design, commissioning, decommissioning and recommissioning

TECHNICAL GUIDANCE NOTES TGN/1.10

DESIGN, COMMISSIONING, DECOMMISSIONING AND RECOMMISSIONING OF PETROLEUM TERMINALS

JUNE 2016

Design, Commissioning, Decommissioning and Recommissioning of Petroleum Terminals

Energy Regulatory Commission, 2015

Contents

1. Introduction ..................................................................... 15

2. Disclaimer ........................................................................ 15

3. Petroleum Terminals ....................................................... 15

4. Objective .......................................................................... 16

5. Scope ................................................................................ 16

6. Availability ...................................................................... 17

7. Legal Framework ............................................................. 17

General .......................................................................................... 17

8. Permits and Licenses ........................................................ 17

9. Using the PPGs ................................................................ 17

10. Design .............................................................................. 18

Risks ............................................................................................. 18Construction Standards for ASTs ................................................. 18Storage of Hazardous Material ..................................................... 19Site Selection ................................................................................ 20Site Diagrams ................................................................................ 21

11. ASTs ................................................................................. 21

12. Pipework .......................................................................... 23

13. Hose Specifications .......................................................... 23

14. Loading Facility ............................................................... 24

15. Drainage Systems ............................................................ 30

16. Corrosion Prevention ....................................................... 31



General Requirements .................................................................. 31Cathodic Protection ....................................................................... 31Exterior Coatings ........................................................................... 32Interior Linings and Coatings ....................................................... 32

17. Overfill Requirements ..................................................... 33

18. Construction ..................................................................... 34

General .......................................................................................... 34Material ......................................................................................... 34Foundation .................................................................................... 35Installation .................................................................................... 35

19. Erection Methods ............................................................. 36

General .......................................................................................... 36Progressive Assembly ................................................................... 36Complete Assembly – Welding Horizontal Seams ....................... 36Jacking Up ..................................................................................... 36Floatation ...................................................................................... 37Prefabrication ................................................................................ 37Construction of Bottom Plate ........................................................ 38Secondary Containment ................................................................ 38Welding ......................................................................................... 38Tolerances ..................................................................................... 39

Shell ............................................................................................................ 39

Floating Roof .............................................................................................. 40

Inspection ................................................................................................... 40

20. Modifications ................................................................... 40

21. Ancillary Equipment ....................................................... 41

General .......................................................................................... 41Pipework ....................................................................................... 41



Vents ............................................................................................. 42Fill Point ....................................................................................... 42

22. Release Prevention and Leak Detection .......................... 44

Overfill Protection ........................................................................ 44Secondary Containment ................................................................ 44Leak Detection .............................................................................. 46

Liquid Sensing Probes and Cables .............................................................. 47

Volumetric and Mass Measurement Methods ............................................ 47

Statistical Inventory Control Methods ......................................... 48Automatic Tank Gauging ........................................................................... 49

Passive-Acoustic Sensing ............................................................................ 49

Vapor Monitoring ....................................................................................... 50

Fiber Optic Sensing Probes ......................................................................... 50

Spill and Storm Run Off ............................................................... 50Ground Monitoring Wells ............................................................ 51

23. Spacing and Dikes ........................................................... 52

24. Vapour Emission Control ................................................ 54

Expected Emissions ....................................................................... 54Associated Emissions .................................................................... 55Requirements ................................................................................ 55

25. Gauging ............................................................................ 55

26. Commissioning ................................................................ 56

General .......................................................................................... 56Labelling ....................................................................................... 56Tank Testing ................................................................................. 57Initial Filling ................................................................................. 57Installation and Modification Inspections ................................... 59Third Party inspections ................................................................. 60



27. Decommissioning ............................................................ 60

Out of Service AST Requirements ................................................ 60Permanent Closure or Change in Service ..................................... 60Temporary Removal from Service ................................................ 61Removing Recoverable Product .................................................... 62Tank Isolation ............................................................................... 62Vapour and Gas Freeing ............................................................... 63Cleaning ........................................................................................ 64

28. Recommissioning ............................................................. 64

General .......................................................................................... 64Temporary Requirements ............................................................. 64

29. Record Keeping ................................................................ 65

30. References ........................................................................ 66

31. Contacts ............................................................................ 67



Acronyms

Acronym Description

API American Petroleum Institute

AST Aboveground Storage Tank

ATG Automatic Tank Gauging

CO Carbon Dioxide 2

COP Codes of Practice

DOSHS Department of Occupational Safety and Health Services

ERC Energy Regulatory Commission

ESD Emergency Shutdown

GMW Ground Monitoring Well

H2 Hydrogen Sulphide S

HAP Hazardous Air Pollutant

KEBS Kenya Bureau of Standards

KS Kenya Standard

LPG Liquefied Petroleum Gas

NEMA National Environment Management Authority

OSR Oil Spill Response

OWS Oil Water Separator

PIRP Pollution Incident Response Plan

PPG Technical Guidance Notes

PVC Poly Vinyl Chloride

PVR Pressure Vacuum Relief

RPB Reactive Permeable Barriers

RVP Reid Vapor Pressure

SCS Secondary Containment System

SOPs Standard Operating Procedures

SUDs Sustainable Drainage Systems

VOC Volatile Organic Compounds



Terminology

Terminology Description

Ancillary Equipment

Electrical, vapor recovery, access or other systems and devices, including, but not limited to, devices, such as piping, fittings, flanges, valves and pumps used to distribute, meter, monitor or control the flow of regulated substances to or from a storage tank system.

Aquifer A geologic formation, group of formations or part of a formation capable of a sustainable yield of significant amount of water to a well or spring.

Automatic Tank Gauging

Automatic Tank Gauge. Electronically operated system that automatically measures the level of product inside the AST.

Bulk Storage Terminal

Premises consisting one or more tanks for storing petroleum or liquefied petroleum gas in transit or for sale

Breathing Losses Emissions that occur when vapors are expelled from the tank due to changes in temperature, barometric pressure, or both. Breathing losses are also known as standing losses.

Cathodic Protection A technique to prevent corrosion of a metal surface by making that surface the cathode of an electrochemical cell.

Certified Inspector A person certified by DOSHS to conduct inspections of tanks or storage tank facilities and who may conduct environmental audits. A certified inspector may not be an employee of a tank owner.

Change Any modification other than “replacement in kind.”

Cleaning Process of removing vapor, sludge, or rinsing Liquid from a storage tank.

Company Company within the meaning of the Cap. 486 of Companies Act

Compatible The ability of two or more substances to maintain their respective physical and chemical properties upon contact with one another for the design life of the tank system under conditions likely to be encountered in the tank system.

