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Management ,of Wastes from theExploration, Development, andProduction of Crude Oil, Natural Gas,:and Geothermal Energy

Volume 3 of 3Appendices ,~- -

A-Summary of State Oil and Gas RegulationsB-Glossary of Terms for Volume 1 'C-Damage Case Summaries

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/"'REPRODUCED BY , \I U.S. DEPARTMENT OF COMMERCE

NATIONAL TECHNICALINFORMATION SERVICESPRINGFIELD, VA 22161

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REPORT TO CONGRESS

MANAGEMENT OF WASTES FROM THEEXPLORATION, DEVELOPMENT, AND PRODUCTION

OF-CRUDE OIL, NATURAL GAS, AND GEOTHERMAL ENERGY

VOLUME 3

APPENDICES

A 0 Summary of State Oil and Gas Regulations

B - Glossary of Terms for Volume 1

C - Damage Case Summaries

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

Office of Solid Waste and Emergency ResponseWashington, D.C. 20460

December 1987

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REPORT DOCUMENTATION II. REPORT NO. I~ PI agc:er4~'!~ 6l1SPAGE EPA/530-SW-88-003C4. Title .nd Subtitle S. R'POrt Oet.

Report to Congress: Management of Wastes from the Exploration, December 1987Development, and Production of Crude Oil, Natural Gas, and I-Geothermal Energy (Volume 3 of 3 - Appendices) .

7. AuthOr(s) I- p.rforminc O...nlz.tion Rept. No.

U.S. EPA/OSW9. Perform1na O...ni.z....... H..... nd Add,... 10. PrajoctlT..../Woril Unit No.

Versar, Inc. II.. ContrKtICl or GrantIG) No.Springfield, Virginia

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12. SPOn,orina O...nlzallon H.mnd Add.... lI. Type 01 R.POrt & Period CoweredU.S. Environmental Protection Agency

Report to CongressOffice of Solid Wa-s-te401 M Street, S.W. 14.Washington, D.C. 20460 .

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This is volume 3 of a four-volume set.

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Section 3001(b)(2)(A) of the 1980 Amendments to the Resource Conservation andRecovery Act (RCRA) temporarily exempted several types of solid waste from regulationunder the Federal hazardous waste control program. These exempted wastes included"drilling fluids, produced waters, and other wastes associated with the exploration,development, or production of crude oil or natural gas or geothermal energy."Section B002(m) of the RCRA Amendments requires EPA to study these wastes and submita final report to Congress. This report responds to those requirements.

This is volume 3 of 3 of this report to Congress. This volume contains theAppendices which include a summary of: (1) State and oil and gas regulatory programs;and (2) the damage cases compiled for the oil and gas industry. A glossary of oiland gas industry terms is also included in this volume.

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17. DocurnMlt: Anal"'" '0 DncrlptOrl

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TABLE OF CONTENTS

APPENDIX A - SUMMARY OF STATE OIL AND GAS REGULATIONS ..... A-1Alabama ...........A-1

. Alaska ".............. 0 0 0A-7Arizona"""" .".""""""""""""""""""""""""""""";0"""""""""""""",, .A-21Arkansas .......................A-25Cal ifornia .........................A-33Colorado . ,. ................. A-47Florida .......... A-57Illinois"""" II""" II ill II."." 11 0 " II'. It, ,I.A-61Indi ana ........................A-67Kansas ."..............A-71Kentucky ..............A-79Loui si ana .........................A-83Maryl and ..........................A-95Michigan A-99Mississippi ................... A-I07Mi ssouri ....................A-115Montana ....................................A-119Nebraska .............. ".... A-125Nevada .............. A-131New Mexi co .......................A-135New york ................... A-145North Dakota ......... A-153Ohio ................. A-159Oklahoma ................... ; . A-169Oregon ............. A-181Rennsylvania ........ A-187South Dakota .~ .......... A-193Tennessee. 11 ;0. ,' . 11 ".;0 D'" II 0.0. 11.11' II lI" oA~197Texas CI " II II A-20IUtah -...... A-215Virginia 0'" 0" "." II 11;0 " ;0 A-221West Virginia ..................A-225Wyomi ng ................ A- 231

APPENDIX B - GLOSSARY OF TERMS FOR VOLUME 1 ................. B-1

APPENDIX C - DAMAGE CASE SUMMARIES ....... C-1OH 49 ....................--; ...... C-1OH 45 .... "............. C-3OH 07. ........................C-4OH 12 ........-...........,...... C- 5OH 38 ...............................C-7WV 18 .....................................C-8

II \

TABLE OF CONTENTS (Continued)

APPENDIX C - ContinuedWV 20 ...............C-1 0.PA 02

TABLE OF CONTENTS (Continued)

APPENDIX C - ContinuedAK 07 " ' " e-84AK 08 " 1"1 C-86AK 12 ...................................................C-87AK 10 -: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .C-88AK 03 , C-90AK 01 ......................C-92KS 14 ............................. 11.11 0 0 . C-94TX 11 ........................C-96TX 15 . 0 0 III 0 II II II 0 01 C-97LA 65 ........ -. C-99NM 03 ...... -... ~ ....... C-101NM 04 ..................... C-103AK 09 ............................' . C-104

v

APPENDIX A

SUMMARY OF STATE OIL AND GAS REGULATIONS

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ALABAMA

INTRODUCTION

Alaba~a produced 8,486,000 barrels of oil, 11,392,000 barrels ofcondensate, and 137 x 109 cubic feet of gas in 1984. Production wasfrom 760 oil wells, 509 conventional gas wells, and 184 coal bed methanewells. Thirteen percent of conventional oil and gas wells and 52 percentof coalbed methane wells are strippers.

Alabama began limited regulation of oil and gas activities in 1946.Regulations for disposal of drilling wastes were adopt~d in 1973.Regulations and/or administrative codes have been revised continuallyover the past 40 years.

REGULATORY AGENCIES

Four agencies regulate oil and gas activity in Alabama. They are:

Alabama State Oil and Gas Board; Alabama Department of Environmental Management; U.S. Bureau of Land Management; and U.S. Army Corps of Engineers.

The Alabama State Oil and Gas Board is "charged with preventing thewaste of Alabama's oil and gas resources and protecting the correlativerights of owners." In carrying nut its mandate, the Board regulates alloil and gas operations, from the issuance of drilling permits through theproduction phase. The Oil and Gas Board has the authority to issuepermits for Underground Injection Controi (UIC) Class II wells. Thevarious permitting requirements and conditions of the Oil and Gas Boardare detailed in the Board's Administrative Code.

A-I

..

The Board hasthese pits.

, -leveling,

t _:

The Alabama Department of Environmental Management (ADEM) has theauthority to issue permits for all UIC wells other than Class II. TheDepartment of Environmental Management also has National PollutantDischarge Elimination System (NPDES) authority. The Oil and Gas Boardand the Department of Environmental Management operate under a 1979Memorandum of Agreement that requires the Board to forward informationregarding actual or proposed discharges to the Department ofEnvironmental Management.

The U. S. Bureau of Land Management's authority and regulations forFederally-held mineral rights are discussed separately in the section onFederal agencies. (See Volume 1, Chapter VII.) The U.S. Forest Serviceretains surface rights (and usually coordinates stipulations with theBureau of Land Management) in Federal forests and grasslands.

STATE RULES AND REGULATIONS

Drilling

. .Drilling pits are permitted by the Oil and Gas Board.

certain construction requirements to ensure the integrity ofPits are closed by dewatering (see below), then backfilling,and compacting.

No pits are permitted in Alabama's coastal wetlands. The Departmentof Environmental Management prohibits the use of pits in wetlands inorder to ensure the prDtection of surface or ground-water resourc~s.Many of the wetland areas in "Alabama fall within the jurisdiction of theArabama Coastal Area Management Program, which is enforced by ADEM. TheCertificate of Consistency, which must be issued by ADEM befor~ a permitcan be granted by the Board, requires use of portable aboveground tanksfor any well drilled in the coastal area.

A-2

Drilling muds and pit fluids may be disposed of in one of threeways. They may be injected into a formation below underground sources ofdrinking water. They may be transported to a drilling mud treatment(recycling) facility. In non-wetlands, the fluids may be applied to theland surface frr into an approved landfill if:

The chloride concentration is less than 500 mg/L; The Oil and Gas Board is properly notified; The landowner provides written approval; It is a one-time-only application; or There will be no discharge to a surface body of water.

These activities are permitted by the Oil and Gas Board prior toallowing disposal of fluids.

Production Waters

Class II injection wells' are used for (l) the disposal of watersproduced in association with oil and/or natural gas, (2) the disposal ofnonhazardous wastewaters that may be generated during the operation of agas plant, (3) the enhanced recovery of oil or natural gas, or (4) thestorage of liquid hydrocarbons at standard temperature:and~pressure.Currently, all of Alabama's 250 Class II injection wells are used fordisposal purposes or for the enhancement of oil or natural gas production.

According to Rule 400-1-5-.04, "Immediately following the initiationof production in any field or pool, all salt water shall bedisposed ofinto an approved underground formation or otherwise disposed of asapproved, by the Supervisor where such sult water cannot damage or polluteunderg~ound sources of drinking water, oil,gas or other minerals." The

A-3

permitting of Class II injection wells in Alabama is a two-step process.Step 1, obtaining approval to drill or convert a well for injectionpurposes, includes a review of all well construction within a one-quartermile radius of the proposed injection well, along with the submission ofdata concerning the construction of the proposed injection well, analysesand estimated Yo1umes of fluids to be injected, antitipatedinjectionpressures, known or calculated fracture pressure of the proposedinjection interval, and the lowermost depth of fresh water. Allinjections will be made through tubing anchored by a packer unlessotherwise approved by the Oil and Gas Supervisor. In addition, theoperator must provide proof that the injection casing is adequatelycemented in order to prevent vertical fluid migration, and must test the,injection casing at a pressure equal to two-tenths of the depth of themid-point of the injection interval, but not to exceed 1,500 psi.

