system audit will com-pare your training program againstthis subpart. You must be prepared toexplain your overall training programand produce evidence to support yourexplanation.

(b) Employee or contract personnelinterviews. MMS or its authorized rep-resentative may conduct interviews ateither onshore or offshore locations toinquire about the types of trainingthat were provided, when and wherethis training was conducted, and howeffective the training was.

(c) Employee or contract personnel test-ing. MMS or its authorized representa-tive may conduct testing at either on-shore or offshore locations for the pur-pose of evaluating an individual’s

knowledge and skills in perfecting wellcontrol and production safety duties.

(d) Hands-on production safety, simu-lator, or live well testing. MMS or its au-thorized representative may conducttests at either onshore or offshore loca-tions. Tests will be designed to evalu-ate the competency of your employeesor contract personnel in performingtheir assigned well control and produc-tion safety duties. You are responsiblefor the costs associated with this test-ing, excluding salary and travel costsfor MMS personnel.

§ 250.1508 What must I do when MMSadministers written or oral tests?

MMS or its authorized representativemay test your employees or contractpersonnel at your worksite or at an on-shore location. You and your contrac-tors must:

(a) Allow MMS or its authorized rep-resentative to administer written ororal tests; and

(b) Identify personnel by current po-sition, years of experience in presentposition, years of total oil field experi-ence, and employer’s name (e.g., oper-ator, contractor, or sub-contractorcompany name).

§ 250.1509 What must I do when MMSadministers or requires hands-on,simulator, or other types of testing?

If MMS or its authorized representa-tive conducts, or requires you or yourcontractor to conduct hands-on, simu-lator, or other types of testing, youmust:

(a) Allow MMS or its authorized rep-resentative to administer or witnessthe testing;

(b) Identify personnel by current po-sition, years of experience in presentposition, years of total oil field experi-ence, and employer’s name (e.g., oper-ator, contractor, or sub-contractorcompany name); and

(c) Pay for all costs associated withthe testing, excluding salary and travelcosts for MMS personnel.

§ 250.1510 What will MMS do if mytraining program does not complywith this subpart?

If MMS determines that your train-ing program is not in compliance, we


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may initiate one or more of the fol-lowing enforcement actions:

(a) Issue an Incident of Noncompli-ance (INC);

(b) Require you to revise and submitto MMS your training plan to addressidentified deficiencies;

(c) Assess civil/criminal penalties; or(d) Initiate disqualification proce-

dures.

Subpart P—Sulphur Operations

SOURCE: 56 FR 32100, July 15, 1991, unlessotherwise noted. Redesignated at 63 FR 29479,May 29, 1998.

§ 250.1600 Performance standard.Operations to discover, develop, and

produce sulphur in the OCS shall be inaccordance with an approved Explo-ration Plan or Development and Pro-duction Plan and shall be conducted ina manner to protect against harm ordamage to life (including fish and otheraquatic life), property, natural re-sources of the OCS including any min-eral deposits (in areas leased or notleased), the national security or de-fense, and the marine, coastal, orhuman environment.

§ 250.1601 Definitions.Terms used in this subpart shall have

the meanings as defined below:Air line means a tubing string that is

used to inject air within a sulphur pro-ducing well to airlift sulphur out of thewell.

Bleedwater means a mixture of minewater or booster water and connatewater that is produced by a bleedwell.

Bleedwell means a well drilled into aproducing sulphur deposit that is usedto control the mine pressure generatedby the injection of mine water.

Brine means the water containingdissolved salt obtained from a brinewell by circulating water into and outof a cavity in the salt core of a saltdome.

Brine well means a well drilledthrough cap rock into the core at a saltdome for the purpose of producingbrine.

Cap rock means the rock formation, abody of limestone, anhydride, and/orgypsum, overlying a salt dome.

Sulphur deposit means a formation ofrock that contains elemental sulphur.

Sulphur production rate means thenumber of long tons of sulphur pro-duced during a certain period of time,usually per day.

§ 250.1602 Applicability.

(a) The requirements of this subpartP are applicable to all exploration, de-velopment, and production operationsunder an OCS sulphur lease. Sulphuroperations include all activities con-ducted under a lease for the purpose ofdiscovery or delineation of a sulphurdeposit and for the development andproduction of elemental sulphur. Sul-phur operations also include activitiesconducted for related purposes. Activi-ties conducted for related purposes in-clude, but are not limited to, produc-tion of other minerals, such as salt, foruse in the exploration for or the devel-opment and production of sulphur. Thelessee must have obtained the right toproduce and/or use these other min-erals.

(b) Lessees conducting sulphur oper-ations in the OCS shall comply withthe requirements of the applicable pro-visions of subparts A, B, C, G, I, J, M,N, and O of this part.

(c) Lessees conducting sulphur oper-ations in the OCS are also required tocomply with the requirements in theapplicable provisions of subparts D, E,F, H, K, and L of this part where suchprovisions specifically are referencedin this subpart.

§ 250.1603 Determination of sulphurdeposit.

(a) Upon receipt of a written requestfrom the lessee, the District Supervisorwill determine whether a sulphur de-posit has been defined that containssulphur in paying quantities (i.e., sul-phur in quantities sufficient to yield areturn in excess of the costs, after com-pletion of the wells, of producing min-erals at the wellheads).

(b) A determination under paragraph(a) of this section shall be based uponthe following:

(1) Core analyses that indicate thepresence of a producible sulphur de-posit (including an assay of elementalsulphur);


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(2) An estimate of the amount of re-coverable sulphur in long tons over aspecified period of time; and

(3) Contour map of the cap rock to-gether with isopach map showing theextent and estimated thickness of thesulphur deposit.

§ 250.1604 General requirements.Sulphur lessees shall comply with re-

quirements of this section when con-ducting well-drilling, well-completion,well-workover, or production oper-ations.

(a) Equipment movement. The move-ment of well-drilling, well-completion,or well-workover rigs and relatedequipment on and off an offshore plat-form, or from one well to another wellon the same offshore platform, includ-ing rigging up and rigging down, shallbe conducted in a safe manner.

(b) Hydrogen sulfide (H2S). When adrilling, well-completion, well-workover, or production operation isbeing conducted on a well in zonesknown to contain H2S or in zoneswhere the presence of H2S is unknown(as defined in 30 CFR 250.417 of thispart), the lessee shall take appropriateprecautions to protect life and prop-erty, especially during operations suchas dismantling wellhead equipment andflow lines and circulating the well. Thelessee shall also take appropriate pre-cautions when H2S is generated as a re-sult of sulphur production operations.The lessee shall comply with the re-quirements in § 250.417 of this part aswell as the requirements of this sub-part.

(c) Welding and burning practices andprocedures. All welding, burning, andhot-tapping activities involved in drill-ing, well-completion, well-workover orproduction operations shall be con-ducted with properly maintained equip-ment, trained personnel, and appro-priate procedures in order to minimizethe danger to life and property accord-ing to the specific requirements in§ 250.402 of this part.

(d) Electrical requirements. All elec-trical equipment and systems involvedin drilling, well-completion, well-workover, and production operationsshall be designed, installed, equipped,protected, operated, and maintained soas to minimize the danger to life and

property in accordance with the re-quirements of § 250.403 of this part.

(e) Structures on fixed OCS platforms.Derricks, cranes, masts, substructures,and related equipment shall be se-lected, designed, installed, used, andmaintained so as to be adequate for thepotential loads and conditions of load-ing that may be encountered duringthe operations. Prior to moving equip-ment such as a well-drilling, well-com-pletion, or well-workover rig or associ-ated equipment or production equip-ment onto a platform, the lessee shalldetermine the structural capability ofthe platform to safely support theequipment and operations, taking intoconsideration corrosion protection,platform age, and previous stresses.

(f) Traveling-block safety device. AfterAugust 14, 1992, all drilling units beingused for drilling, well-completion, orwell-workover operations that haveboth a traveling block and a crownblock shall be equipped with a safetydevice that is designed to prevent thetraveling block from striking thecrown block. The device shall bechecked for proper operation weeklyand after each drill-line slipping oper-ation. The results of the operationalcheck shall be entered in the oper-ations log.

[56 FR 32100, July 15, 1991. Redesignated andamended at 63 FR 29479, 29487, May 29, 1998]

§ 250.1605 Drilling requirements.(a) Lessees of OCS sulphur leases

shall conduct drilling operations in ac-cordance with §§ 250.1605 through250.1619 of this subpart and with otherrequirements of this part, as appro-priate.

(b) Fitness of drilling unit. (1) Drillingunits shall be capable of withstandingthe oceanographic and meteorologicalconditions for the proposed season andlocation of operations.