Competent Person Means a person with enough practical and theoretical knowledge, training and actual experience to carry out a




particular task safely and effectively.

Compliance Meeting legal, regulatory or company requirements.

Connected Piping All piping including valves, elbows, joints,flanges and flexible connectors attached to a tank system through which regulated substances flow. For the purpose of determining how much piping is connected to any individual tank system, the piping that joins two regulated systems should be allocated equally between them.

Contaminant Something that makes a place or a substance (such as water, air, or food) no longer suitable for use.

Containment Structure

Anything built, installed or established which comes in contact with regulated substances that are spilled, leaked, emitted, discharged, escaped, leached or disposed from a storage tank or storage tank system. The term includes, but is not limited to, a vault, dike, wall, building or secondary containment structure around an underground or above-ground storage tank, or any rock or other fill material placed around an underground storage tank.

Contractor Any company or individual that is under contract to provide services.

Code of Practice Codes of practice state ways to manage exposure to risks. If a code of practice exists for a risk at the workplace, the operator must:

• Do what the code says; or • Adopt another way that identifies and manages

exposure to the risk; and • Take reasonable precautions and exercise due care.

Corrective Action Taking measures to prevent, mitigate, abate or remedy releases, pollution and potential for pollution, nuisances and damages to the public health, safety or welfare.

Corrosion Protection

The protection of metal from deterioration. The deterioration may be due to a natural electrochemical reaction between the metal and the soil or other electrolyte, or because of stray direct currents.

Danger Risk to the environment, health, life, person or property of anyone from pollution arising from operation and maintenance of petroleum facilities

Degassing Process of removing organic gases or vapors from a storage tank.

Emergency A containment structure which serves to convey, capture




Containment and contain the total volume of an anticipated release of regulated substance from an aboveground or underground storage tank system and which is expeditiously emptied.

Emission The episodic or ongoing release of materials to the environment (air, water or land).

Environmental Audit

Activities which may be conducted by a certified inspector to evaluate the storage tank system or storage tank facility site, equipment and records to determine evidence of an actual or possible release of regulated substance.

Evaporation Conversion of a liquid to vapor without necessarily reaching the boiling point

Facilities Physical equipment and/or plant, including large mobile equipment, involved in the performance of affiliate operations.

Gantry A framework on loading islands, under or besides which one or loading bays with articulated loading arms.

Gauging Device Device for the measurement of liquid level in a tank

Ground Monitoring Well

This is any cased excavation or opening into the ground made by digging, boring, drilling, driving, jetting or other methods for the purpose of determining the physical, chemical, biological, or radiological properties of groundwater.

Groundwater Water that is below the surface of the ground in the saturation zone, i.e. below the water table.

Hazard A potential source of serious harm to people, property or the environment.

Hazardous Material

Means any chemical, waste, gas, medicine, drug, plant, animal or microorganism which are likely to be injurious to human health or the environment

Hazardous waste This is waste is waste that is dangerous or potentially harmful to our health or the environment. Hazardous wastes can be liquids, solids, gases, or sludges.

Hazardous Area An area in which there exists or may exist an atmosphere containing flammable gas or vapor in a concentration capable of ignition

Hydrocarbon Chemical compounds containing carbon and hydrogen which are produced by the refining of crude oil and which are generally used as fuels.




Improvements Physical additions made during the lifetime of a facility or site.

Incident A specific event or extended condition that has a significant unwanted and unintended impact on the safety or health of people, on property, on the environment, or on legal/regulatory compliance.

In-service Inspection

A scheduled aboveground storage tank external inspection to determine tank system serviceability and compliance with requirements in applicable industry standards. This inspection shall be conducted in accordance with KS and API Standard. The tank system may be in operation during this inspection.

Inspection Activities

Activities to inspect all or a part of storage tank system or storage tank facility. These activities include, but are not limited to, evaluation of:

• Storage tank system structural integrity. • Construction and major modification. • Facility operation.

Install Activities to construct, reconstruct or erect to put into service a storage tank, a storage tank system or storage tank facility.

Kenya Standard Specification or Code of Practice declared by The Standards Council under Section 9 of the Standards Act

Landing Losses Emissions that occur from floating-roof tanks whenever the tank is drained to a level where its roof rests on its deck legs (or other supports).

Liquid Trap Sumps, well cellars and other traps used for the purpose of collecting oil, water and other liquids. The liquid traps may temporarily collect liquids for subsequent disposition.

Loading Arm/Hose

A piping arrangement for filling in a truck.

Loading Bay An inlet for trucks to stay under product loading.

Loading Facilities Facilities consist of pumping and filling installations.

Maintenance The normal operational upkeep to prevent a storage tank system or storage tank facility from releasing regulated substances if the activity involved is not a major modification or minor modification.

Major Modification An activity to upgrade, repair, refurbish or restore all or any part of an existing storage tank system or storage tank




facility which:

• Alters the design of that storage tank system or storage tank facility.

• May affect the integrity of that storage tank system or storage tank facility.

The term includes an activity directly affecting the tank portion of the storage tank system or an activity directly affecting an underground component of the storage tank system.

Management Site management is typically the most senior level of operations management working on site.

Managers Personnel with line management or supervisory responsibilities.

Minor Modification An activity to upgrade, repair, refurbish or restore all or part of an existing storage tank system or storage tank facility which does not alter the design of that storage tank system or storage tank facility, but, which may affect the integrity of that storage tank system or storage tank facility.

The term does not include an activity directly affecting the tank portion of the storage tank system or an activity directly affecting an underground component of the storage tank system.

Modify To conduct an activity that constitutes a major modification or a minor modification.

Monitoring System A system capable of detecting releases in connection with an aboveground or underground storage tank.

Occupational Health

Process encompassing all activities addressing workplace health hazards and employee health. It includes identification, evaluation, and control of health hazards; monitoring of worker exposures; communication of health hazards knowledge, determination of employees medical fitness to do their work and providing or arranging for medical services necessary for the treatment of occupational illnesses or injuries.

Operation Any activity involving the production, manufacture, use, storage or movement of material. Also, the utilization of resources by a “unit” to produce an output.

Operational Life The period beginning when installation of the tank system has commenced until the time the tank system is properly




closed.

Operator A person, who manages, supervises, alters, controls or has responsibility for the operation of a storage tank.

Out of Service A scheduled AST tank inspection that encompasses both internal and external examination to determine tank system serviceability and compliance with applicable industry standards. This inspection shall be conducted by a certified AST Inspector in accordance to API 653. The tank system may not be in operation

Overfill Protection Equipment that halts the transfer of product from a road tanker or pipeline to an AST/UST when the tank is full.