Following completion of the Board's Step 1 requirements, theapplicant may ~eceive approval to start injection. Once injectionbegins, the operator must submit monthly reports on injection volumes,injection pressures, and the casing-tubing annulus pressures. Theinjection pressure and the casing-tubing annulus pressure must berecorded daily or computed on an average daily basis fro~ w~ekllcmeasurements. Also, chemical analyses of injected flui~~:m.u%t~b~

.. submitted on an annual basis, and a pressure test should-be-~~~formed atleast once every 5 years. ."

Produced waters from coal bed methane wells are an exception to theinjection requirement. EPA has advised Alabama that coal bed methaneproduction is not covered under the Federal onshore oil and gasregulations. Produced waters frorrcoalbed methane wells may be allowed toaccumulate in pits and settle. They would then be discharged directlyinto live streams. The Department of Environmental Management stipulatesthat operators must obtain permits for such discharges and requires thats~ch discharges meet a 600 mgjL in-stream limit.

A-4

Plugging/Abandonment

Plugging is required"after 6 months, but wells may be approved fortemporary abandonment if future utility can be shown. Thereafter, wellstatus must be reported every 6 months.

When plugging, cement plugs of not less than 100 feet should beplaced above any producing formation, from SO feet below to SO feet abovethe base of freshwater strata, and from SO feet below .to SO feet abovethe base of the surface casing. A 25-foot plug should be near the surfaceand a steel plate should be placed over the casing stub. Intervalsbetween the plugs must be filled with mud-laden fluid.

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A- 5

References

State Oil and Gas Board of Alabama. Submittal to EPA regarding OnshoreOil ~nd Gas Subcategory, March 1985.

___--=_. Administrative Code. General Order Prescribing Rules andRegulations Governing the Conservation of Oil and Gas in Alabama andOil and Gas Laws of Alabama with Oil and Gas Board Forms, Oil and GasReport 1, 1983.

USEPA. 1985. U.S. Environmental Protection Agency. Alabama MeetingReport. Proceedings of the Onshore Oil and Gas Workshop (March 26-27in Atlanta, Ga.). Washington, D.C.: U.S. Environmental ProtectionAgency.

Personal Communication:

Treena Pizner, Alabama Department of Environmental Management"(205) 271-7850.

A-6

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ALASKA

INTRODUCTION

Alaska produced 681,309,821 barrels of oil and 316 x 109 cubic feetof gas in 1986. During 1986, 608,225,599 barrels of water and1,066 x 109 cubic feet of gas were injected into producing formationsfor enhanced oil recovery.

Alaska ranked second in U.S. oil production, but 23rd in the numberof production wells (1,191 wells) in 1986. It ranked 8th in U.S. gasproduction and 24th in the number of producing gas wells (104 wells).

In 1986, oil and gas in Alaska were produced from two developmentregions, the South Central region (including Cook Inlet and the KenaiPeninsula) and the North Slope .region. The State contains otherprospective regions, but to date no discoveries have geen made there.Approximately 663,738,428 barrels of oil and "123 x 109 cubic feet ofgas were produced from the North Slope in 1986 from two fieldc (Kuparukand Prudhoe). The Endicott Field (Duck Island) will begin production inearl~ 1988. Production at the Milue Point unit is currently suspendedfor economic reasons. -

The Kenai Peninsula produced mostly gas with little associatedproduced water. In 1986, fields in the South Central region produced17,571,393 barrels of oil and 193 x 109 cubic feet of gas.

A-7

REGULATORY AGENCIES

The eight agencies that regulate oil and gas ~ctivities inc Alaska are:

Alaska Oil and Gas Conservation Commission; Alaska Department of Environmental Conservation; U.S. Bureau of Land Management; Alaska Department of Natural Resources; Alaska Department of Fish and Game; U.S. Army Corps of Engineers; U.S. EPA Region X; and U.S. Fish and Wildlife Service.

The Alaska Oil and Gas Conservation Commission (AOGCC) regulates theproduction and conservation of oil and gas in Alaska and is responsiblefor issuing permits for prilling. The Commission checks well casings toprevent contamination of water and has primacy for the Class II injec~ionwells. Under Title 31 of the Alaska Statutes, the Commission has the

\

status of an independent quasi-judicial agency. Its th~ee commissioners,appointed by the Governor, must include an expert in petroleumengineering and an expert in petroleum geology.

The Alaska Department of Environmental Conservation (DEC~ i~ the-cprimary pollution control agency within the State government. The

Department regulates and permits solid waste disposal, wastewaterdischarges, and air contaminant emissions. It issues State dischargepermits' for:- oil and gas drilling and production operations.- TheDepartment also regulates hazardous wastes, oil spill control, and the,subsurface disposal of nonhazardous oil and gas wastes (which are notregulated as Class II wastes). Since Alaska does not have responsibility

A-a

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for the NPDES program, DEC coordinates with EPA Region X, whichadministers the NPDES program in Alaska.

The U.S. Bureau of Land Management is responsible for all oil and gasactivity on Federal and Indian lan9s" (under 43 CFR 3160). There are 370million acres of land in Alaska, of which more than half are underFederal ownership. There are 150 producing oil and gas wells on Federalleases. Regulatory processes for oil and gas operations are covered inthe Onshore Oil and Gas Order No.1. More information on BLM regulationscan be found in the section on Federal programs. (See Volume 1, ChapterVII. )

The Alaska Department of Natural Resources issues surface andsubsurface oil and gas leases on State land. Leasing stipulationsaddress environmental concerns, such as requiring that reserve pits berendered impermeable, at lease award. The Department also approves plansof operation for all oil and gas activity on State lands. The approvalletter contains site-specific stipulations developed through inter-agencyreview. In addition, the Department conducts field inspections ofoperations and abandonments.

Under Section 404 of the Clean Water Act, the U.S. Army Corps ofEngineers is responsible for issuing permits for dredge and-fillactivities on wetlands defined as part of the waters of th~ United

~-

States, and-D:S. EPA has review responsibility for such permits. Severalother State and Federal agencies also have comment and/or c6ncurrenceresponsibilities on the Federal permits. Since much of Alaska's drilling

and production activity, including that on the North Slope, takes placeon wetlands, all pads, roads, and facilities have 404 permits. The Corpsof Engineers requires all reserve pits to be rendered impermeable .

The U.S. Fish and Wildlife Service, in addition to having commentresponsibility on 404 permits, has been conducting research related to

A-9

the permitted discharge of drilling fluids to the tundra wetlands. Theresearch project currently in progress is designed to determine thedeleterious effect of the discharge on wildlife in the wetlands,especially to waterfowl.


New revisions to-the regulations for the handling of drilling andproduction wastes (18 AAC 60) in Alaska were adopted by the Department ofEnvironmental Conservation in June 1987. These amendments impose morestringent requirements on the management of reserve pits and drillingwastas.

Reserve Pits

The management and disposal of drilling wastes primarily involve theproper operation and closure of the reserve pit used during drillingoperations. The reserve pit often provides the permanent disposal sitefor solids or solidified wastes from the drilling operation. Although inexploratory -drilling, reserve pits may often be used and closed in asingle season, on the North Slope many are in continuous use because ofthe directional drilling of multiple wells from a single pad. There are,however, a variety of ways in which drilling wastes_are ultimatelydisposed of, such as subsurface injection. (In 18 AAC 60.910, "drillingwast-e-s~are defi ned as i ncl ud ing "dri 11 i ng muds, cutt i ngs, hydrocarbons,brine, acid, sand, and emulsions of mixtures of fluids produced from andunique to the operation or maintenance of a well,")

State statutes require permits for solid waste disposal facilities;however, prior to 1982, few solid waste permits were issued for reservepits. As early as 1982, it became policy to require permits for all

A-I0

currently active and new pits in the Cook Inlet area. The same policywas applied on the North Slope beginning in 1985.

Under 20 AAC 25.047, administered by the AOGCC, reserve pits arerequired "for the reception and- confinement of drilling fluids andcuttings, to facilitate the safety of the drilling operation, and't6prevent contamination of ground water and damage to the surfaceenvironment." The general construction requirement is that the pits mustbe rendered "impervious."

The new DEC regulations impose specific construction and performancerequirements for reserve pits. The particular requirements depend onfactors such as the proximity of surface water or ground water that isused for drinking water, the proximity of an existing or developingpopulation, and whether the pit is being built in an area of continuouspermafrost. For example, a reserve pit being constructed in anonperm~frost region within 100 feet of a surface water body used fordrinking water would require a double liner, leachate collection (ifthere is no flu~d management plan), site inspection, and monitoring. Areserve pit in a permafrost region not adjacent to water supplies orpopulation would require a containment structure (possibly lined)designed to prevent the escape of wastes from .the reserve pit, siteinspection, a fluid management plan, and monitoring.