(2) Prior to commencing operation,drilling units shall be made availablefor a complete inspection by the Dis-trict Supervisor.

(3) The lessee shall provide informa-tion and data on the fitness of thedrilling unit to perform the proposeddrilling operation. The informationshall be submitted with, or prior to,the submission of Form MMS–123, Ap-plication for Permit to Drill (APD), in


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accordance with § 250.1617 of this sub-part. After a drilling unit has been ap-proved by an MMS district office, theinformation required in this paragraphneed not be resubmitted unless re-quired by the District Supervisor orthere are changes in the equipmentthat affect the rated capacity of theunit.

(c) Oceanographic, meteorological, anddrilling unit performance data. Whereoceanographic, meteorological, anddrilling unit performance data are nototherwise readily available, lesseesshall collect and report such data uponrequest to the District Supervisor. Thetype of information to be collected andreported will be determined by the Dis-trict Supervisor in the interests ofsafety in the conduct of operations andthe structural integrity of the drillingunit.

(d) Foundation requirements. When thelessee fails to provide sufficient infor-mation pursuant to §§ 250.203 and 250.204of this part to support a determinationthat the seafloor is capable of sup-porting a specific bottom-founded drill-ing unit under the site-specific soil andoceanographic conditions, the DistrictSupervisor may require that additionalsurveys and soil borings be performedand the results submitted for reviewand evaluation by the District Super-visor before approval is granted forcommencing drilling operations.

(e) Tests, surveys, and samples. (1) Les-sees shall drill and take cores and/orrun well and mud logs through the ob-jective interval to determine the pres-ence, quality, and quantity of sulphurand other minerals (e.g., oil and gas) inthe cap rock and the outline of thecommercial sulphur deposit.

(2) Inclinational surveys shall be ob-tained on all vertical wells at intervalsnot exceeding 1,000 feet during the nor-mal course of drilling. Directional sur-veys giving both inclination and azi-muth shall be obtained on all direc-tionally drilled wells at intervals notexceeding 500 feet during the normalcourse of drilling and at intervals notexceeding 200 feet in all planned angle-change portions of the borehole.

(3) Directional surveys giving bothinclination and azimuth shall be ob-tained on both vertically and direc-

tionally drilled wells at intervals notexceeding 500 feet prior to or upon set-ting a string of casing, or productionliner, and at total depth. Composite di-rectional surveys shall be preparedwith the interval shown from the bot-tom of the conductor casing. In calcu-lating all surveys, a correction fromthe true north to Universal-Trans-verse-Mercator-Grid-north or Lambert-Grid-north shall be made after makingthe magnetic-to-true-north correction.A composite dipmeter directional sur-vey or a composite measurementwhile-drilling directional survey willbe acceptable as fulfilling the applica-ble requirements of this paragraph.

(4) Wells are classified as vertical ifthe calculated average of inclinationreadings weighted by the respective in-terval lengths between readings fromsurface to drilled depth does not exceed3 degrees from the vertical. When thecalculated average inclination readingsweighted by the length of the respec-tive interval between readings from thesurface to drilled depth exceeds 3 de-grees, the well is classified as direc-tional.

(5) At the request of a holder of anadjoining lease, the Regional Super-visor may, for the protection of correl-ative rights, furnish a copy of the di-rectional survey to that leaseholder.

(f) Fixed drilling platforms. Applica-tions for installation of fixed drillingplatforms or structures including arti-ficial islands shall be submitted in ac-cordance with the provisions of subpartI, Platforms and Structures, of thispart. Mobile drilling units that havetheir jacking equipment removed orhave been otherwise immobilized areclassified as fixed bottom founded drill-ing platforms.

(g) Crane operations. You must oper-ate a crane installed on fixed platformsaccording to § 250.108 of this subpart.

(h) Diesel-engine air intakes. After Au-gust 14, 1992, diesel-engine air intakesshall be equipped with a device to shutdown the diesel engine in the event ofrunaway. Diesel engines that are con-tinuously attended shall be equippedwith either remote-operated manual or


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automatic-shutdown devices. Diesel en-gines that are not continuously at-tended shall be equipped with auto-matic shutdown devices.

[56 FR 32100, July 15, 1991, as amended at 58FR 49928, Sept. 24, 1993. Redesignated andamended at 63 FR 29479, 29487, May 29, 1998; 63FR 34597, June 25, 1998; 65 FR 15864, Mar. 24,2000]

§ 250.1606 Control of wells.

The lessee shall take necessary pre-cautions to keep its wells under con-trol at all times. Operations shall beconducted in a safe and workmanlikemanner. The lessee shall utilize thebest available and safest drilling tech-nologies and state-of-the-art methodsto evaluate and minimize the potentialfor a well to flow or kick. The lesseeshall utilize personnel who are trainedand competent and shall utilize andmaintain equipment and materials nec-essary to assure the safety and protec-tion of personnel, equipment, naturalresources, and the environment.

§ 250.1607 Field rules.

When geological and engineering in-formation in a field enables a DistrictSupervisor to determine specific oper-ating requirements, field rules may beestablished for drilling, well comple-tion, or well workover on the DistrictSupervisor’s initiative or in responseto a request from a lessee; such rulesmay modify the specific requirementsof this subpart. After field rules havebeen established, operations in thefield shall be conducted in accordancewith such rules and other requirementsof this subpart. Field rules may beamended or canceled for cause at anytime upon the initiative of the DistrictSupervisor or upon the request of a les-see.

§ 250.1608 Well casing and cementing.

(a) General requirements. (1) For thepurpose of this subpart, the severalcasing strings in order of normal in-stallation are:

(i) Drive or structural,(ii) Conductor,(iii) Cap rock casing,(iv) Bobtail cap rock casing (required

when the cap rock casing does not pen-etrate into the cap rock),

(v) Second cap rock casing (brinewells), and

(vi) Production liner.(2) The lessee shall case and cement

all wells with a sufficient number ofstrings of casing cemented in a mannernecessary to prevent release of fluidsfrom any stratum through the wellbore(directly or indirectly) into the sea,protect freshwater aquifers from con-tamination, support unconsolidatedsediments, and otherwise provide ameans of control of the formation pres-sures and fluids. Cement composition,placement techniques, and waitingtime shall be designed and conductedso that the cement in place behind thebottom 500 feet of casing or totallength of annular cement fill, if less,attains a minimum compressivestrength of 160 pounds per square inch(psi).

(3) The lessee shall install casing de-signed to withstand the anticipatedstresses imposed by tensile, compres-sive, and buckling loads; burst and col-lapse pressures; thermal effects; andcombinations thereof. Safety factors inthe drilling and casing program designsshall be of sufficient magnitude to pro-vide well control during drilling and toassure safe operations for the life ofthe well.

(4) In cases where cement has filledthe annular space back to the mudline, the cement may be washed out ordisplaced to a depth not exceeding thedepth of the structural casing shoe tofacilitate casing removal upon wellabandonment if the District Supervisordetermines that subsurface protectionagainst damage to freshwater aquifersand against damage caused by adverseloads, pressures, and fluid flows is notjeopardized.

(5) If there are indications of inad-equate cementing (such as lost returns,cement channeling, or mechanical fail-ure of equipment), the lessee shallevaluate the adequacy of the cement-ing operations by pressure testing thecasing shoe. If the test indicates inad-equate cementing, the lessee shall ini-tiate remedial action as approved bythe District Supervisor. For cap rockcasing, the test for adequacy of ce-menting shall be the pressure testingof the annulus between the cap rock


401


and the conductor casings. The pres-sure shall not exceed 70 percent of theburst pressure of the conductor casingor 70 percent of the collapse pressure ofthe cap rock casing.

(b) Drive or structural casing. This cas-ing shall be set by driving, jetting, ordrilling to a minimum depth of 100 feetbelow the mud line or such otherdepth, as may be required or approvedby the District Supervisor, in order tosupport unconsolidated deposits and toprovide hole stability for initial drill-ing operations. If this portion of thehole is drilled, a quantity of cementsufficient to fill the annular space backto the mud line shall be used.

(c) Conductor and cap rock casing set-ting and cementing requirements. (1) Con-ductor and cap rock casing design andsetting depths shall be based upon rel-evant engineering and geologic factorsincluding the presence or absence ofhydrocarbons, potential hazards, andwater depths. The proposed casing set-ting depths may be varied, subject toDistrict Supervisor approval, to permitthe casing to be set in a competent for-mation or through formations deter-mined desirable to be isolated from thewellbore by casing for safer drilling op-erations. However, the conductor cas-ing shall be set immediately prior todrilling into formations known to con-tain oil or gas or, if unknown, upon en-countering such formations. Cap rockcasing shall be set and cementedthrough formations known to containoil or gas or, if unknown, upon encoun-tering such formations. Upon encoun-tering unexpected formation pressures,the lessee shall submit a revised casingprogram to the District Supervisor forapproval.