Pathway A route by which the contaminant can reach the receptor high pressure hand washes

Permanent Water Supply

A well, interconnection with a public water supply, extension of a public water supply, similar water supply or a treatment system, capable of restoring the water supply to the quantity and quality of the original unaffected water supply.

Permit Authorization granted to a person to enable the carrying out of any activity in the energy business, where a license is considered onerous

Petroleum "Petroleum" includes petroleum crude natural gas and any liquid or gas made from petroleum crude, natural gas, coal, schist, shale, peat or any other bituminous substance or from any product of petroleum crude, natural gas and includes condensate

Petroleum System A storage tank system that primarily contains petroleum, and may contain additives or other regulated substances. The term includes systems containing motor fuels, jet fuels, distillate fuel oils, residual fuel oils, lubricants, petroleum solvents and used oils.

Pipework A hollow cylinder or tubular conduit that is constructed of non earthen materials. The terms include the associated fittings such as unions, elbows, tees and flexible joints.

Pressure Vacuum Relief Valves

Pressure/Vacuum Relief Valves (Breather Valves). Direct acting Pressure/vacuum relief valves are special types of relief valves which are specifically designed for tank protection. The range includes pressure only, vacuum only and combined pressure/vacuum valves, all available with flanged outlets or vented to atmosphere.




Pressure / vacuum relief valves are used extensively on bulk storage tanks, including fixed roof tanks with floating covers, to minimize evaporation loss. The valves prevent the buildup of excessive pressure or vacuum which can unbalance the system or damage the storage vessel

Quality The ability for a product, service or activity to meet or exceed requirements.

Recommendations Potential solutions to findings or observations.

Recommissioning Recommissioning is essentially the same process as commissioning, but applies to existing facilities and provides a systematic approach for discovering and solving problems associated with facilities operation and maintenance procedures.

Release Spilling, leaking, emitting, discharging, escaping, leaching or disposing from a storage tank into surface waters and groundwaters or soils or subsurface soils in an amount equal to or greater than the reportable released quantity

Replacement In-kind

Replacement which is essentially identical to the original and satisfies all relevant standards and specifications.

Risk Risk is a function of the probability of an unwanted incident and the severity of its consequences

Risk Assessment The process by which a risk analysis is conducted and results used to make decisions, either through relative ranking of risk reduction strategies or through comparison with risk criteria or other standards of acceptability.

Sanitary Sewer A collection system for waste water

Safety Method Statement

An SMS can range from a simple statement to a detailed technical document depending on the scale of the task involved. The purpose of the SMS is to identify the hazards associated with each task and specify the necessary controls to them.

Site The place where something was, is or is to be located. May be a marketing location, a refinery, gas plant or offshore platform.

Source Substance capable of causing pollution or harm.

Spill Response Plan A written plan developed by the operator to respond to any spills at Vehicle Cleaning, Washing and Servicing facility at a site. As a minimum the plan shall define roles and responsibilities for spill response, contact names and numbers for appropriate agencies and a checklist for all spill




response equipment.

Standard Operating Procedures

Standard Operating Procedures are documented series of steps to be carried out in a logical order for a defined operation or in a given situation.

Standard A defined product or result. Includes requirements for quality, content, review and conformance with regulations.

Stormwater A pipe conduit, drain or other equipment or facilities for the collection and transmission of storm water or uncontaminated water.

Street Way, road, lane, square, court, alley, passage or open space, whether a thoroughfare or not, over which the public have a right of way, and also the roadway and footway over any public bridge, or causeway

Sustainable Drainage Systems

SUDS are a sequence of water management practices and facilities designed to drain surface water in a manner that will provide a more sustainable approach than what has been the conventional practice of routing run-off through a pipe to a watercourse.

Working Losses Emissions related to the movement of the liquid level in the tank. Working losses from fixed-roof tanks occur as vapors are displaced from the tank during tank filling and emptying.

Working losses from floating-roof tanks occur as the liquid level (and therefore the floating roof) is lowered, causing the liquid on the exposed tank walls and fittings to evaporate.



1. Introduction

1.1. These guidelines are intended to help those who design, construct, commission, decommission and recommission Bulk Petroleum Terminal, herein referred to as “terminal”.

1.2. They have been produced by the Energy Regulatory Commission (ERC) in consultation with key government agencies. Contact details can be found at the end of these guidelines.

2. Disclaimer

2.1. The information contained in the PPGs is not intended to be prescriptive, or to preclude the use of new developments, innovative solutions or alternative designs, materials, methods and procedures, so long as such alternatives provide a level of control over pollution appropriate to the risks identified.

2.2. The guidelines are provided for information and while every reasonable care has been taken to ensure the accuracy of its contents, the ERC cannot accept any responsibility for any action taken, or not taken, on the basis of this information.

3. Petroleum Terminals

3.1. Every terminal has the potential for releasing polluting agents into the air, soil and groundwater and/or surface water.

3.2. Possible causes for the release include:

a. Damaged foundation of AST

b. Leaks of aboveground and/or underground pipelines

c. Leaking or broken loading arms

d. Overfill when AST is receiving product

e. Overfill when delivery tankers are loaded at the terminal

f. Non fuel proof pavement of loading gantries

g. Lack of drainage and/or Oil/Water Separator at the terminal

h. General damage to fuel equipment and facilities

3.3. The PPGs provide straightforward guidance on good practices for the design, construction, commissioning, decommissioning and recomissioning of terminals, compliance with legal requirements and best practices using COPs and sound engineering practices.



4. Objective

4.1. The PPGs:

a. Provide technical information on terminals which receive, store and handle in ASTs.

b. Cover civil and mechanical installation issues for design, construction, commissioning, modification and decommissioning of terminals.

c. Provide information aimed at minimizing the risks to health and to the environment.

d. Describe good practice and certain legal requirements, particularly those applicable in new terminals and existing sites that are modified/refurbished.

4.2. The PPGs outline good practices which should be adopted by a terminal to prevent pollution during:

a. Design

b. Commissioning

c. Construction

d. Decommissioning

e. Recommissioning

4.3. For each of these stages, the PPGs highlight the potential risks to air, soil and groundwater and outline the types of good practices to be developed and followed.

5. Scope

5.1. The PPGs are relevant to terminals which store hydrocarbons in ASTs. They contain advice specifically aimed at the following persons:

a. Owners

b. Persons involved in design and construction

c. Persons involved in decommissioning and recommissioning

d. Persons responsible for abandonment

5.2. The persons responsible for complying with the guideline might not necessarily possess appropriate knowledge and expertise and are urged to consult relevant guidance or seek expert advice.