Under 20 AAC 25.047, administered by~tft~OGCC, upon termination ofoperations related to a particular reserve pit, "the operator shallproceed with diligence to dispose of and solidify in place all pumpablefluids, and shall leave the reserve pit in a condition that does notconstitute a hazard to ground water." Under 18 AAC 60 and 18 AAC 72,administered by the DEC, solid WJste permits are required for closure andwastewater permits are needed for all discharges. Pits must be closed

A-II

_ .~.-._0- .~_.~~. __-~-._ ~ _. -_. ,, __ ~ _.,:'- "_._.'

within 12 months after the final drilling wastes have been disposed of inthe pit.

Disposal from Reserve Pits

Reserve pit fluids on the North Slope may be disposed of throughinjection in dedicated wells. In the Kenai area there have been severalpermits for centralized disposal of oil field wastes. One of thesepermitted disposal facilities was operated by an independentconcessionaire on Kenai Borough-owned land, but DEC canceled the permitbecause contaminants were found in monitoring wells.

DEC has issued general permits for discharges to the tundra, forannular injection of reserve pit fluids, and for dedicated injectionwells that are not Class II wells, and issues occasional specific permitsfor road application. Injection into dedicated Class II wells is~ermitted by the Oil and Gas Conservation Commission. Annular injectionis allowed under the permit-to-drill issued by AOGCC.

" .Surface Discharge to Tundra

-- DEC issued a seasonal general permit on May 12, 1986 (~.xpire9-:, _- ~ S"eptember 30, 1986) for discharges onto the tundra from res-erve pits .-

containing "produced waters, drilling fluids and cuttings, boilerbl owdown , rig washing fluids, worKb~fluids, completion fluids, excessfluids from blowouts and drill pad runoff." Only those pits that hadreceived no discharges or placements of any materials into the pit sinceAugust 1, 1985, were eligible (that is, pits that had gone through aI-year freeze-thaw cycle to precipitate contaminants). Further, pits musthave no visible sheen on the surface. Operators must notify DEC 2 weeksprior to any discharge, and include information on volumes and analysesfor salinity, settleable solids, arsenic, and chromium. Written ~pproval

A-12

..

must be received from DEC prior to the discharge. The permit appliesonly to discharges of the clarified supernatant from the pits. Themaximum drawdown is 18 inches from pit bottom at point of withdrawal toprevent solids carry-over. Other management practices, such asinjection, must be used for further drawdown. Effluents must be monitoredduring discharge. The effluent limitations for 1986 were:

CODpH

SalinitySettleable solidsOil and greaseAromatic hydrocarbonsArsenicBariumCadmiumChromiumLeadMercury

200 mg/L6.0 . 8.5(orwithin 0.5 ofreceiving water)3 parts/thousands1 mg/L15 mg/L10 ug/L0.05 mg/L1 mg/L0.01 mg/L0.05 mg/L0.05 mg/L0.002 mg/L.

These limitations were to be reevaluated prior"toissuance:of the1987 general permit. Limitations are also being evaluated-for copper,zinc, aluminum, and boron. The process of reevaluation after 1985 led tothe elimination of an effluent limitation for manganese in the 1986general permit. DEC figures in the information sheet with the 1986general permit indicate that approximately 36 million gallons of liquidwere discharged from 43 reserve pits in 1985, 35 of which exceededlimitations. Sixteen of these pits, however, exceeded only thelimitati9n for manganese, which is found at naturally high levels inwaters on the slope.

A-13

Surface Discharge to Roads

Permits for road applications of reserve pit fluids, used for dustcontrol during the summer, are issued to individual applicants. Twopermits issued to facilities of one company for 1986 were valid fromMay 15th to December 31st, but specified that discharges must be betweenJune 1st and August 31st unless DEC determined sufficient thaw existed toprevent puddling or runoff.

Unlike discharges to the tundra, road application permits do notrequire that the reserve pit fluids go through a I-year freeze-thaw cyclebefore disposal. Application is specifically designated for particularroads and pads. Spraying is prohibited when the surfaces are already wet.Spraying is to be made no closer than 3 feet from the edge of theshoulder of any pad or road to prevent spraying onto adjacent areas.Compliance with effluent limitations is to be determined at the edge ofthe road or pad. The required limitations 'are the same as those fordischarge to the tundra, except for the range for pH (6 to 9). Samplingand monitoring reports are required.

Annular Disposal

Reserve pit wastes are frequently injected down the annulus either ofthe~ell being drilled or of another well on the pad. A general permitfor. annular disposal for the North Slope was issued by DEC for the periodof August 6, 1985, to April 30, 1981. The permit applies to the dischargeof "fluids produced from the drilling, servicing or testing of oil andgas exploration, development, service and stratigraphic test wells,including but not limited to drilling fluids, rig washwater, completionfluids, formation fluids, reserve pit meltwaters and" domesticwastewaters .... "

A-14

Discharge must occur below the permafrost zone; the minimum depthmust be 1,000 feet. No discharge must be into any zone containing totaldissolved solids (TDS) of less than 3,000 ppm. Operators must notify DECat least 2 weeks before beginning injection, and must include informationon volumes and types of material being injected, the zone and depth ofthe injection, and the method to be used to seal the injection zone atthe completion of disposal. Written approval must be received from DEC.A report must be sub~itted after closure of the well, stating volumes andtypes of liqUids injected, well location, well designations, date andtime of injections, and depth of injection zones.

This option may require that the operator perform annual maintenanceon the well to preserve the permafrost.

Injection Wells

The Oil and Gas Conservation Commission has responsibility forClass II UIC wells. The Commission permits the disposal of both oil fieldwaste fluids and produced waters into wells dedicated to ~isposal of oilfield wastes (20 AAC 25.252), and approves injection into wells forenhanced recovery (20 AAC, Article 5). While the numbers continually

~ change, current figures provided in February and March- 1987 were 17di'sposal wells (14 North Slope, 3 Kenai) and 387 enhanced recovery wells.

Since more water is injected for enhanced recovery in Alaska than isproduced with oil and gas production, produced waters are injected intodisposal wells only when they are geographically distant from anyenhanced recovery operation. Additional water for enhanced recovery isdrawn from both Cook Inlet and the Arctic Ocean.

A-IS

Injection for enhanced recovery may be carried out under areainjection orders (20 AAC 25.460). The Commission may issue orderspermitting injection on an area basis, rather than fo~ eac~ individualwell, if the wells are essentially similar; are within the same field,site, or similar area; ar~ operated by a single operator; and are used toinject other than hazardous waste.

Reserve pit fluids may be injected into dedicated disposal wells or,in some instances, returned down the annulus to formation.

Injection wells must be cased with safe and appropriate casing, tubedto 'prevent leakage, and cemented to protect oil, gas, and freshwaterstrata. At application, information must be provided on all wells withinone-quarter mile of the injection well that penetrate the injection lone.Adequate evidence must be provided that a proposed injection well willnot cause or increase fractures in overlying strata, which could allowinjected or fotmation liquids to enter freshwater strata. (Freshwateraquifers may be exempted from the restrictions affecting them if theycurrently do not and cannot in the future serve as sources of drinkingwater; are between 3,000 and 10,000 mg/L TOS but cannot be reasonablyexpected to supply a public water system; or if they are too contaminatedfor economic or technologically practical recovery.)

.c Injection wells must be equipped with tubing and packer- 9r other~ equipment that would isolate pressure to the injection interval. Wells

must undergo pressure tests for mechanical integrity before operation.The test must run for 30 minutes at 1,500 psi or 0.25 psi/ft times thevertical depth of the casing shoe, whichever is greater (but must notexceed 70 percent of the minimum yield strength of the casing), with amaximum pressure decline of 10 percent. Thereafter, mechanical integritymust be demonstrated by the operator by monitoring the pressure in thecasing-tubing annulus during actual injection. The monitored pressuremust.be reported month1y~

A-I6

At present, two applications are pending with the EPA for permits for

~

dedicated, .Class I, disposal wells on the North Slope, one for thePrudhoe Bay Unit and one for the Endicott Unit. These wel~s will be forrestricted oil and gas development wastes.


All wells that have been permitted on a property must be abandonedwithin 1 year following cessation of the operator's oil and gas activitywithin the field where the wells are lqcated. Any well that is notcompleted after drilling must be abandoned or suspended before thedrilling equipment is removed.

The Commission may approve suspension of a well if it has futureproductive or service use, and if there is d justifiable reason for thesuspension (e.g., unavailability of production or marketing facilities).The operator of a suspended well must set d bridge plug 200 to 300 feetbelow the casing head and cap with 100 linear feet of cement. Additionalplugging requirements for a suspended well would be determined by theCommission on a site-specific basis;

Abandoned wells must be plugged to prevent movement.of fluid -into orbetween freshwater and hydrocarbon sources. Uncased portions of a wellmust be cased to keep fluids in original strata; cementcplugs must beplaced from 50 feet below to 100 feet above hydrocarbon strata, and from150 feet below to 50 feet above the base of the lowest freshwater stratum .

. Uncased and cased portions of the wellbore must be segregated;various cementing method/plug placement combinations may be used (e.g.,plug from 100 feet below to 100 feet above the casing shoe, using thedisplacement method).

A-I?

Cased portions of the wellbore must be plugged with cement to confinehydrocarbons and fresh water to the original strata. Perforated intervalsmust be plugged by one of several methods (e.g., by extending cementplugs from 100 feet below to 50 feet above the base and from 50 feet

-below to 100 feet above the top of each interval, or by placing amechanical "bridge with a 75-foot cement cap 50 feet over the interval),as must casing stubs within the outer casing (plug from 100 feet above to100 feet below the stub, bridge plug 25 feet over the stub with a 75-footcap, or down squeeze 150 feet of cement through the retainer with anadditional 50-foot plug).