(2) Conductor casing shall be ce-mented with a quantity of cement thatfills the calculated annular space backto the mud line. Cement fill shall beverified by the observation of cementreturns. In the event that observationof cement returns is not feasible, addi-tional quantities of cement shall beused to assure fill to the mud line.

(3) Cap rock casing shall be cementedwith a quantity of cement that fills thecalculated annular space to at least 200feet inside the conductor casing. Whengeologic conditions such as near sur-face fractures and faulting exist, cap

rock casing shall be cemented with aquantity of cement that fills the cal-culated annular space to the mud line,unless otherwise approved by the Dis-trict Supervisor. In brine wells, thesecond cap rock casing shall be ce-mented with a quantity of cement thatfills the calculated annular space to atleast 200 feet above the setting depth ofthe first cap rock casing.

(d) Bobtail cap rock casing setting andcementing requirements. (1) Bobtail caprock casing shall be set on or just incap rock and lapped a minimum of 100feet into the previous casing string.

(2) Sufficient cement shall be used tofill the annular space to the top of thebobtail cap rock casing.

(e) Production liner setting and cement-ing requirements. (1) Production linersfor sulphur wells and bleedwells shallbe set in cap rock at or above the bot-tom of the open hole (hole that is openin cap rock, below the bottom of thecap rock casing) and lapped into theprevious casing string or to the sur-face. For brine wells, the liner shall beset in salt and lapped into the previouscasing string or to the surface.

(2) The production liner is not re-quired to be cemented unless the caprock contains oil or gas. If the cap rockcontains oil or gas, sufficient cementshall be used to fill the annular spaceto the top of the production liner.

§ 250.1609 Pressure testing of casing.(a) Prior to drilling the plug after ce-

menting, all casing strings, except thedrive or structural casing, shall bepressure tested. The conductor casingshall be tested to at least 200 psi. Allcasing strings below the conductor cas-ing shall be tested to 500 psi or 0.22 psi/ft, whichever is greater. (When oil orgas is not present in the cap rock, theproduction liner need not be cementedin place; thus, it would not be subjectto pressure testing.) If the pressure de-clines more than 10 percent in 30 min-utes or if there is another indication ofa leak, the casing shall be recemented,repaired, or an additional casing stringrun and the casing tested again. Theabove procedures shall be repeateduntil a satisfactory test is obtained.The time, conditions of testing, and re-sults of all casing pressure tests shallbe recorded in the driller’s report.


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(b) After cementing any string of cas-ing other than structural, drilling shallnot be resumed until there has been atimelapse of at least 8 hours underpressure for the conductor casingstring or 12 hours under pressure for allother casing strings. Cement is consid-ered under pressure if one or more floatvalves are shown to be holding the ce-ment in place or when other means ofholding pressure are used.

§ 250.1610 Blowout preventer systemsand system components.

(a) General. The blowout preventer(BOP) systems and system componentsshall be designed, installed, used,maintained, and tested to assure wellcontrol.

(b) BOP stacks. The BOP stacks shallconsist of an annular preventer and thenumber of ram-type preventers as spec-ified under paragraphs (e) and (f) ofthis section. The pipe rams shall be ofproper size to fit the drill pipe in use.

(c) Working pressure. The working-pressure rating of any BOP shall ex-ceed the surface pressure to which itmay be anticipated to be subjected.

(d) BOP equipment. All BOP systemsshall be equipped and provided with thefollowing:

(1) An accumulator system that pro-vides sufficient capacity to supply 1.5times the volume necessary to closeand hold closed all BOP equipmentunits with a minimum pressure of 200psi above the precharge pressure, with-out assistance from a charging system.After February 14, 1992, accumulatorregulators supplied by rig air, which donot have a secondary source of pneu-matic supply, shall be equipped withmanual overrides or other devices al-ternately provided to ensure capabilityof hydraulic operations if rig air islost.

(2) An automatic backup to the accu-mulator system. The backup systemshall be supplied by a power sourceindependent from the power source tothe primary accumulator system. Theautomatic backup system shall possesssufficient capability to close the BOPand hold it closed.

(3) At least one operable remote BOPcontrol station in addition to the oneon the drilling floor. This control sta-

tion shall be in a readily accessible lo-cation away from the drilling floor.

(4) A drilling spool with side outlets,if side outlets are not provided in thebody of the BOP stack, to provide forseparate kill and choke lines.

(5) A choke line and a kill line eachequipped with two full-opening valves.At least one of the valves on the chokeline and one valve on the kill line shallbe remotely controlled, except that acheck valve may be installed on thekill line in lieu of the remotely con-trolled valve, provided that two readilyaccessible manual valves are in placeand the check valve is placed betweenthe manual valve and the pump.

(6) A fill-up line above the uppermostpreventer.

(7) A choke manifold designed withconsideration of anticipated pressuresto which it may be subjected, methodof well control to be employed, sur-rounding environment, and corrosive-ness, volume, and abrasiveness offluids. The choke manifold shall alsomeet the following requirements:

(i) Manifold and choke equipmentsubject to well and/or pump pressureshall have a rated working pressure atleast as great as the rated workingpressure of the ram-type BOP’s or asotherwise approved by the District Su-pervisor;

(ii) All components of the chokemanifold system shall be protectedfrom freezing by heating, draining, orfilling with proper fluids; and

(iii) When buffer tanks are installeddownstream of the choke assembliesfor the purpose of manifolding thebleed lines together, isolation valvesshall be installed on each line.

(8) Valves, pipes, flexible steel hoses,and other fittings upstream of, and in-cluding, the choke manifold with apressure rating at least as great as therated working pressure of the ram-typeBOP’s unless otherwise approved bythe District Supervisor.

(9) A wellhead assembly with a ratedworking pressure that exceeds the pres-sure to which it might be subjected.

(10) The following system compo-nents:

(i) A kelly cock (an essentially full-opening valve) installed below theswivel and a similar valve of such de-sign that it can be run through the


403


BOP stack installed at the bottom ofthe kelly. A wrench to fit each valveshall be stored in a location readily ac-cessible to the drilling crew;

(ii) An inside BOP and an essentiallyfull-opening, drill-string safety valvein the open position on the rig floor atall times while drilling operations arebeing conducted. These valves shall bemaintained on the rig floor to fit allconnections that are in the drill string.A wrench to fit the drill-string safetyvalve shall be stored in a location read-ily accessible to the drilling crew;

(iii) A safety valve available on therig floor assembled with the properconnection to fit the casing stringbeing run in the hole; and

(iv) Locking devices installed on theram-type preventers.

(e) BOP requirements. Prior to drillingbelow cap rock casing, a BOP systemshall be installed consisting of at leastthree remote-controlled, hydraulicallyoperated BOP’s including at least oneequipped with pipe rams, one withblind rams, and one annular type.

(f) Tapered drill-string operations.Prior to commencing tapered drill-string operations, the BOP stack shallbe equipped with conventional and/orvariable-bore pipe rams to provide ei-ther of the following:

(1) One set of variable bore rams ca-pable of sealing around both sizes inthe string and one set of blind rams, or

(2) One set of pipe rams capable ofsealing around the larger size string,provided that blind-shear ram capa-bility is present, and crossover subs tothe larger size pipe are readily avail-able on the rig floor.

§ 250.1611 Blowout preventer systemstests, actuations, inspections, andmaintenance.

(a) Prior to conducting high-pressuretests, all BOP systems shall be testedto a pressure of 200 to 300 psi.

(b) Ram-type BOP’s and the chokemanifold shall be pressure tested withwater to rated working pressure or asotherwise approved by the District Su-pervisor. Annular type BOP’s shall bepressure tested with water to 70 per-cent of rated working pressure or asotherwise approved by the District Su-pervisor.

(c) In conjunction with the weeklypressure test of BOP systems requiredin paragraph (d) of this section, thechoke manifold valves, upper and lowerkelly cocks, and drill-string safetyvalves shall be pressure tested to pipe-ram test pressures. Safety valves withproper casing connections shall be ac-tuated prior to running casing.