5.3. The PPGs do not:

a. Cover the detailed procedures for assessment of risk.

b. Provide information on operational procedures.

c. Cover all potential configurations/types of installations, some of which will have site-specific risks associated with them.

6. Availability

6.1. The PPGs are published by the ERC and can be accessed on ERC website.

7. Legal Framework

General

7.1. The Regulatory Framework and useful guidance and publications are given at the end of the guideline.

7.2. It is against the law to cause water pollution and there are specific regulations that apply to terminals handling hydrocarbons. Non compliance with these regulations is an offence and may result in enforcement action being taken against the terminal operator.

7.3. The law requires terminal operators to rehabilitate inadequate facilities to bring them to standard. The existing legal framework applies to terminals handling hydrocarbons in ASTs.

8. Permits and Licenses

8.1. All Terminals must obtain approvals from ERC, NEMA, DOSHS and County Governments.

8.2. All operating permit conditions must be followed.

8.3. ASTs must be included in the Spill Response Plan.

9. Using the PPGs

9.1. The PPGs apply to terminals, the degree and means of environmental protection will vary for each individual terminal.

9.2. In determining what is required for individual terminals, it is necessary to take into account the following:



a. Location and environmental setting of the terminal

b. Age of the terminal

c. Storage and throughput volumes of the terminal

d. Practical engineering options and control mechanisms

e. Likely costs and benefits of upgrading terminals.

9.3. Whilst the best practicable environmental options should be adopted, it is not expected that all terminals would meet or exceed the highest degree of engineering design or operational and management systems. However, all terminals are expected to meet the minimum industry standards for the selected degree of engineering.

10. Design

Risks

10.1. Whilst no loss of product can occur during the design and construction phases, failure to consider potential environmental risks of operations could ultimately result in a significant pollution incident.

Construction Standards for ASTs

10.2. Aboveground oil storage tanks must be constructed of steel and meet or exceed one of the following design and manufacturing standards:

a. The Kenya Standards KS1967, and KS 1938-Part 3

b. ASME Boilers and Pressure Vessels Code section 1 and 2

c. UL, Standard for Steel Aboveground Tanks for Flammable and Combustible Liquids, No. 142

d. API, Standard No. 650, Welded Steel Tanks for Oil Storage

e. API, Standard No. 620, Recommended Rules for Design and Construction of Large, Welded, Low-Pressure Storage Tanks

10.3. Leak Detection: Facilities must include a system of visual leak monitoring for tanks between the tank bottom and the impermeable containment as detailed in API Standard 650, Welded Steel Tanks for Oil Storage.

10.4. Corrosion Protection: All tanks must have a cathodic protection system for the portion of the tank in contact with the soil or backfill, in accordance with API Recommended Practice 651, API Standard 650, Welded Steel Tanks for Oil Storage and API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction or NACE Standard RP0169-1996 unless a cathodic protection assessment indicates that the corrosion rate will not



reduce the floor thickness below the minimum allowed in API 653 before the next required internal inspection date.

10.5. Painting: Tanks must be painted in accordance with recommended industry standards, such as the Steel Structures Painting Council publication Steel Structures Painting, Manual, Volume 1 Good Painting Practice.

10.6. Tanks on Earthen Base Pads: All tanks on a prepared earthen pad must include the following:

a. Construction of the base pad leak detection system must meet the standards of API Standard 650 Welded Steel Tanks for Oil Storage.

b. A release prevention barrier;

c. The support base must be constructed of compacted, clean, free-draining granular material such as sand, gravel, or crushed stone. The use of cinders and organic material are prohibited.

d. The support base must be constructed so as to provide for positive drainage of water away from the base;

e. The support base must be constructed so as to leave at least 30 centimeters above the general grade (dike floor) after ultimate settlement; and

f. The surface of the support base must be protected against erosion by good engineering practices.

10.7. Tank Spacing: New or relocated or reconstructed tanks must be separated in accordance with KS1967 or National Fire Protection Association 30..

10.8. Highway Curve Locations: Tanks located near a highway curve must be protected from vehicular collisions.

Storage of Hazardous Material

10.9. The contents being stored in ASTs must be compatible with the construction material of the AST.

10.10. AST will be constructed using appropriate industry standards

10.11. ASTs must have:

a. Facility sign posted

b. Product transfer area safeguards

c. Internal and/or external corrosion protection

d. Overfill protection

e. Label lines to identify connections



f. Underground piping safeguards, if utilized

10.12. Storage areas must be secured to prevent unauthorized entry and tampering with ASTs.

10.13. Tank areas must have access to emergency lighting sources in the event of power outage.

10.14. Storage facility must be equipped with spill response equipment.

10.15. ASTs and associated piping must be secondarily contained.

10.16. Storage facilities must be posted with specific filling and monitoring procedures.

Site Selection

10.17. Consider environmental and fire protection, access, maintenance and security requirements before proposing the location for new and reconstructed terminals.

10.18. ASTs must be separated in accordance with KS1967 or NFPA 30. Tanks used only for storing Class III B liquids (Flash point at or above 200o F) may be spaced no less than 3 feet apart unless within a diked area or a drainage path for a tank storing Class I or II liquid in which case the provisions of NFPA 30 apply.

10.19. ASTs must not be located within the following areas:

a. Within 900 metres of a surface water body intake used as a public drinking water supply;

b. Within 180 meters of an existing private drinking water supply, except a facility's own well;

c. Within 300 meters of a significant ground water spring; or

d. Within 300 meters of a residential area, park, preserve, or similar site when such site is so designated.

10.20. An oil terminal facility located other that set forth above is presumed to pose a serious threat to public health or welfare or to the environment unless the operator:

a. Operates the facility a unique way that allows for compliance through an alternative design, operation, or siting proposal which provides an equivalent level of protection as the siting provisions set forth above; or

b. The facility environment is unique in some way such that a valuable resource will not be negatively affected by the proposed siting.

10.21. The location should provide access for maintenance and deliveries to the tank (filling) including safe parking for oil tankers making deliveries.



Site Diagrams

10.22. All ASTs at the terminal must be shown on a site diagram which is permanently mounted in an area accessible to terminal operators, their employees and maintenance contractors.

10.23. The diagram must show the:

a. Tank numbers, location, contents and capacities for each AST

b. Location of piping and valves

c. Location of storm sewers, drainage ditches, catch basins, and adjacent water bodies to which a spill might travel

d. Location of the spill kit and available emergency response equipment

e. Terminal operator’s phone number

f. Electrical drawings should also be available

11. ASTs

11.1. ASTs, new or reconstructed, must have a stable foundation, capable of supporting the total weight of the tank when full of product without movement, rolling or unacceptable settling.