Surface plugs must seal annular openings in communication with theopen hole, and a ISO-foot .cement plug must extend to within 5 feet ofgrade elevation.

Cements used for plugging within permafrost zones must be designed toset before freezing and have low heat of hydration. Muds equaling orexceeding the density of mud used to drill each interval should fill the

r

intervals betw~en plugs.

Final abandonment of the wells and drill sites must also be approvedby the Alaska Department of Natural Resources if the site ;s on ~tate1and. - .

A-I8

..

.. References

Alaska Department of Environmental Conservation. General WastewaterDisposal Permits for surface discharges from reserve pits(#8640-D8001; May 12, 1986) and annular injection (#8540-D8001;August 6, 1985); and individual permits for road application(#8636-0B003 and 08004).

Regulations, Alaska Administrative Code, Title 18,Chapter 60 (Solid Waste Management), Septemoer 1987; Chapter 72(Wastewater Oispqsal); January 1983.

Alaska Oil and Gas Conservation Commission. 1986. Regulations, AlaskaAdministrative Code, Title 20, April 2, 1986.

Alaska Statutes, Title 31, Chapter OS, Alaska Oil and Gas ConservationAct.

Fristoe, Br"adley R. 1985. Letter communication to EPA. State of AlaskaDepartment of Environmental Conservation.

Interstate Oil and Gas Commission. 1986. Summary of State statutes andregulations for oil and gas productioll, ,June 1986:

Interstate Oil Compact Commission. 1985. The Oil and Gas CompactBulletin, Vol . XLIV, No.2, December 1985.'

Title 46, Water, Air, Energy, and Environmental Conservation:Chapters 3 (Environmental Conservation); 4 (Oil Pollution Control);and 8-9 (Oil and Hazardous Substance Release).

-- USEPA. 1985. U.S. Environmental Protection Agency. Alaska Meeting----:-----:--:-----:.-:.--R:ep.ort. Proceedings of the Onshore Oil and Gas Sta'te/Federal Western

Workshop (March 26-27 in Atlanta, Ga.). Washington, D.C.: U.S.Environmental Protection Agency. -- - -----

Personal Communications:

William Barnwell, Alaska Oil and Gas Conservation Commission(907) 279-1433.

Michael Frank, Alaska Attorney General's Office, Natural ResourcesDivision (907) 276-3550.

Douglas Lowery, Alaska Department of Environmental Conservation(907) 452-1714.

A-19

Doug Redburn, Chief of Water Quality Management Section, Juneau(907) 465-2666.

Dan Wilkerson, Alaska Department of Environmental Conservation(907) 274-2533.

A-20

..

ARIZONA

INTRODUCTION

Arizona produced 214,000 barrels of oil and 225 MMCF of gas in 1984.Production was from 26 oil wells and 5 gas wells. Approximately655 barrels of produced waters are produced in the State per day.

REGULATORY AGENCIES

The five agencies that regulate the oil and gas industry in Arizonaare:

Arizona Oil and Gas Conservation Commission; U.S. Bureau of Land Management; U.S. Bureau of Indian Affairs; Arizona Department of Health and Safety; and EPA, Region IX.

The Bureau of Land Management (BLM) has the authority to issue oiland gas drilling permits for Federal minerals. Where Indian mineralrights prevail, oil and gas activity may be governed by both the BLM andthe Bureau of Indian Affairs.

The Arizona Oil and Gas Conservation Commission reviews all oil andgas drilling applications and is primarily responsible for approving andenforcing oil and gas activities. The Oil and Gas Commission'sregulations pertain to the construction, location, and operation ofonsite drilling and production activities.

A-21

. "., : .'"

Arizona does not have NPDES or UIC program primacy. The Departmentof Health and Safety coordinates with EPA's Region IX for any surfacewater discharge or underground injection permits. Region IX administersthe UIe program; there are no discharges from oil and gas facilities.


Drilling

Reserve pits receive drilling fluids and muds, drill cuttings,. andany waters produced during drilling. The pits are allowed to evaporatebefcre closure, and then are filled.

Production

All waters produced during the production phase are reinjected, foreither enhanced recovery or disposal. To drill an injection well, permitapproval is required from both EPA Region IX and the Commission. Thecasing and cementing requirements in the Arizona State regulations aregeneral, requiring "safe or adequate casing or tubing in order to preventleakage," cemented and set to prevent damage to gas, oil, or freshwaterstrata. Surface casing is required to be pressure tested at 600 pst .for30 minutes, with a maximum allowable drop of 10 percent in -p-ressure.


The regulations do not specify a time limit for plugging a well afterproduction ceases. Decisions are made on a case-by-case basis. In thecase of a dry hole, plugging must take place within 60 days after th~cessation of drilling, unless permission for temporary abandonment isgranted by the Commission.

A-22

- . -,-",-' -.',.. '. -.-

When a well is plugged, a 50-foot cement plug must be placedimmediately above each producing formation, and a continuous cement plugmust be placed through, and to 50 feet above and below all freshwaterstrata. A 20-foot cement plug must be placed at or near the surface ofthe well. Intervals between plugs must be filled with heavy mud. Anu~cased hole must be plugged with heavy mud up to the base of the surfacestring, at which point a 50-foot plug must be placed in and out of thebottom of the surface pipe .

A23

References

Brady,Ray. Deputy State Director, Division of Mineral Resources. Letterto U.S. Environmental Protection Agency, September 4, 1985.

Oil and Gas Conservation Commission. 1982. Arizona Administrative CodeChapter 7, Article 1. Oil~ Gas, and Helium.


Lyndon Hammon, NPDES Permits Section Manager, Arizona Department ofHealth and Safety. September 29, "1986 (602) 257-2262.

Nate Lau, Director of the UIC Division, EPA Region IX. September 28,1986 (415) 974-0893.

A-24

..

ARKANSA'S

INTRODUCTION

Arkansas produced 19,715,691 barrels of oil and 194,483 MM cubic feetof gas in 1985. Production is from 9,490 oil wells and 2,492 gas wells.The State is divided into two geographical districts. The Arcoma Basin,located in the northwest corner of the State, produces 99 percent naturalgas on a volume basis. The Mississippi Embayment in southeasternArkansas produces approximately 90 percent oil and 10 percent gas.

REGULATORY AGENCIES

The two agencies that reg~late oil and gas activity in Arkansas are:

Arkansas Oil and Gas Commission; and Arkansas Department of Pollution Control and Ecology.

The Arkansas Oil and Gas Commission regulates industry practicesregarding drilling and production activities of oil and gas wells underthe authority of Act 105 of 1939 (the "Oil and Gas Act"), Act 937 of1979, and Act 523 of 1981. Act 105 created the Oil and Gas Commissionand authorized it to prevent the waste of oil and gas resources and thepollution of freshwater supplies by oil, gas, or salt water. Act 937authorized the Commission to prevent waste in produced water production.Act 523 amended the "Oil and Gas Act~ to authorize the Oil and GasCommission to "acquire primary enforcement responsibility eithersingularly or jointly with the Department of Pollution Control andEcology for the control of underground injection ijnder the applicableprovisions of the Safe D~inking Water Act." Drilling and productionpractices are regulated underth~"General Rules and Regulations" of theCommission (Order No. 2-39). The General Rules and Regulations do notaddress all aspects of industry practices, and refer the reader to

A-25

"special rule.s pertaining to individu'al oil, gas, or salt water fieldsand pools." Special rules of any nonemergency nature require a publichearing, and are provided for in Rul.es A-2 and B-38 of the General Rulesand Regulat ions.

The Arkansas Department of Pollution Control and Ecology (ADPCE)regulates pollution generally, or polluti~n specifically related to oiland gas drilling and production wastes, under authority of Act 472 of1949 (the "Arkansas Water.and Air Pollution Control Act"), Act 120 of1961, Act 254 of 1969, and Act 743 of 1975. Act 472 provided authorityto ADPCE to establish pollution standards and industrial discharge limitsfor State waters. Act 120 included "wells" within the definition ofwaters of the state, and made it a violation to cause pollution in watersof the State. Act 254 provided a tax penalty for operators allowing saltwater to escape a lease, and required ADPeE to identify the source ofpollution and to take steps to eliminate it if the chloride level in anystream exceeded 250 ppm. Act 743 of 1975 provided ADPCE withjurisdiction to permit disposal of pollutants into wells.

The principal regulations of ADPCE related to oil and gas drillingand production wastes are found in Regulation No.1, "Regulation for thePrevention of Pollution by Salt Water and Other Oil Field Was-toes Produced -byWe:TTs 'in New Fields or Pools." The regulation was promulgated onOctdbe~-i3, 1958, pursuant to the autho~ity provided by Act 472.

"-ADPCE is currently considering revisions to Regulation No.1 that

would be modeled on Louis,iana State Orde)" No. 29-B. As of the start of1987, however, the timing and outcome of the effort were uncertain.

Arkansas has p~imacyfor both the NPDES program and the UIC program.The NPDES program is admin{stered by ADPCE. A Memorandum of Agreement(Mar~h 25, 19Q2) governs the division of authority between ADPCE and

A-26

...

the Oil and Gas Commission witll respect to underground injection ~ells,but there continues to be some disagreement between the two agencies asto what the Agreement actually allows or requires.