(d) BOP system shall be pressuretested as follows:

(1) When installed;(2) Before drilling out each string of

casing or before continuing operationsin cases where cement is not drilledout;

(3) At least once each week, but notexceeding 7 days between pressuretests, alternating between control sta-tions. If either control system is notfunctional, further drilling operationsshall be suspended until that systembecomes operable. A period of morethan 7 days between BOP tests is al-lowed when there is a stuck drill pipeor there are pressure control oper-ations and remedial efforts are beingperformed, provided that the pressuretests are conducted as soon as possibleand before normal operations resume.The date, time, and reason for post-poning pressure testing shall be en-tered into the driller’s report. Pressuretesting shall be performed at intervalsto allow each drilling crew to operatethe equipment. The weekly pressuretest is not required for blind and blind-shear rams;

(4) Bind and blind-shear rams shall beactuated at least once every 7 days.Closing pressure on the blind and blind-shear rams greater than necessary toindicate proper operation of the ramsis not required;

(5) Variable bore-pipe rams shall bepressure tested against all sizes of pipein use, excluding drill collars andbottomhole tools; and

(6) Following the disconnection or re-pair of any well-pressure containmentseal in the wellhead/BOP stack assem-bly. In this situation, the pressuretests may be limited to the affectedcomponent.

(e) All BOP systems shall be in-spected and maintained to assure thatthe equipment will function properly.The BOP systems shall be visually in-spected at least once each day. The


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30 CFR Ch. II (7–1–01 Edition)§ 250.1612

manufacturer’s recommended inspec-tion and maintenance procedures areacceptable as guidelines in complyingwith this requirement.

(f) The lessee shall record pressureconditions during BOP tests on pres-sure charts, unless otherwise approvedby the District Supervisor. The test du-ration for each BOP component testedshall be sufficient to demonstrate thatthe component is effectively holdingpressure. The charts shall be certifiedas correct by the operator’s representa-tive at the facility.

(g) The time, date, and results of allpressure tests, actuations, inspections,and crew drills of the BOP system andsystem components shall be recordedin the driller’s report. The BOP testsshall be documented in accordancewith the following:

(1) The documentation shall indicatethe sequential order of BOP and auxil-iary equipment testing and the pres-sure and duration of each test. As analternate, the documentation in thedriller’s report may reference a BOPtest plan that contains the required in-formation and is retained on file at thefacility.

(2) The control station used duringthe test shall be identified in thedriller’s report.

(3) Any problems or irregularities ob-served during BOP and auxiliary equip-ment testing and any actions taken toremedy such problems or irregularitiesshall be noted in the driller’s report.

(4) Documentation required to be en-tered in the driller’s report may in-stead be referenced in the driller’s re-port. All records, including pressurecharts, driller’s report, and referenceddocuments, pertaining to BOP tests,actuations, and inspections, shall beavailable for MMS review at the facil-ity for the duration of the drilling ac-tivity. Following completion of thedrilling activity, all drilling recordsshall be retained for a period of 2 yearsat the facility, at the lessee’s field of-fice nearest the OCS facility, or at an-other location conveniently availableto the District Supervisor.

§ 250.1612 Well-control drills.Well-control drills shall be conducted

for each drilling crew in accordancewith the requirements set forth in

§ 250.408 of this part or as approved bythe District Supervisor.


§ 250.1613 Diverter systems.(a) When drilling a conductor or cap

rock hole, all drilling units shall beequipped with a diverter system con-sisting of a diverter sealing element,diverter lines, and control systems.The diverter system shall be designed,installed, and maintained so as to di-vert gases, water, mud, and other ma-terials away from the facilities andpersonnel.

(b) After August 14, 1992, diverter sys-tems shall be in compliance with therequirements of this section.

The requirements applicable todiverters that were in effect imme-diately prior to August 14, 1991, shallremain in effect until August 14, 1992.

(c) The diverter system shall beequipped with remote-control valves inthe flow lines that can be operatedfrom at least one remote-control sta-tion in addition to the one on the drill-ing floor. Any valve used in a divertersystem shall be full opening. No man-ual or butterfly valves shall be in-stalled in any part of a diverter sys-tem. There shall be a minimum numberof turns in the vent line(s) downstreamof the spool outlet flange, and the ra-dius of curvature of turns shall be aslarge as practicable. Flexible hose maybe used for diversion lines instead ofrigid pipe if the flexible hose has inte-gral end couplings. The entire divertersystem shall be firmly anchored andsupported to prevent whipping and vi-brations. All diverter control equip-ment and lines shall be protected fromphysical damage from thrown and fall-ing objects.

(d) For drilling operations conductedwith a surface wellhead configuration,the following shall apply:

(1) If the diverter system utilizesonly one spool outlet, branch linesshall be installed to provide downwinddiversion capability, and

(2) No spool outlet or diverter line in-ternal diameter shall be less than 10inches, except that dual spool outletsare acceptable if each outlet has a min-imum internal diameter of 8 inches,and both outlets are piped to overboard


405


lines and that each line downstream ofthe changeover nipple at the spool hasa minimum internal diameter of 10inches.

(e) The diverter sealing element anddiverter valves shall be pressure testedto a minimum of 200 psi when nippledupon conductor casing. No more than 7days shall elapse between subsequentpressure tests. The diverter sealing ele-ment, diverter valves, and diverter con-trol systems (including the remote)shall be actuation tested, and the di-verter lines shall be tested for flowprior to spudding and thereafter atleast once each 24-hour period alter-nating between control stations. Alltest times and results shall be recordedin the driller’s report.

§ 250.1614 Mud program.(a) The quantities, characteristics,

use, and testing of drilling mud and therelated drilling procedures shall be de-signed and implemented to prevent theloss of well control.

(b) The lessee shall comply with re-quirements concerning mud control,mud test and monitoring equipment,mud quantities, and safety precautionsin enclosed mud handling areas as pre-scribed in § 250.410 (b), (c), (d), and (e) ofthis part, except that the installationof an operable degasser in the mud sys-tem as required in § 250.410(b)(8) is notrequired for sulphur operations.


§ 250.1615 Securing of wells.A downhole-safety device such as a

cement plug, bridge plug, or packershall be timely installed when drillingoperations are interrupted by eventssuch as those that force evacuation ofthe drilling crew, prevent station keep-ing, or require repairs to major drillingunits or well-control equipment. Theuse of blind-shear rams or pipe ramsand an inside BOP may be approved bythe District Supervisor in lieu of theabove requirements if cap rock casinghas been set.

§ 250.1616 Supervision, surveillance,and training.

(a) The lessee shall provide onsite su-pervision of drilling operations at alltimes.

(b) From the time drilling operationsare initiated and until the well is com-pleted or abandoned, a member of thedrilling crew or the toolpusher shallmaintain rig-floor surveillance con-tinuously, unless the well is securedwith BOP’s, bridge plugs, packers, orcement plugs.

(c) Lessee and drilling contractorpersonnel shall be trained and qualifiedin accordance with the provisions ofsubpart O of this part. Records of spe-cific training that lessee and drillingcontractor personnel have successfullycompleted, the dates of completion,and the names and dates of the coursesshall be maintained at the drill site.

§ 250.1617 Application for permit todrill.

(a) Prior to commencing the drillingof a well under an approved Explo-ration Plan, Development and Produc-tion Plan, or Development OperationsCoordination Document, the lesseeshall file Form MMS–123, APD, withthe District Supervisor for approval.Prior to commencing operations, writ-ten approval from the District Super-visor must be received by the lessee un-less oral approval has been given pur-suant to § 250.140 of this part.

(b) An APD shall include rated capac-ities of the proposed drilling unit andof major drilling equipment. After adrilling unit has been approved for usein an MMS district, the informationneed not be resubmitted unless re-quired by the District Supervisor orthere are changes in the equipmentthat affect the rated capacity of theunit.

(c) An APD shall include a fully com-pleted Form MMS–123 and the fol-lowing:

(1) A plat, drawn to a scale of 2,000feet to the inch, showing the surfaceand subsurface location of the well tobe drilled and of all the wells pre-viously drilled in the vicinity fromwhich information is available. For de-velopment wells on a lease, the wellspreviously drilled in the vicinity neednot be shown on the plat. Locationsshall be indicated in feet from thenearest block line;

(2) The design criteria considered forthe well and for well control, includingthe following:


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30 CFR Ch. II (7–1–01 Edition)§ 250.1618

(i) Pore pressure;(ii) Formation fracture gradients;(iii) Potential lost circulation zones;(iv) Mud weights;(v) Casing setting depths;(vi) Anticipated surface pressures

(which for purposes of this section aredefined as the pressure that can rea-sonably be expected to be exerted upona casing string and its related wellheadequipment). In the calculation of an-ticipated surface pressure, the lesseeshall take into account the drilling,completion, and producing conditions.The lessee shall consider mud densitiesto be used below various casing strings,fracture gradients of the exposed for-mations, casing setting depths, and ce-menting intervals, total well depth,formation fluid type, and other perti-nent conditions. Considerations for cal-culating anticipated surface pressuremay vary for each segment of the well.The lessee shall include as a part of thestatement of anticipated surface pres-sure the calculations used to determinethis pressure during the drilling phaseand the completion phase, includingthe anticipated surface pressure usedfor production string design; and

(vii) If a shallow hazards site surveyis conducted, the lessee shall submitwith or prior to the submittal of theAPD, two copies of a summary reportdescribing the geological and manmadeconditions present. The lessee shallalso submit two copies of the site mapsand data records identified in the sur-vey strategy.