11.2. The foundation must minimize corrosion of the tank bottom and meet or exceed the specifications of the tank manufacturer. The foundation design and construction must be based on sound engineering practices.

11.3. Field constructed AST shall be hydrostatically tested as required in API 650. Deficiencies shall be remedied prior to AST being placed into service. Hydrostatic test fluids shall be discharged or disposed of in accordance with The Environmental Management and Coordination (Water quality) Regulations requirements.

11.4. Reconstruction of tanks must be accomplished in accordance with API 650. Reconstructed tanks must be inspected and hydrostatically tested before being placed into service. Hydrostatic test fluids shall be discharged or disposed of in accordance with The EMC (Water quality) Regulations requirements.

11.5. ASTs that are relocated to another service site must meet the performance requirements for ASTs and shall be tested according to API 650 and inspected to API 653 before being put back in service.

11.6. Factors that affect the choice of a new or replacement AST include:

a. Legal requirements

b. Minimum manufacturing standards



c. Intended application for AST

d. Type of oil to be stored

e. Secondary containment

f. Location of the tank

g. Safe filling and dispensing

h. Safe installation and routine maintenance

11.7. Other factors other than compliance with standards for construction and manufacture that could affect OSR include pipework, location and deliveries

11.8. ASTs should as a minimum:

a. Last at least 20 years, with proper maintenance

b. Be constructed of material that is suitable for the type of oil stored in accordance with ASTM A 282/A 283/285.

c. Be of sufficient strength and structural integrity to ensure that it will not burst or leak in ordinary use

d. Have isolating check valves that meet ASME B16.34.

11.9. For tanks in open bunds, it is recommended that a minimum distance of 750 mm is allowed between the tank and the bund wall and 600 mm between the tank and the base to allow access for external inspection and maintenance.

11.10. SCS (also known as bunds) is an area around a tank and its ancillary equipment designed to contain any loss of oil and to prevent it from escaping to the environment. It can be manufactured as part of an integrally bunded tank system or built on site ready for the tank to be put into it.

11.11. SCS must hold at least 110% of the volume of oil the tank is designed to contain. The extra 10% margin is intended to take into account a range of factors, including:

a. Loss of the total tank contents

b. Sudden tank failure or leaks

c. Overfilling

d. Containment of fire-fighting agents

e. Dynamic factors such as overtopping caused by surge and wave action following tank failure

f. Allowance for rainfall during an oil spill incident.

11.12. If the terminal has more than one AST, the SCS must be capable of storing 110% of the biggest tank’s capacity or 25% of the total capacity, whichever is the greater.



11.13. SCS must be impermeable to oil and water with no direct outlet :

a. Connecting it to drain, sewer or watercourse

b. Discharging onto a yard or unmade ground.

11.14. Pipework to fill or empty the AST should not pass through the SCS floor or walls (the bund). If this is unavoidable, the joint between pipe and bund should be sealed with a material that is resistant to both internal and external corrossion, so that the containment remains leak-proof.

11.15. Do not store other items in the SCS as this will reduce the volume available in the event of a spill and can cause a fire risk if it becomes soaked in oil.

11.16. ASTs should be fitted with independent high-high level alarm and SCS sensors that detect if oil has collected in the bund from an incorrect delivery, overfill or inner tank problem and to warn if additional maintenance is needed.

12. Pipework

12.1. The design of piping shall be suitable for expected working pressures, temperatures and structural stresses and comply with ASME/ANSI B31.3/31.4 and ASME A 53.

12.2. Any material used in the construction or installation of piping shall be suitable for the conditions of use, in particular:

a. It shall be compatible with petroleum products with which it will be in contact

b. It shall be resistant to heat to which it may be exposed

c. Where subject to corrosion, it shall be sufficiently resistant to ensure acceptable life.

12.3. Pipework has normally been constructed from steel and should have adequate protection against corrosion.

12.4. Pipework should be supported to remain secure

13. Hose Specifications

13.1. Standards for petroleum hoses should use the following standards: BS EN 1765:2004, BS EN 13765:2003, BS EN 1762:2003 or any latest such standard as may be applicable. Hoses are designated as follows:

a. Type A Rough bore externally armored hose principally for gravity discharge with a maximum working pressure of 3 bars.



b. Type AX Rough bore composite hose principally for gravity discharge with a maximum working pressure of 3 bars.

c. Type B Rough bore externally armored hose with a maximum working pressure of 7 bars.

d. Type BX Rough bore composite hose with a maximum working pressure of 7 bars.

e. Type C Smooth bore hose with smooth or corrugated exterior principally for gravity discharge with a maximum working pressure of 3 bars.

f. Type D Smooth bore hose with smooth or corrugated exterior with a maximum working pressure of 7 bars.

g. Type E Smooth bore reeling hose with a maximum working pressure of 7 bars.

h. Type F Smooth bore reeling hose of controlled dilation for metered delivery with a maximum working pressure of 7 bars.

13.2. Types A, AX, B and BX are divided into the following two classes:

a. Class 1 for aviation and other uses

b. Class 2 for non-aviation use.

14. Loading Facility

14.1. The loading and unloading facilities vary with the size and complexity of the terminal and the locations. Because of seasonal and other variations and product distribution, loading facilities shall be quite flexible and its capacity may far exceed normal plant production.

14.2. When new facilities are planned it is recommended that the simplest facilities that will efficiently perform loading operations be constructed. These requirements can also be used for the modernization and/or extension of existing loading facilities for road tankers.

14.3. Specifying the yearly average loading capacity, the size of tanker and loading assembly may be fixed and pump capacity will be calculated.

14.4. It should be noted that in case there is freedom in tanker size and/or loading assembly then economical evaluation shall be considered for such selections.

14.5. Loading and unloading facilities shall integrate constructive measures for the protection of the environment, particularly in respect of avoidance/containment of spillages.



14.6. At the design stage, the loading and/or unloading system should be reviewed to allow for the installation of a vapor collection system return line for poisonous, hazardous and high vapor pressure products.

14.7. It is essential to minimize the generation and emission of vapors during loading by eliminating the free fall of volatile products and reducing jetting and splashing by filling with closed vapor systems:

a. Majority of loading facilities in service are top loading, the best solution is to replace (or modify) the existing loading arms so that when volatile products are loaded, the manhole is sealed and vapors are diverted into a vapor return system. The latter may be either integral with the loading arm or a vapor manifold on the vehicle connected to all the tank compartments.

b. Bulk vehicles equipped for bottom loading require a pipe connection from the vapor emission vent of each compartment into a vapor recovery manifold, which should terminate in a position which is easily accessible from ground level for use at either the loading bay or retail outlets as required. The coupling connections for liquid and vapor must be different types.