- Under the Agreement, ADPCE has primary responsibility for Class I,III, IV, and V injection wells, except for bromine-related brine disposalwells. AOGC is given "administrativa management responsibility for theissuance of construction and operating permits for Class II and Class Vbromine-related disposal wells. AOGC shall be responsible for enforcementin respect to all Class II wells." AOGC is further described asresponsible for well integrity and the migration of wastes from theinjection strata into actual or potential drinking water aquifers.

The Memorandum also notes, however, the statutory overlap ofjurisdiction that it was intended to resolve. The degree to which thisissue is still unresolved is reflected in the introduction. during thecurrent session of the legislature, of a bill drafted by counsel for theCommission that.would have given ~he Commission exclusive aut~ority withrespect to Class II wells, while repeal~n9 all portions of statutesgiving ADPCE any claim to such jurisdiction. The bill failed to get outof commtttee.

--The result of this conflict is that operators do not always comply.or believe they need to comply, with all of the requirements of ADPCE.According to information provided by both the Department and theCommission, operators in the gas fields in the northern part of the Statetend to follow the Department's requirements, while those in the olderoil fields in the south frequently fail to apply for ADPCE permits orfollow their requirements.

A-27


Dri 11 ing

The Oil and Gas Commission does not h~ve any specific regulationsgoverning the construction or management of reserve pits or the disposalof drilling wastes, nor does Regulation No.1 of ADPCE impose anyrequirements on reserve pits. Typical practices include onsite disposalin unlined reserve pits or 1andspreading in the vicinity of the pit.

ADPCE, however, has been sending out letters of authorizationintended to serve as informal permits that stipulate management practicesfor reserve pits and disposal of drilling wastes. Many of the provisionsrequired by the letter are those the Department would like to include ina proposed revision of Regulation No.1. The lack of specificregulations containing the provisions in the letter, however, ~asresulted in urlBven compliance with these requirements by operators. Theletter lists conditions that the Department of Pollution Control andEcology expects to be followed during drilling operations pertaining toreserve pit construction, pit fluid and drilling mud disposal, and drillsite reclamation.

-- - U-nder the letter's requirements, all earthen pits mustJ)~-::1ined with:a synthetic liner (20 mils thick) or a clay liner (18 to 24- inchesthick), and must maintain at least 2 feet of freeboard. Pits must bereclaimed to grade and seeded within 60 days after the drilling rig hasbeen removed from the site. Reserve pit fluids can be disposed of onlyby ADPCE permitted disposal services.

The letter of authorization also states that compl~tion fluids highin total dissolved solids, such as KC1, shpuld be kept separate from the

A-28

..

.:. -,~., - . - _. '. ::.,'

contents of the reserve pit, and recommends that a lined pit be used forthis purpose.

Production

Rules C-7 and C-8 of the General Rules and Regulations define themeans by which salt water produced from oil and gas wells can be.discharged into subsurface formations for disposal or enhanced recovery.The Oil and Gas Commission states that it will consult the StateGeological Survey and the State Board ~f Health, when reviewing anapplication to inject salt water, in order to protect freshwatersupplies.

Wells for disposal and enhanced recovery are to be, cased and cemented"in such manner that damage will not be caused to oil, gas or freshwaterresources." Injection pressure must be limited to ensure that fracturesare not propagated in the confining zones. Injection must be throughtubing set on a packer. Information must be provided by the applicant onall wells or dry holes within one-half mile of the new or convertedinjection well.

Section 4 of Regulation No.1 forbids discharging salt water from anyoil or gas well in a manner whereby the salt water migh~::..come. in contactwith "any of the waters of the State, whether by natural drainage,seepage, overflow, or otherwise." Other sections of Regulation No.1require the well operator to obtain a permit for a waste disposal systemthat prevents the wastes from contacting State waters. The regulationprovides two alternatives for saltwater disposal: (1) subsurfacedischarge in disposal wells constructed in accordance with the Rules andRegulations of the Arkansas Oil and Gas Commission, and (2) surfacedischarge into lined earthen pits. Currently, only subsurface disposalis permitted~

A-29

The letter of authorization issued by the Arkansas Department ofPollution Control and Ecology states that salt water produced any timeduring the lifetime of a well will remain the responsibility of theproduction company, and "shall be stored in a plastic or fiberglass tankabove ground and resting oh a concrete pad."

Offsite Disposal

Disposal of reserve pit fluids and drilling mud requires a permitfrom the Arkansas Department of Pollution Control and Ecology. Thepermit stipulates that the disposal company must provide an analysis ofthe pit fluids and drilling mud, the amount hauled, and its finaldestination. A disposal company that is permitted to land apply pitfluid and drilling mud near the well must provid~ the Department with acopy of the landowner's agreement as well as an analysis of the wastes.An analysis of pit fluid will include tests for chlorides and pH, and adrilling mud analysis will contain tests for chromium, zinc. chlorides,and pH.


-~ W~ll~ that are not completed as commercially productive aftetdrilling must be abandoned and plugged before the drilling equipment isreleased from the drilling operation. No time limitation is establishedin the regulations, however, for temporary abandonment of a properlycased well.

When plugging, a lOO-foot cement plug must be placed above eachproducing stratum, or a bridge plug may be used. A cement plug of

A-30

100 feet must be placed 50 feet below the base of the freshwater stratumif surface casing is not cemented below that stratum; if it is cemented,a 100-foot cement plug should be placed inside the base of the surfacecasing. A plug should be set at the surface of the ground" in such a wayas not to interfere with cultivation. Intervals between plugs should befilled with heavy mud-laden fluid.

. A-31

".' . "'-' ,-

References

Arkansas Department of Pollution Control and Ecology. Regulation No.1,October 1958.

Arkansas Oil and Gas Commission. State of Arkansas Rules and RegulationsOrder No. 2-39, revised 1983.

Interstate Oil and Gas Commission. 1996. Summary of State statutes andregulations for oil and gas production, june 1986.

Interstate Oil Compact Commission. 1985. The Oil and Gas CompactBulletin, Vol. XLIV, No.2, December 1985.

Letter to Mr. Naresh R. Shah, West Virginia Department of NaturalResources Permits Branch, from Mr. Terry Muse, Arkansas Departmentof Pollution Control and Ecology, regarding Arkansas Water Permit No.2839-W, March 2, 1984.

Letter of Authorization from Mr. David A. Thomas, Arkansas Department ofPol1~tion Control and Ecology, to Mr. William S. Walker, StevensProduction Company, August 20, 1986.

USEPA. 1985. U.S.Onshore Oil andAtlanta, Ga.}.Agency.

Environmental Protection Agency. Proceedings:Gas State/Federal Western Workshop (March 26-27 inWashington, D.C.: U.S. Environmental Protection


Phil Deisch, Arkansas Department of Pollution Control andEcology (501) 562-7444.

Steve Drown, Arkansas Department of Pollution Control andEcology (501) 562-7444.

Lynn Fite, Arkansas Oil and Gas Commission (501) 862-4965.

David A. Thomas, Arkansas Department of Pollution Control andEcology, August 1986, (501) 562-7444.

John Welch, Arkansas Game and Fish Commission (501) 223-6319.

~i11iam Wynne; Crumyler, O'Connor, and Wynne; serving as counsel toArkansas Oil and Gas Commission (501) 863-8118.

A-32

CALIFORNIA

INTRODUCTION

California produced 423,900,000 barrels of oil and 493 billionx 109 cubic feet of gas in 1985. Ca1ifornia ranked fourth in U.S. oilproduction and sixth in U.S. gas production. Production was fl"om 55,079producing oil wells and 1,566 producing gas wells. Approximately55 percent of the oil production is attributed to enhanced recovery.

REGULATORY AGENCIES

A number of agencies regulate oil and gas activity in California,including:

8 California Department of Conservation, Division of Oil and Gas;

California Water Resources Control Board and the nine RegionalWater Quality Control Boards;

California Department of Health Services;

California Air Resources Board and the county or r~gional AirPollution Control Districts;

State Lands Commission;

California Coastal Commission;

Local government agencies;

8 U.S. Bureau of Land Management; and

U.S. Department of Energy .

. The Division of Oil and Gas of the California Department ofConservation. created in 1915, issues permits for the drilling, reworking,and abandonment of oil and gas wells. Under authority delegated by EPA,the Division also issues UIC permits for Class II injection wells. As

part of its responsibilities, the Division ensures that the drilling andoperation of such wells do not endanger fresh ground-water strata.

The California Water Resources Control -Board is generally responsiblefor protecting the waters of the State and for preserving all present andanticipated beneficial uses of these waters. EPA has delegated authorityto issue NPDES permits to the Watel' Resou~ces Control Board. Thisresponsibility is implemented through nin~ Regional Water Quality ControlBoards, which issue Waste Discharge Requirements (California's NPDESpermits) for point sources of water pollution. The Water Resources -Control Board has the autnority to adopt statewide water quality policyand water quality control plans for regional -boards to follow .

. The regional boards must, at a minimum, implement requirements asstrict as those of the State board; however, they have autonomy todevelop more stringent requirements within their regions. All dischargesof drilling wastes or produced waters to surface impoundments or surfacewa ters are subject to the permit t i ng authority of the reg iana1 boards.Under a Memorandum of Understanding between the Regional Water Quality

I -

Control Boards_ and the Division of Oil and Gas, the regional boards alsohave the responsibility for reviewing permits written by the Division ofOil and Gas to ensure the incorporation of the concerns of the regionalboards.