(3) A BOP equipment program includ-ing the following:

(i) The pressure rating of BOP equip-ment,

(ii) A schematic drawing of the di-verter system to be used (plan and ele-vation views) showing spool outlet in-ternal diameter(s); diverter linelengths and diameters, burst strengths,and radius of curvature at each turn;valve type, size, working-pressure rat-ing, and location; the control instru-mentation logic; and the operating pro-cedure to be used by personnel, and

(iii) A schematic drawing of the BOPstack showing the inside diameter ofthe BOP stack and the number of annu-lar, pipe ram, variable-bore pipe ram,blind ram, and blind-shear ram pre-venters.

(4) A casing program including thefollowing:

(i) Casing size, weight, grade, type ofconnection and setting depth, and

(ii) Casing design safety factors fortension, collapse, and burst with theassumptions made to arrive at thesevalues.

(5) The drilling prognosis includingthe following:

(i) Estimated coring intervals,(ii) Estimated depths to the top of

significant marker formations, and(iii) Estimated depths at which en-

counters with fresh water, sulphur, oil,gas, or abnormally pressured water areexpected.

(6) A cementing program includingtype and amount of cement in cubicfeet to be used for each casing string;

(7) A mud program including theminimum quantities of mud and mudmaterials, including weight materials,to be kept at the site;

(8) A directional survey program fordirectionally drilled wells;

(9) An H2S Contingency Plan, if appli-cable, and if not previously submitted;and

(10) Such other information as maybe required by the District Supervisor.

(d) Public information copies of theAPD shall be submitted in accordancewith § 250.190 of this part.

[56 FR 32100, July 15, 1991, as amended at 58FR 49928, Sept. 24, 1993. Redesignated andamended at 63 FR 29479, 29487, May 29, 1998; 64FR 72794, Dec. 28, 1999]

§ 250.1618 Sundry notices and reportson wells.

(a) Notices of the lessee’s intentionto change plans, make changes inmajor drilling equipment, deepen, side-track, or plug back a well, or engage insimilar activities and subsequent re-ports pertaining to such operationsshall be submitted to the District Su-pervisor on Form MMS–124, Sundry No-tices and Reports on Wells. Prior tocommencing operations associatedwith the change, written approvalmust be received from the District Su-pervisor unless oral approval is ob-tained pursuant to § 250.140 of this part.

(b) The Form MMS–124 submittalshall contain a detailed statement ofthe proposed work that will materiallychange from the work described in the


407


approved APD. Information submittedshall include the present state of thewell, including the production linerand last string of casing, the well depthand production zone, and the well’s ca-pability to produce. Within 30 daysafter completion of the work, a subse-quent detailed report of all the workdone and the results obtained shall besubmitted.

(c) Public information copies of FormMMS–124 shall be submitted in accord-ance with § 250.117 of this part.


§ 250.1619 Well records.(a) Complete and accurate records for

each well and all well operations shallbe retained for a period of 2 years atthe lessee’s field office nearest the OCSfacility or at another location conven-iently available to the District Super-visor. The records shall contain a de-scription of any significant malfunc-tion or problem; all the formationspenetrated; the content and characterof sulphur in each formation if coredand analyzed; the kind, weight, size,grade, and setting depth of casing; allwell logs and surveys run in thewellbore; and all other information re-quired by the District Supervisor inthe interests of resource evaluation,prevention of waste, conservation ofnatural resources, protection of correl-ative rights, safety of operations, andenvironmental protection.

(b) When drilling operations are sus-pended or temporarily prohibited underthe provisions of § 250.170 of this part,the lessee shall, within 30 days aftertermination of the suspension or tem-porary prohibition or within 30 daysafter the completion of any activitiesrelated to the suspension or prohibi-tion, transmit to the District Super-visor duplicate copies of the records ofall activities related to and conductedduring the suspension or temporaryprohibition on, or attached to, FormMMS–125, Well Summary Report, orForm MMS–124, Sundry Notices andReports on Wells, as appropriate.

(c) Upon request by the Regional orDistrict Supervisor, the lessee shallfurnish the following:

(1) Copies of the records of any of thewell operations specified in paragraph(a) of this section;

(2) Copies of the driller’s report at afrequency as determined by the Dis-trict Supervisor. Items to be reportedinclude spud dates, casing settingdepths, cement quantities, casing char-acteristics, mud weights, lost returns,and any unusual activities; and

(3) Legible, exact copies of reports oncementing, acidizing, analyses of cores,testing, or other similar services.

(d) As soon as available, the lesseeshall transmit copies of logs and chartsdeveloped by well-logging operations,directional-well surveys, and core anal-yses. Composite logs of multiple runsand directional-well surveys shall betransmitted to the District Supervisorin duplicate as soon as available butnot later than 30 days after completionof such operations for each well.

(e) If the District Supervisor deter-mines that circumstances warrant, thelessee shall submit any other reportsand records of operations in the man-ner and form prescribed by the DistrictSupervisor.


§ 250.1620 Well-completion and well-workover requirements.

(a) Lessees shall conduct well-com-pletion and well-workover operationsin sulphur wells, bleedwells, and brinewells in accordance with §§ 250.1620through 250.1626 of this part and otherprovisions of this part as appropriate(see §§ 250.501 and 250.601 of this part forthe definition of well-completion andwell-workover operations).

(b) Well-completion and well-workover operations shall be conductedin a manner to protect against harm ordamage to life (including fish and otheraquatic life), property, natural re-sources of the OCS including any min-eral deposits (in areas leased and notleased), the national security or de-fense, or the marine, coastal, or humanenvironment.



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30 CFR Ch. II (7–1–01 Edition)§ 250.1621

§ 250.1621 Crew instructions.Prior to engaging in well-completion

or well-workover operations, crewmembers shall be instructed in thesafety requirements of the operationsto be performed, possible hazards to beencountered, and general safety consid-erations to protect personnel, equip-ment, and the environment. Date andtime of safety meetings shall be re-corded and available for MMS review.

§ 250.1622 Approvals and reporting ofwell-completion and well-workoveroperations.

(a) No well-completion or well-workover operation shall begin untilthe lessee receives written approvalfrom the District Supervisor. Approvalfor such operations shall be requestedon Form MMS–124. Approvals by theDistrict Supervisor shall be based upona determination that the operationswill be conducted in a manner to pro-tect against harm or damage to life,property, natural resources of the OCS,including any mineral deposits, the na-tional security or defense, or the ma-rine, coastal, or human environment.

(b) The following information shallbe submitted with Form MMS–124 (orwith Form MMS–123):

(1) A brief description of the well-completion or well-workover proce-dures to be followed;

(2) When changes in existing sub-surface equipment are proposed, a sche-matic drawing showing the well equip-ment; and

(3) Where the well is in zones knownto contain H2S or zones where the pres-ence of H2S is unknown, a descriptionof the safety precautions to be imple-mented.

(c)(1) Within 30 days after comple-tion, Form MMS–125, including a sche-matic of the tubing and the results ofany well tests, shall be submitted tothe District Supervisor.

(2) Within 30 days after completingthe well-workover operation, exceptroutine operations, Form MMS–124shall be submitted to the District Su-pervisor and shall include the results of

any well tests and a new schematic ofthe well if any subsurface equipmenthas been changed.