14.8. Apart from installing a full vapor recovery system, considerable reduction in vapor emissions can be achieved by avoiding free fall and splashing of volatile products in top and bottom filling operations:

a. For top loading, the loading arms should be designed to reach the end compartments of a vehicle tank in such a manner that the down pipe can penetrate vertically to the bottom of the compartment.

b. For bottom loading, it may be necessary to fit deflectors in the vehicle tank at the point of entry of the product into the compartment.

c. These measures have the following advantages:

i. Minimizing the hazard of static electricity

ii. Minimizing the amount of vapor formation

iii. Reducing product losses

iv. Reducing the fire risk: the concentration of vapor emanating from the compartments will be dissipated faster to below the explosive limit.

14.9. The main items to be considered at the loading/unloading facilities are provision of:

a. Emergency shut-off valve to prevent or reduce spillage due to overfilling, hose failure, etc.

b. Emergency push-button switch to stop the pumps, activate an alarm, and close all flow control and block valves on the loading gantry

c. Adequate drainage and interception arrangements.



14.10. The first criterion for selection of loading system is the volatility characteristics of the product. If RVP of the product at 38°C is higher than 0.55 bar then bottom loading shall be used.

14.11. The second aspect is the requirements to restrict emissions from a specific product which dictates to use bottom loading.

14.12. The relative merits of top and bottom loading system are summarized in the Table below:

RELATIVE MERITS OF TOP AND BOTTOM LOADING

BOTTOM LOADING SAFETY FEATURES TOP LOADING

Worksite Ground level

On platform. Can be made safe by provision of guard rails and access ramps to vehicles, but at extra cost.

Vapor emissions (no vapor

recovery)

Closed manhole covers gives rise to small pressure build-up to operate the vents resulting in marginally less vapor emission.

Open manhole covers therefore slightly greater vapor emission.

Control of product flow

assuming meter preset does not work

Reliance on overspill protection equipment.

Positive visual control by loader assuming ‘hold-open' valve is correctly used.

Two-arm loading requires overspill protection when the conditions are the same as for bottom loading.

Product handling equipment

Arms and particularly hoses filled with product are heavier to handle. Generally, hose diameters should be limited to DN 80 (3 inches).

Care is needed to ensure that the down-pipe of loading arm is correctly positioned in each compartment. DN 100 and DN 150 (2 and 6 inches) diameter counter-balanced arms are easily handled.

Electrostatic precautions Flow rates restricted to 75% of that for equivalent top loading system.

Vapor recovery (loading bay)

Vehicles must be fitted with a vapor recovery manifold connecting each compartment; of sufficient capacity to cope with simultaneous loading of 2, 3 or 4 compartments.

Preparation for loading (normal)

Preparation for loading

(vapor return)

Loading arrangement

Product flow rates

Vehicles already equipped with vapor return manifold for use when loading.

Removal of caps and connecting couplings is contained within small operating envelope. (No significant difference between

Each product loading arm must be fitted with a vapor sealing head so that vapors are diverted into a vapor recovery system; either (a) on loading arm, or (b) manifold provided for gasoline deliveries to retail outlets. Care must be taken to position collar seal in fill





systems.)

Vehicles must be fitted with a vapor recovery manifold connecting each compartment; of sufficient capacity to cope with simultaneous loading of 2, 3 or 4 compartments.

Vehicles already equipped with vapor return manifold for use when loading.

Removal of caps and connecting couplings is contained within small operating envelope. (No significant difference between systems.)

Additional coupling connection to vapor manifold. (No significant difference between systems.)

Simultaneous loading of 2 or more compartments more easily arranged.

25% slower per compartment than equivalent top handling system

Simultaneous loading of 2 or more compartments more easily arranged.

25% slower per compartment than equivalent top handling system because of electrostatic hazard in certain filling operations.

opening. Liquid level sensing equipment must be fitted on loading arms or in each vehicle tank compartment.

Vehicles must be fitted with vapor return manifold.

Greater area of operation because of positioning of manhole covers.

(No significant difference between systems.)

Care must be taken to position arm/vapor head in fill opening.

(No significant difference between systems.)

Capital costs 25% slower per compartment than equivalent top handling system because of electrostatic hazard in certain filling operations.

1. Approximately 17% more loading space is required than that of an equivalent top-loading gantry. Additional cost for greater roof area.

2. i) All vehicle compartments must be fitted with loading dry-break couplings.

Additional structure and safety equipment for working platform.





ii) To minimize over-filling risk, vehicles must be fitted with liquid level sensing equipment.

iii) Deflectors must be fitted to foot valves to minimize jetting and turbulence.

iv) Additional product handling equipment on islands. Depending upon by group's requirements, this may be about 30-50% more.

Maintenance Costs The additional equipment above will require to be maintained/replaced

Maintenance of working platform and safety features.

Vehicle accommodation

Compatibility with competitors and Contractors vehicles Compartment outlets full or empty Sophistication

Out-of-service time of vehicles for maintenance may be increased.

Can more easily accept range of vehicle capacities and heights (present and future).

All vehicles likely to use loading bays must be fitted with suitable equipment.

Industry agreement to adopt similar practices should be encouraged.

Possible need to persuade authorities to change law to permit outlet pipes filled with product, otherwise drainage must be arranged with consequent measurement and operational problems.

Less flexible operation. Increased maintenance.

Need for greater control of maintenance

Less flexible than bottom loading arrangement.

More flexible.

No problem.

More flexible operation.

14.13. Areas susceptible to contamination at the Loading Gantry should be impermeable to hydrocarbons and should not allow seepage through or below the surface.



14.14. Impervious surfaces are structure such as pavements (roads, sidewalks, driveways and parking lots) that are covered by impenetrable materials such as asphalt, concrete, brick, and stone.

14.15. Impermeable surfaces prevent air/liquids to pass or diffuse through.

14.16. Control of product flow by volume requires preset quantity device which will be first line of control. A first line of control is an inbuilt mechanism that stops the flow of product beyond the pre-set quantity.

14.17. In the event of any emergency the second line of control is necessary. The second line of control is independent of the device and is activated in the event of failure and/or malfunction of the first line of control:

a. The fitting of a deadman control in the form of a hold open valve enables the operative when filling through a manhole to watch the level of product and to stop the flow in emergency.

b. Liquid level control provides an alternative secondary positive means of stopping the flow of product in emergencies

c. For bottom loading the use of an overfill protection device based on liquid level detection is essential. The liquid level control device is linked to an interlock which covers bonding of the vehicle and access to product by means of controls on the loading arm.

d. In automated systems interlock systems are used whereby product will not flow until the vehicle is adequately bonded and the loading arm is in the correct position.