The California Department of Health Services is r~sponsible for theregulation of hazardous wastes. The Department determines which wustestreams and constituents are hazardous under California's laws, includingdeterminations as to the hazardousness of drilling fluids and muds. TheDepartment is also responsible for the regulation of the injection wellsinto which hazardous wastes are being injected. Further, the Departmentof Health Services shares with the-Regional Water Quality Control Boards

A-34

the responsibility for regulating hazardous waste landfills and surfaceimpoundments;

For wells on State-owned, onshore lands~ the State Lands Commissionhas joint responsibility with the Division of Oil and Gas. Theirresponsibilities are expressed in the provisions of the lease terms.

The California Department of Fish and Game, while not a permittingagency for drilling projects, provides comments and recommendations onmethods to mitigate any problems that oil and gas operations may createfor fish and wildlife. The Department of Fish and Game coordinates Stateoperations involving spills that affect fish and wildlife.

Local Air Pollution Control Distric~s issue permits to operateequipment that emits pollutants into the atmosphere. The equipmentincludes steam generators used for enhanced oil recovery projects.

The California Coastal Commission issuesproposed within the coastal zone. This zone3-mile seaward limit to 1,000 yards inland.this area would need permits, a1though thereexemptions.

permits for any developmentextends from the State'sOil and gas projects withinare provisions for

Cities and counties also issue land use permits for eil and gasoperations. Generally, a condition of their permits requires that anoperator comply with the regulations of the Division of Oil and Gas.

The Bureau of Land Management (BLM) approves approximately 400 oiland gas drilling permits per year on Federal lands and provides permitsfor wells for reinjection of produced waters. Since operators of

A-35

these wells must meet the requirements of the State as well as BLM, theyare subject to dual permitting. In 1985, there were 6,200 oil, gas, andinjection wells on Federal lands. The oil and gas wells produced about22.4 million barrels of water per month, with most going to reinjectionand some to evaporation percolation ponds.

The Department of Energy manages the Elk HIlls Naval PetroleumReserves. In 1985, these fields produced approximately 86,000 barrels ofwater, 128,000 barrels of oil, and 184 billion cubic feet of gas perday. Produced waters have been reinjected or disposed of in earthensumps, but the Department of Energy has been managing a transition todisposal only in injection wells.


Drilling

Under Article 9 of Title 22 of the California Administrative Code,drilling fluids and drilling muds are listed as wastes that come underthe provisions of the regulations for hazardous wastes if they contain ahazardous material. Mosf muds actually in use in Calif~~~iaqo not fallunder this provision, however. The Department of Heal~h~~erviceshasprepared a list (available to operators on request) of_a4qih~e~ andfluids that are nonhazardous if used according to the manufacturers'recommendations. The Department will also review test data submitted bycompanies on hew muds or fluids when requested to do so. in order todetermine if they are nonhazardous.

Discharges of drilling muds and cuttings that do not containhalogenated solvents into onsite sumps are specifically excluded from therequirement~ affecting "Discharges of Waste to Land" (Subchapter 1~,Chapter 3, Title 23) under the jurisdiction of the Regional Water Quality

A-36

Control Boards, provided that the operator takes appropriate measures atthe conclusion of drilling operations. The operator must either"(I) remove all wastes from the sump or (2) remove'all free liquid fromthe sump and cover solid and semisolid wastes, provided thatrepresentative sampling of the sump contents after 1iquid removal showsresidual solid wastes to be nonhazardous."

Drilling pits mayor may not need to he lined or sealed depending ontheir location. While the Regi~nal Water Quality Control Boards do notprescribe pit construction conditions, the conditional use permit that adriller obtains from each county may detail the pit requirements. If thefluids contain hazardous materials, the pits would have to have liners.

On Federal lands, drilling fluids are left in the sump untilcompletion of the well, after which drilling fluids are hauled to aClass II disposal site for oil field wastes.

Before drilling a well, operators must file an indemnity bond withthe- Division of Oil and Gas to ensure that the appl icant campl ies withthe permit requirements and properly abandons or completes the well.After proper abandonment or completion, the Division releases' the bond.

Produced Waters

Produced waters may be reinjected for enhanced recovery or disposal,discharged on the surface for beneficial use, placed in lined sumps forevaporation or unlined sumps for evaporation and percolation, or disposedof in sewer systems. In some cases, produced waters ultimately disposedof in sumps are first discharged into watercourses, which carry the saltwater to the sumps. The impact and legality of this practice arecurrently under review. The approximate percentages of produced waterdisposed of b~ each method are:

A-37

Evaporation in percolation sumpsEvaporation in lined sumpsDisposal in sewer systemsSurface disposal (beneficial)Injection for enhanced recoveryInjection for disposal

Surface Discharge for Beneficial Use

18%

6%2%

18%41%

15%.

In cases where the quality of the water is sufficient for beneficialuse for irrigation, livestock, and/or wildlife, produced waters may be

,perw.itted for discharge into surface waters (principally into irrigationcanals, dry ditches, and ephemeral streams). There are at least 12 suchpermits in the Fresno office of the Central Valley Regional Water QualityControl Board. Discharge permit'limits include the following maximumvalues:

Oil and greaseChloridesBoronElectrical conductivity

Sewer Disposal

35 mg/L

200 mg/L1 mg/L1,000 umhos.

The small percentage that goes to sewer systems is predominantlywithin the Los Angeles County Sanitation District. Production watersentering such sewers must meet 'applicable pretreatment standards,including a maximum oil and grease content of 75 mg/L, and limits onheavy metals, cyanide, chlorinated hydrocarbons, and sulfides. There isno pretreatment limit for chloride.

A-38 '

Regulation of all ,saltwater sumps is under the jurisdiction of theRegional Water Quality Control Boards, which have .the authority toregulat~ discharges to surface impoundments "by issuing waste dischargerequir~ments, including discharge prohibitions, which implement waterquality control plans" (Title 23, Chapter 3, Subchapter 15 of theCalifornia Administrative Code). But whil& minimum regulatory standardsare established for various classes of impoundments under Subchapter 15,a specific exemption is provided for evaporation ponds and percolationponds if "the applicable regional board has issued waste dischargerequirements, reclamation requirements, or waived such issuance." To beeligible for the exemption, the discharge must also be nonhazardous andcomply with the State Board's nondegradation policy and with "the waterquality objectives set forth in th~ applic~ble water quality controlplan .... " For example, unlined sumps containing produced waters thatcould adversely affect freshwater aquifers would not be permitted inlocations which could impact such aquifers.

Regional Water Quality Control Boards, while they must at leastimplement the requirements established by the State board, have theauthority to establish requirements "more stringent than those set by theState board. Thus~ the regional boards may establish specific pitconstruction requirements (e.g., liners to prevent percolation from thesumps) in sensitive areas.

Any sump, other than an operations sump, containing a mixture of oiland water, must be covered with screening to restrain entry of wildlife.If the Department of Fish and Game deems the condition of a sump to behazardous for wildlife. the Department notifies the Division of Oil andGas, which requires the operator to abate the ~ondition within 10 days(if an immediate or grave danger) or 30 days.'

A-39

In addition to discharge to onsite saltwater sumps,volumes of salt water are discharged to offsite sumps.discussed below.

Injection

substantialThese are

Over half of the produced waters in California are reinjected, eitherfor enhanced recovery or for disposal; The authority for management ofClass II injection wells is delegated by EPA to the Division of Oil andGas. The Regional Water Quality Control Boards, under a Memorandum ofUnderstanding with the Division of Oil and Gas, may comment on Class IIinjection well permits on matters that could affect water quality,including degradation of ground water.

On Bureau of Land Management leases, operators of Class II wells mustobtain permits from both the Division of Oil and Gas and BLM. M~ny ofthe injection ~ells are for enhanced recovery and therefore couldsignificantly affect BLM's royalty earn~ngs from its leases. As aresult, BLM wants to maintain-joint signatory authority on UIC permits.BLM and the Division of Oil and Gas are attempting to develop aMemorandum of Understanding on joint permitting.

Injection wells, other than those injec~ing steam, air, or-pipeline-quality gas, must be equipped with tubing and packer set immediatelyabove the approved zone of injection. Exceptions may be granted wherethere is no evidence of freshwater-bearing strata, where more than onestring of casing is cemented below the base of fresh water, or where theoperator can demonstrate that freshwater and oil zones can be protectedwithout tubing and packer. The pressure in the well must not besufficient to fracture the zone of injection.

A-40

To obtain approval from the Division of Oil and Gas, operators mustfile plans, geologic analyses, evaluations of the impact of the plannedwell on other wells in the area, monitoring programs, the source andanalysis of the water being injected, an~ analysis of water in theinjection zone. A new chemical an~lysis of the water being injected mustbe filed whenever the source of the water i~ changed or as requested bythe Division. Mechanical integrity tests (MIls) are carried outannually, except for thermal enhanced recovery wells and wells withspecial conditions. In these cases, MITs are performed on varyingschedules--usually every 3 years.

Some disposal of salt water in California also takes place incombination with other .oil field-related nonhazardous wastes in Class Vwe11s; regulation of Class V wells has not been delegated to the State.

Any wells into which wastes defined as hazardous under Californiaregulations are being injected, regardless of the Federal classification,would become subject to the requirements established in the Toxic

. Injection Well Control Act of 1905, which are generally more stringentthan Federal requirements. These requirements are under the jurisdictionof the Department of Health Services.