[56 FR 32100, July 15, 1991, as amended at 58FR 49928, Sept. 24, 1993. Redesignated at 63FR 29479, May 29, 1998]


(a) Well-control fluids, equipment,and operations shall be designed, uti-lized, maintained, and/or tested as nec-essary to control the well in foresee-able conditions and circumstances, in-cluding subfreezing conditions. Thewell shall be ccntinuously monitoredduring well-completion and well-workover operations and shall not beleft unattended at any time unless thewell is shut in and secured;

(b) The following well-control fluidequipment shall be installed, main-tained, and utilized:

(1) A fill-up line above the uppermostBOP,

(2) A well-control fluid-volume meas-uring device for determining fluid vol-umes when filling the hole on trips,and


(c) When coming out of the hole withdrill pipe or a workover string, the an-nulus shall be filled with well-controlfluid before the change in fluid leveldecreases the hydrostatic pressure 75psi or every five stands of drill pipe orworkover string, whichever gives alower decrease in hydrostatic pressure.The number of stands of drill pipe orworkover string and drill collars thatmay be pulled prior to filling the holeand the equivalent well-control fluidvolume shall be calculated and postednear the operator’s station. A mechan-ical, volumetric, or electronic devicefor measuring the amount of well-con-trol fluid required to fill the hole shallbe utilized.


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(a) The BOP system and system com-ponents and related well-control equip-ment shall be designed, used, main-tained, and tested in a manner nec-essary to assure well control in foresee-able conditions and circumstances, in-cluding subfreezing conditions. Theworking pressure of the BOP systemand system components shall equal orexceed the expected surface pressure towhich they may be subjected.

(b) The minimum BOP stack for well-completion operations or for well-workover operations with the tree re-moved shall consist of the following:

(1) Three remote-controlled, hydrau-lically operated preventers includingat least one equipped with pipe rams,one with blind rams, and one annulartype.

(2) When a tapered string is used, theminimum BOP stack shall consist ofeither of the following:

(i) An annular preventer, one set ofvariable bore rams capable of sealingaround both sizes in the string, and oneset of blind rams; or

(ii) An annular preventer, one set ofpipe rams capable of sealing around thelarger size string, a preventer equippedwith blind-shear rams, and a crossoversub to the larger size pipe that shall bereadily available on the rig floor.

(c) The BOP systems for well-comple-tion operations, or for well-workoveroperations with the tree removed, shallbe equipped with the following:

(1) An accumulator system that pro-vides sufficient capacity to supply 1.5times the volume necessary to closeand hold closed all BOP equipmentunits with a minimum pressure of 200psi above the precharge pressure with-out assistance from a charging system.After February 14, 1992, accumulatorregulators supplied by rig air which donot have a secondary source of pneu-matic supply shall be equipped withmanual overrides or alternately otherdevices provided to ensure capability ofhydraulic operations if rig air is lost;

(2) An automatic backup to the accu-mulator system supplied by a powersource independent from the powersource to the primary accumulator sys-tem and possessing sufficient capacity

to close all BOP’s and hold themclosed;

(3) Locking devices for the pipe-rampreventers;

(4) At least one remote BOP-controlstation and one BOP-control station onthe rig floor; and

(5) A choke line and a kill line eachequipped with two full-opening valvesand a choke manifold. One of thechoke-line valves and one of the kill-line valves shall be remotely controlledexcept that a check valve may be in-stalled on the kill line in lieu of the re-motely-controlled valve provided thattwo readily accessible manual valvesare in place, and the check valve isplaced between the manual valve andthe pump.

(d) The minimum BOP-stack compo-nents for well-workover operationswith the tree in place and performedthrough the wellhead inside of the sul-phur line using small diameter jointedpipe (usually 3⁄4 inch to 11⁄4 inch) as awork string; i.e., small-tubing oper-ations, shall consist of the following:

(1) For air line changes, the wellshall be killed prior to beginning oper-ations. The procedures for killing thewell shall be included in the descrip-tion of well-workover procedures in ac-cordance with § 250.1622 of this part.Under these circumstances, no BOPequipment is required.

(2) For other work inside of the sul-phur line, a tubing stripper or annularpreventer shall be installed prior to be-ginning work.

(e) An essentially full-opening, work-string safety valve shall be maintainedon the rig floor at all times duringwell-completion operations. A wrenchto fit the work-string safety valve shallbe readily available. Proper connec-tions shall be readily available for in-serting a safety valve in the workstring.


§ 250.1625 Blowout preventer systemtesting, records, and drills.

(a) Prior to conducting high-pressuretests, all BOP systems shall be testedto a pressure of 200 to 300 psi.

(b) Ram-type BOP’s and the chokemanifold shall be pressure tested withwater to a rated working pressure or as


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30 CFR Ch. II (7–1–01 Edition)§ 250.1625

otherwise approved by the District Su-pervisor. Annular type BOP’s shall bepressure tested with water to 70 per-cent of rated working pressure or asotherwise approved by the District Su-pervisor.

(c) In conjunction with the weeklypressure test of BOP systems requiredin paragraph (d) of this section, thechoke manifold valves, upper and lowerkelly cocks, and drill-string safetyvalves shall be pressure tested to pipe-ram test pressures. Safety valves withproper casing connections shall be ac-tuated prior to running casing.

(d) BOP system shall be pressuretested as follows:

(1) When installed;(2) Before drilling out each string of

casing or before continuing operationsin cases where cement is not drilledout;

(3) At least once each week, but notexceeding 7 days between pressuretests, alternating between control sta-tions. If either control system is notfunctional, further drilling operationsshall be suspended until that systembecomes operable. A period of morethan 7 days between BOP tests is al-lowed when there is a stuck drill pipeor there are pressure control oper-ations, and remedial efforts are beingperformed, provided that the pressuretests are conducted as soon as possibleand before normal operations resume.The time, date, and reason for post-poning pressure testing shall be en-tered into the driller’s report. Pressuretesting shall be performed at intervalsto allow each drilling crew to operatethe equipment. The weekly pressuretest is not required for blind and blind-shear rams;

(4) Blind and blind-shear rams shallbe actuated at least once every 7 days.Closing pressure on the blind and blind-shear rams greater than necessary toindicate proper operation of the ramsis not required;

(5) Variable bore-pipe rams shall bepressure tested against all sizes of pipein use, excluding drill collars andbottomhole tools; and

(6) Following the disconnection or re-pair of any well-pressure containmentseal in the wellhead/BOP stack assem-bly, the pressure tests may be limitedto the affected component.

(e) All personnel engaged in well-completion operations shall participatein a weekly BOP drill to familiarizecrew members with appropriate safetymeasures.

(f) The lessee shall record pressureconditions during BOP tests on pres-sure charts, unless otherwise approvedby the District Supervisor. The test du-ration for each BOP component testedshall be sufficient to demonstrate thatthe component is effectively holdingpressure. The charts shall be certifiedas correct by the operator’s representa-tive at the facility.

(g) The time, date, and results of allpressure tests, actuations, inspections,and crew drills of the BOP system andsystem components shall be recordedin the operations log. The BOP testsshall be documented in accordancewith the following:

(1) The documentation shall indicatethe sequential order of BOP and auxil-iary equipment testing and the pres-sure and duration of each test. As analternate, the documentation in theoperations log may reference a BOPtest plan that contains the required in-formation and is retained on file at thefacility.

(2) The control station used duringthe test shall be identified in the oper-ations log.

(3) Any problems or irregularities ob-served during BOP and auxiliary equip-ment testing and any actions taken toremedy such problems or irregularitiesshall be noted in the operations log.

(4) Documentation required to be en-tered in the driller’s report may in-stead be referenced in the driller’s re-port. All records, including pressurecharts, driller’s report, and referenceddocuments, pertaining to BOP tests,actuations, and inspections shall beavailable for MMS review at the facil-ity for the duration of the drilling ac-tivity. Following completion of thedrilling activity, all drilling recordsshall be retained for a period of 2 yearsat the facility, at the lessee’s field of-fice nearest the OCS facility, or at an-other location conveniently availableto the District Supervisor.


411



(a) No tubing string shall be placedinto service or continue to be used un-less such tubing string has the nec-essary strength and pressure integrityand is otherwise suitable for its in-tended use.

(b) Wellhead, tree, and related equip-ment shall be designed, installed, test-ed, used, and maintained so as toachieve and maintain pressure control.

§ 250.1627 Production requirements.(a) The lessee shall conduct sulphur

production operations in compliancewith the approved Development andProduction Plan requirements of§§ 250.1627 through 250.1634 of this sub-part and requirements of this part, asappropriate.

(b) Production safety equipmentshall be designed, installed, used,maintained, and tested in a manner toassure the safety of operations and pro-tection of the human, marine, andcoastal environments.

[56 FR 32100, July 15, 1991. Redesignated andamended at 63 FR 29479, 29487, May 29, 1998; 63FR 34597, June 25, 1998]

§ 250.1628 Design, installation, and op-eration of production systems.

(a) General. All production facilitiesshall be designed, installed, and main-tained in a manner that provides for ef-ficiency and safety of operations andprotection of the environment.