14.18. Pressure gages shall be located in a sufficient number of places in the liquid and vapor lines to allow the operator to have a constant check on operating pressure, differentials and so forth to ensure safe operation.

14.19. Emergency shut-off valves may incorporate all or any of the following means of closing:

a. Automatic shut-off through thermal (fire) actuation. (When fusible elements are used they shall have a melting point not exceeding 120°C.

b. Manual shut-off from a remote location.

c. Manual shut-off at the installed location.

14.20. Installation practices for emergency shut-off valves shall include the following considerations:

a. Emergency shut-off valves shall be installed in the transfer line where hose or swivel piping is connected to the fixed piping of the system. Where the flow is only in one direction, a back-flow check valve may be used in place of an emergency shut-off valve if it is installed in the fixed piping downstream of the hose or swivel piping.

b. Emergency shut-off valves shall be installed so that the temperature sensitive element in the thermally actuated shut-off system is not more

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than 1.5 meters in an unobstructed direct line from the nearest end of the hose or swivel-type piping connected to the line in which the valve is installed in line with IP Electrical Safety Code; Model Code of Safe Practice. – Part 1

c. The emergency shut-off valves and/ or breakaway coupling shall be installed in the plant piping so that any break resulting from a pull will occur on the hose or swivel piping side of the connection while retaining intact the valves and piping on the plant side of the connection. This may be accomplished by the use of concrete bulkheads or equivalent anchorage or by the use of a weakness or shear fitting.

14.21. When liquid meters are used in determining the volume of liquid being transferred from one container to another, or to or from a pipeline, such and accessory equipment shall be installed in accordance with the procedures stipulated by the API "Manual of Petroleum Measurement Standards" and Recommended Practice 550.

14.22. Hoses and arms for transfer shall be suitable for the temperature and pressure conditions encountered. Hoses shall be provided for the service and shall be designed for a bursting pressure of not less than five times the working pressure in line with EN 13765 and AS 2117. The hose working pressure shall be considered as the greater of the maximum pump discharge pressure or the relief valve setting.

14.23. Provisions shall be made for adequately supporting the loading hose and arm.

14.24. Flexible pipe connections shall be capable of withstanding a test pressure of one and one-half times the design pressure for that part of the system in accordance with UL 971 – Test requirements for Flexible Pipe.

15. Drainage Systems

15.1. Drainage systems should be designed such that surface spillages are contained and there is no direct loss to ground or to surface watercourses or soakaways for surface water drainage. This involves the use of low permeability surfacing in areas which could be contaminated with product.

15.2. Types of low permeability surfacing include:

a. Porous Asphalt

b. Porous Concrete.

c. Plastic Grid Systems

d. Block Paving.



15.3. All surface water run-off and spillages should pass through an OWS.

15.4. The drainage system including hardstanding and drainage pipework should also be constructed of materials, which are resistant to attack by hydrocarbons.

15.5. The drainage pipework should be sized in accordance with BS 5911 or any other approved by the national standards body to suit the storm return requirements to the location and capable of transporting a spillage from the tanker standing area at the rate of at least 15 Litres per second.

15.6. All roof drains which collect clean, uncontaminated water should be routed to bypass the Oil/Water Separator to avoid reducing the capacity of the unit to contain spills.

16. Corrosion Prevention

General Requirements

16.1. All ASTs must have a cathodic protection system for the portion of the tank in contact with the soil or backfill, in accordance with API Recommended Practice 651, API Standard 650, Welded Steel Tanks for Oil Storage and API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction or NACE Standard RP0169-1996 unless a cathodic protection assessment indicates that the corrosion rate will not reduce the floor thickness below the minimum allowed in API 653 before the next required internal inspection date.

16.2. The tank system shall be maintained with corrosion and deterioration prevention measures Existing tank bottoms that do not meet the standards shall be upgraded when the tank bottom is replaced.

Cathodic Protection

16.3. The cathodic protection system on new, reconstructed or relocated tanks or the replacement of the tank bottom shall consist of one or more of the following:

a. Sacrificial anodes and dielectrical coating.

b. Impressed current.

16.4. Another method specified in an appropriate recognized association code of practice such as API 651.

16.5. Cathodic protection systems shall be designed by a corrosion expert and maintained to provide protection against external corrosion for the operational life of the tank system.



16.6. Each cathodic protection system shall have an access point which enables the owner or operator to check on the adequacy of cathodic protection.

16.7. A monthly inspection must be performed on the impressed current cathodic protection system.

16.8. An annual structure - soil and structure - structure potential test must be performed by a cathodic protection tester for impressed current systems as well as annual structure to soil potentials for galvanic systems. Rectifier voltage and current readings must be in the range specified by the manufacturer or installer of the system. All readings and repairs must be documented.

Exterior Coatings

16.9. The exterior surfaces of ASTs and piping shall be protected by a suitable coating which prevents corrosion and deterioration. The coating system shall be maintained throughout the entire operational life of the tank.

Interior Linings and Coatings

16.10. Coating or lining systems may be used to protect tank interiors from corrosion.

16.11. An AST's structure is subject to forces such as expansion and contraction caused by changes in air temperature, sun heating, sudden introduction of new product at different temperatures and wind deflection.

16.12. Traditional thin mil systems like an epoxy coating do not have flex modulus or elongation characteristics capable of moving with the tank wall. This can lead to point disbondment from the substrate. Once this has begun, the blistering and flaking cycle of the coating begins.

16.13. Oxidation of the tank wall material develops behind the disbonded areas of coating, and then migrates to adjoining areas. Lining systems with a high temperature, high pressure spray up application that bonds to steel or concrete should be used.

16.14. The coating or lining system shall be designed in accordance with current codes of practices such as API 652.

16.15. Any appropriate coating which is bonded firmly to the interior surfaces may be used to protect a tank from corrosion.

16.16. Specific requirements are as follows:

a. Coatings and linings shall be chemically compatible with the substance to be stored.

b. Coating material shall be applied and cured in strict accordance with manufacturer’s specifications.



c. Surfaces shall be prepared and inspected in accordance with API 652.

d. Coatings used to protect the bottom of a tank shall extend up the side of the tank a minimum of tank bottom shell, while some forms of lining may cover the entire tank interior.

e. Coatings shall be examined for blisters and air pockets, and tested for pinholes. The coating thickness shall be checked to assure compliance with manufacturer’s specifications.

f. Defects in coating or lining systems shall be repaired or corrected prior to putting the tank or system into service.

g. Interior linings or coatings shall be inspected by a certified inspector or AST inspector at installation, when undergoing a major modification, and at least every 10 years or as warranted or recommended by the manufacturer or design engineer.