Uffsite Disposal

Central Sumps for Produced Waters

On the western side of the San Joaquin Valley, a series of largepercolation/evaporation sumps receive produced water discharged to themthrough natural watercourse drainage. The Department of Energy hasordered the closure of two of these sumps, whi~h are on the property ofthe Elk Hills Naval Petroleum Reserve; the two' sumps no longer receive

A-41

- ... -. ~--" - ~. -. --- ... ,.. - - ,. -.-; -..-'. -

produced waters and are in the process of clo5ure. The remaining sumpsare still operating. Some of the wells discharging to the sumps, andsome of the watercourses through which the discharges ~o, are on Federallands managed by the Bureau of Land Management. Currently, most of thesumps either operate under requirement~ dating back two decades, or haveno requirements at all.

While this disposal method c~rrently is allowedy.the Central ValleyRegional Water Quality Control Board is considering whether theseproduced waters should be regulated under the requirements for California"designated" wastes (if they contain pollutants that exceed water qualityobjectives or could cause degradation of the waters of the State). Thereis also a question as to whether this method of disposal is in accordancewith 435.32 of 40 CFR, since the discharg~ to the sumps is throughnatural watercourses, and the. discharged waters generally do not meet therequirements for agriculture and wildlife use.

Waste Disposal Facilities for Drilling Wastes

Drilling wastes may be transported offsite for disposal. Ifhazardous by California's definition, the wastes must be disposed of (asrequired by Section 2521, Subchapter 15, Chapter 3, Title 23) in Class 1waste management units (requiring double liners and no migration~~ .If.classified as "designated" wastes, they may be disposed of in Class IIfacilities (single liners. no migration, and design and constru~tion ~forthe containment of the specific wastes which will be dischal'ged") orClass I facilities. If ncndezignated, a~ternative uses would bepermissible.

A-42

Transport

An invoice for an undesignated waste is required'for trucks haulingproduced water. If being trucked to a central injection facility, theDivision of Oil and Gas requires that the trucker carry a ticketdesignating the volume and source of the fluid. The operator of thecentral facility collects a copy of the ticket and files it.


Under Section 3237 of the Public Resources Code~ suspension ofactivity and removal of drilling activity is evidence of desertion of awell after 6 months. Removal of production equipment is evidence ofdesertion after 2 years. While the' Supervisor of the Division of Oil andGas may order the plugging of a well that has been deserted, the Divisionof Oil and Gas generally exercises its discretion for previouslyproducing wells (particularly those that were permitted prior to theexistence of a bonding requirement). Moreover, the Division activelycommunicates with operators about plugging wells that have been. out ofproduction for 5 years.

When a well is plugged, cement plugs generally should ba placed-across specified intervals to protect oil, gas, and us~pl~ water zones.The district deputy may allow cement to be mixed with or replaced byother substances with adequate physical properties. Intervals that arenot plugged are to be filled with mud fluid of "sufficient weight andconsisten~y" as to prevent movement of other fluids into the wellbore.

At the surface, the hole and all annuli must be plugged with at leasta 25-foot cement plug. In an open hole, a ~ement plug must be placedfrom at least 100 feet below the bottom to at least 100 feet above the

A43

top of each oil or gas zone, and at least a 200-foot plug must be placedacross all fresh-saltwater interfaces. Where the hole is open below theshoe, a cement plug is required from 50 feet below to 50 feet above theshoe.

In a cased hole, all perforations must be plugged with cement, and aplug must extend at least 100 feet above the top of a landed liner, theuppermost perforations, the casing cementing point, the water shutoff'holes, or the oil or gas zone, whichever is highest. If cement is behindthe casing across the fresh-saltwater interface, a 100-foot cement plugmust be placed at the interface inside the casing. If the top of thecement behind the casing is below the top of the highest saltwater sands,squeeze-cementing is required through perforations to protect the freshwater, in addition to a 100~foot plug inside the casing.

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i ./

References

California Administrative Code: T~t1es 14, 22, and 23. Title 14,Chapter 4 - Development, Regulation and Conservation of Oil and GasResources Title 23, Chapter 3, Subchapter 15 - Discharges of Waste toLead Title 22, Chapter 30 - Minimum Standards for Management ofHazardous and Extremely Hazardous Wastes.

Interstate Oil and Gas Comm~ssion. 1986. Su~mary of State statutes andrequlationsfor oil and gas production, June 1986.


Mefferd, Marty. 1985. Letter communication to EPA.Supervisor, Division of Oil and Gas.

USEPA. 1985. U.S. Environmental Protection Agency. California MeetingReport. Proceedings of the Onshore Oil and Gas State/FederalWestern Workshop (March 26-27 in Atlanta, Ga.). Washington, D.C.:U.S. Environmental Protection Agency.


Theodore R. Anderson, Bureau of Land Management, Bakersfield,(805) 861-4177.

Hal Bopp, Division of Oil and Gas (805) 322-4031.

Shelton Gray, Central Valley Water Quality Control Board(209) 445-5142.

Bob Reid, Division of Oil and Gas (916) 445-9686.

Chong Rhee, L.A. County Sanitation District (213) 699-7411.

Scott Smith, Central Valley Water Quality Control Board(209) 445-5116.

Greg Williams, Department of Health Services (916) 322-0453.

A-45

COLORADO

INTRODUCTION

Colorado has a !ong history of regulating o~l and gas activities. Asfar back as 1889, Colorado passed a bill prohibiting the discharge ofoil, petroleum, or other substances into any waters of the State. In1927, a second bill was enact~d that included provisions for wellplugging. In 1951, the Oil and Gas Conservation Act was passed. TheSolid Wastes Disposal Sites and Facilities Act was passed in 1973. TheSolid Wastes Disposal Sites and Facilities Act (Title 30-20-Part 1,C.R.S. 1973, as amended) also has jurisdiction over oil and gasactivities.

Inwell s;well s.

1985, Colorad~ produced 30,552,685 barrels of oil from 5,287275,684 million cubic feet of gas were produced from 4,665 gas

Mud and air drilling are both encountered.

REGULATORY AGENCIES

The three agencies sharing regulatory authority for oil and gaswastes in Colorado are:

Department of Natural Resources--Oil and Gas Conser~ationCommission;

Department of Health; and

U.S. Bureau' of Land Management.

The Oil and Gas Conservation Commission has primary responsibilityfor the management of oil and g~s exploration, developmp.nt, andproduction activities in Colorado. The Commission is responsible for the

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-, ~,- .... '-: '--

conservation of oil and gas and the protection of the rights of allparties. It has general authority, to protect the environment frompollution by oil and gas activities on the sites of drilling and'production operatio~s. The Commission is also,responsible for theregulation and permitting of central disposal facilities operated by theproducing companies.

The Colorado Department of Health, spe:ifically the Wate( QualityControl Division/Commission and the Waste Management Division, hasstatutory and loegulatory authority over solid waste disposal sites andfacilities and NPDES permits, and is generally concerned with theendangerment of public health and the environment. Commercial disposalfacilities for wastes from oil and gas production operations are subjectto the Departmentis permitting and regulation. In addition, theDepartment is responsible for permitting of discharges for beneficial usefor agriculture and wildlife.

Because the two agencies shared certain areas of responsibility undertheir statutes, they developed a Memorand~m of Understanding in 1971 tospecifically allocate responsibilities. Under this agreement, the WaterQuality Control Commission of the Department of Health designated the

--Oil and Gas Conservation Commission as "its authorized'represeotative_to~ ~'~exercise authority for the administration of water pol!utionprevention,

. abatement and control required to protect the waters of~the state fromconditions and activities arising from the drillfng, prod4ction andpl~gging of wells and all ~ther operations for the production of oil andgas." This relationship has subsequently been clarified in theregulations of both agencies. The Department of Health regulations.specify that the Department:

"... will consider oil and gas liquid waste impoundments to be incompliance with these regulations if:

A-48

A. The disposal facilities are regulated by the Oil and GasConservation Commission,

B. There is no imminent or substantial endangerment to the publichealth or the environment from the disposal facilities, and

C. Compliance with the Certificate of Designation requirement is notrequired by the County within which the site is located (forcentral disposal facilities only)."

The U.S. Bureau of Land Management has jurisdiction overFederally-owned mineral rights. The U.S. Forest Service retains surfacerights on Federally-owned forests and grasslands. EPA retainsresponsibility for approving underground injection wells on Indian land.The requirements of these agencies are discussed separately in thesection on Federal agencies. (See Volume 1" Chapter VII.)


Drilling

Pit Requirements ~

Oil and Gas Conservation Commission rules require that "beforecommencing to drill, proper and adequate slush pits shall be constructedfor the reception and confinement of mud and cuttings-and to facilitatethe drilling operation, Special precautions shall be taken to preventcontamination or pollution of state waters."

According to information provided by the Oil and Gas ConservationCommission, most wells are drilled using tanks rather than reserve pits;the reserve pits are used primarily when the mud is displaced during therunning of pipe. While no rules prohibit the discharge of producedwaters into a reserve pit, this is not commonly done. If the

A49

volume of produced water exceeded five barrels/day, this would make thereserve pits subject to the construction requirements and reviews inRule 325. Otherwise, pits "for temporary storage and disposal ofsubstances produced in the initial completion and testing or workover ofwells drilled for oil and/or gas for a period of time not in excess ofninety (90) days" are excluded from application of many of the Rule'sprovisions.

Most drilling fluids and muds in Colorado are bentonite- andfreshwater-based. Very few oil-based drilling fluids are used, and theseare moved from operation to operation until disposed of into an approvedlandfill.

Pit Closure/Discharqe

If the well is a dry hole and is abandoned, backfilling of pits andreclamation of the land must be completed within 6 months unless an

. extension is granted for unusual circumstances (Rule 319(a)(8)).