(b) Approval of design and installationfeatures for sulphur production facilities.Prior to installation, the lessee shallsubmit a sulphur production systemapplication, in duplicate, to the Dis-trict Supervisor for approval. The ap-plication shall include information rel-ative to the proposed design and instal-lation features. Information con-cerning approved design and installa-tion features shall be maintained bythe lessee at the lessee’s offshore fieldoffice nearest the OCS facility or at an-other location conveniently availableto the District Supervisor. All approv-als are subject to field verification.The application shall include the fol-lowing:

(1) A schematic flow diagram show-ing size, capacity, design, workingpressure of separators, storage tanks,

compressor pumps, metering devices,and other sulphur-handling vessels;

(2) A schematic piping diagram show-ing the size and maximum allowableworking pressures as determined in ac-cordance with API RP 14E, Rec-ommended Practice for Design and In-stallation of Offshore Production Plat-form Piping Systems;

(3) Electrical system information in-cluding a plan of each platform deck,outlining all hazardous areas classifiedaccording to API RP 500, Rec-ommended Practice for Classificationof Locations for Electrical Installa-tions at Petroleum Facilities Classifiedas Class I, Division 1 and Division 2, orAPI RP 505, Recommended Practice forClassification of Locations for Elec-trical Installations at Petroleum Fa-cilities Classified as Class I, Zone 0,Zone 1, and Zone 2, and outlining areasin which potential ignition sources areto be installed;

(4) Certification that the design forthe mechanical and electrical systemsto be installed were approved by reg-istered professional engineers. Afterthese systems are installed, the lesseeshall submit a statement to the Dis-trict Supervisor certifying that thenew installations conform to the ap-proved designs of this subpart.

(c) Hydrocarbon handling vessels asso-ciated with fuel gas system. Hydrocarbonhandling vessels associated with thefuel gas system shall be protected witha basic and ancillary surface safetysystem designed, analyzed, installed,tested, and maintained in operatingcondition in accordance with the provi-sions of API Recommended Practicefor Analysis, Design, Installation andTesting of Basic Surface Safety Sys-tems for Offshore Production Plat-forms (API RP 14C). If processing com-ponents are to be utilized, other thanthose for which Safety Analysis Check-lists are included in API RP 14C, theanalysis technique and documentationspecified therein shall be utilized to de-termine the effects and requirementsof these components upon the safetysystem.

(d) Approval of safety-systems designand installation features for fuel gas sys-tem. Prior to installation, the lesseeshall submit a fuel gas safety system


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30 CFR Ch. II (7–1–01 Edition)§ 250.1629

application, in duplicate, to the Dis-trict Supervisor for approval. The ap-plication shall include information rel-ative to the proposed design and instal-lation features. Information con-cerning approved design and installa-tion features shall be maintained bythe lessee at the lessee’s offshore fieldoffice nearest the OCS facility or at an-other location conveniently availableto the District Supervisor. All approv-als are subject to field verification.The application shall include the fol-lowing:

(1) A schematic flow diagram show-ing size, capacity, design, workingpressure of separators, storage tanks,compressor pumps, metering devices,and other hydrocarbon-handling ves-sels;

(2) A schematic flow diagram (APIRP 14C, Figure E1) and the relatedSafety Analysis Function Evaluationchart (API RP 14C, subsection 4.3c);

(3) A schematic piping diagram show-ing the size and maximum allowableworking pressures as determined in ac-cordance with API RP 14E, Design andlnstallation of Offshore ProductionPlatform Piping Systems;

(4) Electrical system information in-cluding the following:

(i) A plan of each platform deck, out-lining all hazardous areas classified ac-cording to API RP 500, RecommendedPractice for Classification of Locationsfor Electrical Installations at Petro-leum Facilities Classified as Class I,Division 1 and Divisions 2, or API RP505, Recommended Practice for Classi-fication of Locations for Electrical In-stallations at Petroleum FacilitiesClassified as Class I, Zone 0, Zone 1,and Zone 2, and outlining areas inwhich potential ignition sources are tobe installed;

(ii) All significant hydrocarbonsources and a description of the type ofdecking, ceiling, walls (e.g., grating orsolid), and firewalls; and

(iii) Elementary electrical schematicof any platform safety shutdown sys-tem with a functional legend.

(5) Certification that the design forthe mechanical and electrical systemsto be installed was approved by reg-istered professional engineers. Afterthese systems are installed, the lesseeshall submit a statement to the Dis-

trict Supervisor certifying that thenew installations conform to the ap-proved designs of this subpart; and

(6) Design and schematics of the in-stallation and maintenance of all fire-and gas-detection systems includingthe following:

(i) Type, location, and number of de-tection heads;

(ii) Type and kind of alarm, includingemergency equipment to be activated;

(iii) Method used for detection;(iv) Method and frequency of calibra-

tion; and(v) A functional block diagram of the

detection system, including the elec-tric power supply.

[53 FR 10690, Apr. 1, 1988, as amended at 61FR 60026, Nov. 26, 1996. Redesignated at 63 FR29479, May 29, 1998, as amended at 65 FR 219,Jan. 4, 2000]

§ 250.1629 Additional production andfuel gas system requirements.

(a) General. Lessees shall complywith the following production safetysystem requirements (some of whichare in addition to those contained in§ 250.1628 of this part).

(b) Design, installation, and operationof additional production systems, includ-ing fuel gas handling safety systems. (1)Pressure and fired vessels shall be de-signed, fabricated, code stamped, andmaintained in accordance with applica-ble provisions of section I, IV, and VIIIof the American Society of MechanicalEngineers (ASME) Boiler and PressureVessel Code.

(i) Pressure safety relief valves shallbe designed, installed, and maintainedin accordance with applicable provi-sions of sections I, IV, and VIII of theANSI/ASME Boiler and Pressure VesselCode. The safety relief valves shallconform to the valve-sizing and pres-sure-relieving requirements specifiedin these documents; however, the safe-ty relief valves shall be set no higherthan the maximum-allowable workingpressure of the vessel. All safety reliefvalves and vents shall be piped in sucha way as to prevent fluid from strikingpersonnel or ignition sources.

(ii) The lessee shall use pressure re-corders to establish the operating pres-sure ranges of pressure vessels in orderto establish the pressure-sensor set-tings. Pressure-recording charts used


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to determine operating pressure rangesshall be maintained by the lessee for aperiod of 2 years at the lessee’s field of-fice nearest the OCS facility or at an-other location conveniently availableto the District Supervisor. The high-pressure sensor shall be set no higherthan 15 percent or 5 psi, whichever isgreater, above the highest operatingpressure of the vessel. This settingshall also be set sufficiently below (15percent or 5 psi, whichever is greater)the safety relief valve’s set pressure toassure that the high-pressure sensorsounds an alarm before the safety reliefvalve starts relieving. The low-pressuresensor shall sound an alarm no lowerthan 15 percent or 5 psi, whichever isgreater, below the lowest pressure inthe operating range.

(2) Engine exhaust. Engine exhaustsshall be equipped to comply with theinsulation and personnel protection re-quirements of API RP 14C, section4.2c(4). Exhaust piping from diesel en-gines shall be equipped with spark ar-resters.

(3) Firefighting systems. Firefightingsystems shall conform to subsection5.2, Fire Water Systems, of API RP14G, Recommended Practice for FirePrevention and Control on Open TypeOffshore Production Platforms, andshall be subject to the approval of theDistrict Supervisor. Additional re-quirements shall apply as follows:

(i) A firewater system consisting ofrigid pipe with firehose stations shallbe installed. The firewater system shallbe installed to provide needed protec-tion, especially in areas where fuelhandling equipment is located.

(ii) Fuel or power for firewater pumpdrivers shall be available for at least 30minutes of run time during platformshut-in time. If necessary, an alternatefuel or power supply shall be installedto provide for this pump-operatingtime unless an alternate firefightingsystem has been approved by the Dis-trict Supervisor;

(iii) A firefighting system usingchemicals may be used in lieu of awater system if the District Supervisordetermines that the use of a chemicalsystem provides equivalent fire-protec-tion control; and

(iv) A diagram of the firefighting sys-tem showing the location of all fire-

fighting equipment shall be posted in aprominent place on the facility orstructure.

(4) Fire- and gas-detection system. (i)Fire (flame, heat, or smoke) sensorsshall be installed in all enclosed classi-fied areas. Gas sensors shall be in-stalled in all inadequately ventilated,enclosed classified areas. Adequateventilation is defined as ventilationthat is sufficient to prevent accumula-tion of significant quantities of vapor-air mixture in concentrations over 25percent of the lower explosive limit.One approved method of providing ade-quate ventilation is a change of air vol-ume each 5 minutes or 1 cubic foot ofair-volume flow per minute per squarefoot of solid floor area, whichever isgreater. Enclosed areas (e.g., buildings,living quarters, or doghouses) are de-fined as those areas confined on morethan four of their six possible sides bywalls, floors, or ceilings more restric-tive to air flow than grating or fixedopen louvers and of sufficient size toallow entry of personnel. A classifiedarea is any area classified Class I,Group D, Division 1 or 2, following theguidelines of API RP 500, or any areaclassified Class I, Zone 0, Zone 1, orZone 2, following the guidelines of APIRP 505.

(ii) All detection systems shall be ca-pable of continuous monitoring. Fire-detection systems and portions of com-bustible gas-detection systems relatedto the higher gas concentration levelsshall be of the manual-reset type. Com-bustible gas-detection systems relatedto the lower gas-concentration levelmay be of the automatic-reset type.

(iii) A fuel-gas odorant or an auto-matic gas-detection and alarm systemis required in enclosed, continuouslymanned areas of the facility that areprovided with fuel gas. Living quartersand doghouses not containing a gassource and not located in a classifiedarea do not require a gas detection sys-tem.

(iv) The District Supervisor may re-quire the installation and maintenanceof a gas detector or alarm in any po-tentially hazardous area.

(v) Fire- and gas-detection systemsshall be an approved type, designed andinstalled in accordance with API RP


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30 CFR Ch. II (7–1–01 Edition)§ 250.1630

14C, API RP 14G, and API RP 14F, Rec-ommended Practice for Design and In-stallation of Electrical Systems forOffshore Production Platforms.

(c) General platform operations.Safetydevices shall not be bypassed orblocked out of service unless they aretemporarily out of service for startup,maintenance, or testing procedures.Only the minimum number of safetydevices shall be taken out of service.Personnel shall monitor the bypassedor blocked out functions until the safe-ty devices are placed back in service.Any safety device that is temporarilyout of service shall be flagged by theperson taking such device out of serv-ice.

[53 FR 10690, Apr. 1, 1988, as amended at 61FR 60026, Nov. 26, 1996. Redesignated at 63 FR29479, May 29, 1998, as amended at 64 FR72794, Dec. 28, 1999; 65 FR 219, Jan. 4, 2000]

§ 250.1630 Safety-system testing andrecords.

(a) Inspection and testing.Safety-sys-tem devices shall be successfully in-spected and tested by the lessee at theinterval specified below or more fre-quently if operating conditions war-rant. Testing shall be in accordancewith API RP 14C, Appendix D or forsafety-system devices other than thoselisted in API RP 14C, Appendix D theanalysis technique and documentationspecified therein shall be utilized forinspection and testing of these compo-nents, and the following:

(1) Safety relief valves on the naturalgas feed system for power plant oper-ations such as pressure safety valvesshall be inspected and tested for oper-ation at least once every 12 months.These valves shall be either bench test-ed or equipped to permit testing withan external pressure source.

(2) The following safety devices shallbe inspected and tested at least onceeach calendar month, but at no timeshall more than 6 weeks elapse betweentests:

(i) All pressure safety high or pres-sure safety low, and

(ii) All level safety high and levelsafety low controls.

(3) All pumps for firewater systemsshall be inspected and operated weekly.

(4) All fire- (flame, heat, or smoke)and gas-detection systems shall be in-

spected and tested for operation and re-calibrated every 3 months providedthat testing can be performed in a non-destructive manner.

(5) Prior to the commencement ofproduction, the lessee shall notify theDistrict Supervisor when the lessee isready to conduct a preproduction testand inspection of the safety system.The lessee shall also notify the DistrictSupervisor upon commencement ofproduction in order that a complete in-spection may be conducted.

(b) Records. The lessee shall maintainrecords for a period of 2 years for eachsafety device installed. These recordsshall be maintained by the lessee atthe lessee’s field office nearest the OCSfacility or another location conven-iently available to the District Super-visor. These records shall be availablefor MMS review. The records shallshow the present status and history ofeach safety device, including dates anddetails of installation, removal, inspec-tion, testing, repairing, adjustments,and reinstallation.

§ 250.1631 Safety device training.

Prior to engaging in production oper-ations on a lease and periodicallythereafter, personnel installing, in-specting, testing, and maintainingsafety devices shall be instructed inthe safety requirements of the oper-ations to be performed; possible haz-ards to be encountered; and generalsafety considerations to be taken toprotect personnel, equipment, and theenvironment. Date and time of safetymeetings shall be recorded and avail-able for MMS review.

§ 250.1632 Production rates.

Each sulphur deposit shall be pro-duced at rates that will provide eco-nomic development and depletion ofthe deposit in a manner that wouldmaximize the ultimate recovery of sul-phur without resulting in waste (e.g.,an undue reduction in the recovery ofoil and gas from an associated hydro-carbon accumulation).

§ 250.1633 Production measurement.

(a) General. Measurement equipmentand security procedures shall be de-signed, installed, used, maintained, and


415


tested so as to accurately and com-pletely measure the sulphur producedon a lease for purposes of royalty de-termination.

(b) Application and approval. The les-see shall not commence production ofsulphur until the Regional Supervisorhas approved the method of measure-ment. The request for approval of themethod of measurement shall containsufficient information to demonstrateto the satisfaction of the Regional Su-pervisor that the method of measure-ment meets the requirements of para-graph (a) of this section.

§ 250.1634 Site security.(a) All locations where sulphur is

produced, measured, or stored shall beoperated and maintained to ensureagainst the loss or theft of producedsulphur and to assure accurate andcomplete measurement of producedsulphur for royalty purposes.

(b) Evidence of mishandling of pro-duced sulphur from an offshore lease,or tampering or falsifying any meas-urement of production for an offshorelease, shall be reported to the RegionalSupervisor as soon as possible but nolater than the next business day afterdiscovery of the evidence of mis-handling.

PART 251—GEOLOGICAL ANDGEOPHYSICAL (G&G) EXPLO-RATIONS OF THE OUTER CONTI-NENTAL SHELF

Sec.251.1 Definitions.251.2 Purpose of this part.251.3 Authority and applicability of this

part.251.4 Types of G&G activities that require

permits or Notices.251.5 Applying for permits or filing Notices.251.6 Obligations and rights under a permit

or a Notice.251.7 Test drilling activities under a permit.251.8 Inspection and reporting requirements

for activities under a permit.251.9 Temporarily stopping, canceling, or

relinquishing activities approved under apermit.

251.10 Penalties and appeals.251.11 Submission, inspection, and selection

of geological data and information col-lected under a permit and processed bypermittees or third parties.

251.12 Submission, inspection, and selectionof geophysical data and information col-lected under a permit and processed bypermittees or third parties.

251.13 Reimbursement for the cost of repro-ducing data and information and certainprocessing costs.

251.14 Protecting and disclosing data andinformation submitted to MMS under apermit.

251.15 Authority for information collection.

AUTHORITY: 43 U.S.C. 1331 et seq.

SOURCE: 62 FR 67284, Dec. 24, 1997, unlessotherwise noted.

§ 251.1 Definitions.Terms used in this part have the fol-

lowing meaning:Act means the Outer Continental

Shelf Lands Act (OCSLA), as amended(43 U.S.C. 1331 et seq.).

Analyzed geological information meansdata collected under a permit or a leasethat have been analyzed. Analysis mayinclude, but is not limited to, identi-fication of lithologic and fossil con-tent, core analyses, laboratory anal-yses of physical and chemical prop-erties, well logs or charts, results fromformation fluid tests, and descriptionsof hydrocarbon occurrences or haz-ardous conditions.

Archaeological interest means capableof providing scientific or humanisticunderstanding of past human behavior,cultural adaptation, and related topicsthrough the application of scientific orscholarly techniques, such as con-trolled observation, contextual meas-urements, controlled collection, anal-ysis, interpretation, and explanation.

Archaeological resources means anymaterial remains of human life or ac-tivities that are at least 50 years of ageand of archaeological interest.

Coastal environment means the phys-ical, atmospheric, and biological com-ponents, conditions, and factors thatinteractively determine the produc-tivity, state, condition, and quality ofthe terrestrial ecosystem from theshoreline inward to the boundaries ofthe coastal zone.

Coastal Zone means the coastal wa-ters (including the lands therein andthereunder) and the adjacentshorelands (including the waters there-in and thereunder), strongly influencedby each other and in proximity to theshorelines of the several coastal States