Generally, after the lighter fluids are decanted in the reserve pits,reserve pit sludges may be dried out and disposed of on the surface bytil.ling into the grciund. The sludge may be removed to a differentlocation before land disposal. The sludge may also be buried when thepitis backfilled. The Commission has permitted one facility for landdischarge of wastes with limitations on total suspended solids, totaldissolved solids, oil and grease, and chemical oxygen demand.

Produced Waters

Produced water is disposed of through reinjection (approximately85 percent), placement in storage and disposal pits (approximately15 percent), and discharge for beneficial use for agriculture andwildlife 1 percent).

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..

Disposal and Storage Pits

The Oil and Gas Conservation Commission regulates all produced-waterstorage or disposal pits except for the commercial disposal facilities.regulated by the Department of Health. This includes both onsite andcentral pits. A central pit is a storage or disposal pit serving severalleases or batteries in a field, and operated by one of more oil and gasoperators under a field operator's agreement approved by the Commission.

Both central and onsite pits are subject to the requirements ofRule 325, which specifies informational, construction, and operatingrequirements. Minimally, such pits are required to have adequate storagecapacity for the volume of produced water expected, and to be kept freeof surface accumulations of oil or other hydrocarbons that could impedeevaporation. Certain other requ~rements in the Rule do not apply wherethe volume of water to be disposed of does not exc~ed five barrels perday on a monthly basis.

Generally, applicants for pel"mits to construct produced waterdisposal pits must provide substantial information on surface waters andground waters, geology, and soil types in the area of the well. Theapplication must also indicate the source and expected yolume of water to

: be produced daily, and a chemical analysis of the water~a~sessing allf~ctors r~lated to salinity. If a pit is located over permeable soil,and will receive, at full capacity, in excess of 100 barrels of fluid/daywith a TDS content of 5,000 ppm or more, the operator must provide a planfor lining the pit and detecting leaks. Liners may be required wherewater placed in the pit has a higher TDS content than underlying aquifershydrologically connected, regardless of the amount of water delivered tothe pit.

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The Commission makes a case-by-case determination on liningrequirements for all produced-water storage and disposal pits on thebasis of site-specific evaluations. According to information provided bythe Commission, 90 percent of the pits for wells producing more thanfive barrels per day of water are requjred to be lined (approximately two-thirds with clay and one-third with synthetic liners). Of the remainingpits, either the received water is fresh and allowed to percolate, or thepits are over impervious shales and the water evaporates~

Injection

Produced water is reinjected into Class II wells both for enhancedrecovery (667 wells) and disposal (134 wells). The UIC Class IIinjection program has been delegated to the Oil and Gas ConservationCommission.

Wells usedofor injection into oil or gas producing disposal zonesmust have "safe and adequate casing or tubing so as to prevent leakage,and shall be so set or cemented that damage will not be caused to oil,gas or fresh water resources." Detailed reports on fluids received andinjected must be filed monthly .

.. Mechanical integrity tests must be performed on new inj~Etjen~~ells~:before starting injection and every 5 years thereafter~~The te$tpressure must be 300 psi or the minimum injection pressure, whichever isgreater, and not more than the maximum injection pressure, with apressure variance of no more than 10 percent. Monthly injection reportsare submitted listing volumes injected and injection pressures. Allinjection facilities are inspected by the Commission staff on a routinebasis.

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Discharges for Wildlife and Agricultural Use

A few State facilities have permits from the Department of Health foreffluent discharges under the BPT Wildlife and Agricultural UseSubcategory. The effluent limitations are:

pH

Total suspended solids

Oil and grease

Total dissolved solids

Offsite Disposal

6.0 to 9.0

30 mg/L (3D-day average)45 mg/L (I-day maximum)

10 mg/L

5,000 mg/L (3D-day average)7,500 mg/L (I-day maximum).

" :::

Commercial offsite prodllced water evaporation or evaporation/percolation pits are regulated by the Division of Waste Management of theDepartment of Health. According to information provided by theDepartment of Health, there are currently eight commercial disposal pits,half of which are lined. Lining requirements are determined byclassifications of impoundments. Class I facilities (in a recharge areafor a drinking water aquifer where seepage from impoundment would impair

_use of the ground water) require double liners with leak detectio~systems. Class II impoundments (where seepage would damage a freshwateraquifer if no liner were used) require single liners and monito~ingsystems._ Class III impoundments (those located outside a recharge area.having competent bedrock between the surface and the aquifer, or whereimpairment would not result from unrestricted seepage) require no liners.

Truckers transporting produced waters to offsite impoundments orinjectlon wells must file monthly reports on the source, volume, and

A-53

recipient of the waters hauled. Similar records must be kept by thereceiving facility. These records will be subject to computerizedcross-tabulation.


Wells that have ceased production or are incapable of production areto be abandoned within 6 months unless granted an extension by theDirector of the Oil and Gas Conservation Commission (Rule 319(b. Inpractice, if a well is shut down for economic reasons, th~ Commissionwill not require a formerly producing we]l to be plugged. If, however,the operator of the well has numerous wells that are closed down foreconomic reasons, and is operating all such wells under a single blanketbond, the Director may require the provision of individual bonds for eachwell. The operator must file a status report every 6 months indicatingplans for future operations.

Wells must be plugged so as to confine oil, "gas, or water to theoriginal strata. The operator must obtain approval of the pluggingmethod from the Commission prior to the plugging operation. Surfacecasing may not be removed from the well unless approved by the Director.Generally, requirements call for the placement of cement plugs 50 feetabove and below each permeable zone, a IOO-foot plug at the-base of thesurface casin~, and a cement plug at the top of the surface-casing. Theoperator may plug above perforated zones, or may squeeze with cementprior to abandoning the well or before recompleting into anotherformation.

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References

Colorado Department of Health. Statement of the Colorado Department ofHealth for the Informational Hearing Regarding Oil and Gas BrineWaste Disposal to the Colorado Water Quality Control Commission.May 10, 1983.


Order 1-39, modifying the Rul~s and regulations of the Oil and GasConservation Commission. Effective August 8, 1986.

State of Colorado. Regulitions pertaining to solid waste disposal sitesand facilities, Effective Date: October 1, 1984.

State of Colorado. Department of Natural Resources. Oil and GasConservation Commission. Rules and regulations. rules of practiceand procedure. and Oil and Gas Conservation Act (As Amended).Effective July 16, 1984.

USEPA. 1985. U~S. Environmental Protection Agency. Colorado MeetingReport. Proceedings of the Onshore Oil and Gas State/Federal WesternWorkshop (March 26-27 in Atlanta, Ga.). Washington, D.C.: U.S.Environmental Protection Agency.

Personal COmmunication:

William R. Smith, Oil and Gas Conservation Commission (303) 866-3531.

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FLORIDA

INTRODUCTION

Florida p"oduced 14,090.000 barrels of uil and 15 x 109 cubic feetof gas in 1984. Production was from 165 oil wells; there are noproducing gas wells. Virtually all drilling fluids as well as producedfluid$are reinjected.

REGULATORY AGENCIES

The four agencies responsible for regulating the oil and gas industryin Florida are:

Florida Department of Natural Resources, Division of ResourceManagement, Florida Geological Survey;

Florida Department of Environmental Regulation;

Florida Regional Water Management Districts; and

U.S. Environmental Protection Agency, Region IV .

. Primary regulatory responsibility rests with the Department ofNatural Resources (DNR). DNR is the per'mitting agency for oil and gaswells, including approval to dispose of waste fluids by subsurfaceinjection. The DNR regulates the exploration, drilling, and productionof the oil and gas industry with respect to reporting, spacing, safety,and construction.

The Department of Environmental Regulation oversees the industry withregard to water ~uality standards and dredge and fill requirements (forpits) if oil and gas activities occur in wetlands of the State.

Florida's Regio~al Water Management Districts, which are separateregulatory groups on a iocal le~el, regulate oil and gas activitiesinvolving water use. Consumptive use permits are issued if applicable.

Other State agencies may ~e involved on a ~ase-bY-lase basis. Theseagencies are most commonly the Florida Game and Freshwater FishCommission, the Department of Community Affairs, and the D~partment ofTransportation.

The Stat~ of Florida does not have primacy for Class II UIC programwells. The State operates a separate program for injection well~ with aState permit and State inspections. A driller wishing to inject fluidsunderground must apply for a permit to do so from two separategovernmental entities, the U.S. Environmental Protection Agency Regiun IVand the State, and undergo two sets of in~pections.


Drilling fluids are put into pitsdisposed of by reinjection. Pits are

,c'-backfilled. They are lowered as fastwellbore prior to plugging the well.

during operation, but then arenearly dry when they areas possible by pumping down theA11 produced waters. are rei njected .

. I" The DNR is governed by Chapter 377, flo~'ida Statutes, and itsimplementing l"ules, Chapters 16C-25 thro~l;h 16C-30, FloridaAdministrative Code. One aspect of Chapter 377's specific purpose is to"require'the drilling, casing, and plugging of wells to be done in such amanner as to prevent the pollution of fresh, salt, or brackish waters on1he lands of the State." Section 377.371 further states that, "No persondrilling for or producing oil, gas, or other petroleum products shallpollute land or water; damage aquatic or marine life, wildlife, birds, or'public or private property."

f'

UIC permi~s are issued pursuant to Chapter 403, Florida Statutes, andChapter l7-Z8, Florida Administrative Code. If applicable, dredge andfill ac

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