17. Overfill Requirements

17.1. Owner/operator shall ensure that releases from overfills do not occur.

17.2. Transfer of stored substance may not exceed the volume available in the receiving tank and the transfer shall be adequately monitored.

17.3. Immediate action shall be taken to stop the flow of regulated substance prior to exceeding tank capacity or in the event that an equipment failure occurs.

17.4. ASTs should have overfill protection consistent with API 2350, NFPA 30 or PEI RP 200.

17.5. There are several options for meeting this requirement. A tank can have a:

a. High-level alarm that can be seen or heard by the person controlling the transfer, set at no greater than 95% of the tank capacity

b. System that automatically shuts off substance flow into the tank, set at no greater than 95% of capacity

c. Level gauge monitored during the transfer by the person controlling the transfer or by someone in contact with the person controlling the transfer

17.6. An existing tank system which is taken out of service to perform a scheduled out-of-service inspection or a major modification to the tank shall be upgraded with a high-level alarm with a cut-off device or a high-level alarm with a manned operator shutdown procedure prior to being put back in service.



18. Construction

General

18.1. Loss of product could arise during the operation as a result of inadequate construction methods and/or equipment installation.

18.2. Factors during construction that influence the future integrity of the operational terminal:

a. Tank and pipework handling

b. Ground preparation

c. Installation procedures

d. Incorrect site layout and set-up

e. Supervision and quality control

f. Commissioning procedures

18.3. Construction should be undertaken by suitably experienced contractors who are duly licensed for their class of works by the National Construction Authority (NCA).

18.4. The quality of all materials and equipment should be checked prior to installation or use and strict quality assurance maintained during construction.

18.5. Rigorous inspection and checking of a completed storage system is vital.

Material

18.6. The erection contractor shall inspect and keep stock of all materials delivered at the terminal and be fully responsible for their safekeeping.

18.7. All fittings, valves, plates, etc. Shall be properly laid out on wooden supports, clear of the soil. Special care shall be taken that damage does not occur to joint faces of valves and flanges or to beveled ends of fittings.

18.8. All materials shall be examined and repaired as necessary at the terminal before being erected, to ensure that any damage incurred in transit is made good to the satisfaction of the owner’s representative. Particular attention shall be paid to the avoid of buckles and distortions in plates.

18.9. Welding electrodes shall be stored in their original pockets or cartons in a dry place adequately protected from weather effects. Hydrogen controlled electrodes shall be stored and baked in accordance with the electrode manufacturer’s recommendations.



Foundation

18.10. Foundations for tanks will be constructed to the specified levels, profiles and tolerances.

18.11. For AST, to have a shell which is truly circular and free from buckles and flat spots, the foundation shall remain level as the tank shell is erected. For this reason the foundation shall be checked, not only at the commencement of operations, but several times during the various stages of tank erection. The measurements shall be stated in a report. This final report shall be handed to the owner for maintenance purposes.

18.12. Whichever type of construction is chosen, the surface immediately under the shell plates shall be laid so that the difference from a mean level does not exceed plus or minus 6 mm in 10 m and plus or minus 12 mm between any two points around the periphery as per API 650. Close tolerances in the tank foundation peripheral levels are particularly necessary for floating roof tanks.

18.13. Uneven foundation and settlement can result in the shell assuming an oval shape at the top, causing the floating roof to stick.

18.14. An indication that the tank is settling unevenly is the appearance of gaps in the circumferential seams, and departure of the shell from the perpendicular. If these signs appear, no attempt should be made to close the gap by pulling with the key plates and wedges or cutting of plates.

18.15. The tank level should be checked and corrected by leveling, if necessary. If the gap is due to inaccurate fabrication, plate edges should to the amount approved by the company or his representative be built up with weld metal, and the joint welded.

18.16. Pulling the plates to close the gap will cause deformations of the tank shell. To obtain a perpendicular and circular shell, a level tank foundation is essential.

18.17. If tank foundations are finished off with a sand bitumen mix as a water proof seal coat, steel plates should be placed temporarily across the edge of the tank foundation, in order to protect it whilst the bottom plates are being dragged into position.

18.18. Include tell-tale pipe as part of the tank bottom leak detection system.

Installation

18.19. Site erection of atmospheric above ground welded storage tanks shall be in accordance with Section 5 of API Standard 650



19. Erection Methods

General

19.1. ASTs should be installed by a suitably-qualified tank installer who will ensure that ASTs are installed according to API 650, API 2000 and BS 2654.

19.2. Maintain information of AST from the manufacturers and installers. Leave all the markings on the AST (tank manufacturer, make, model and capacity markings) intact.

Progressive Assembly

19.3. In the progressive assembly method, the bottom plates are assembled and welded first. Thereafter the shell plates are erected, held in place, tacked and completely welded.

19.4. This shall be done course by course, working upwards to the top curb angle.

19.5. No course shall be added as long as the previous course has not been entirely welded. The erection and completion of the roof framing and roof plates then follow.

Complete Assembly – Welding Horizontal Seams

19.6. In the complete assembly method, the bottom plates are assembled and welded first. Thereafter the shell plates are erected, held in place, tacked and only the vertical seams completely welded, leaving the horizontal seams unwelded. This shall be done course by course, working upwards to the top curb angle. No course shall be added as long as the vertical seams of the previous course have not been entirely welded.

19.7. The erection and completion of the roof framing and roof plates then follow.

19.8. Finally the horizontal seams are welded working upwards from the bottom course or downwards from the top curb angle.

Jacking Up

19.9. Some contractors employ a system of erection in which the bottom plates are completed. The top course is erected on the bottom plates, the roof framing and sheeting are completed and a number of jacks are then assembled around the structure.



19.10. By means of these jacks the completed top course together with the roof framing and sheeting is lifted to a height sufficient to insert the next lower course. The jacking method and the supporting of the partly erected shell shall have no adverse effect on the roundness of the shell.

19.11. The welding is completed at each stage of lift until all courses of the shell plates have been inserted and the finished height is reached.

19.12. The final operation is the welding of the bottom course to the bottom plates.

Floatation

19.13. The floatation method is used for floating roof tanks. After the completion of the bottom plating and erection and welding of the two lower courses of the tank, the floating roof is assembled on the tank bottom and completed.

19.14. The tank is then filled with water and, using the floating roof as a working platform, the third and subsequent courses are erected and welded, water being pumped in as each course is completed.

19.15. This method may only be used at locations where soil settlement is very limited and with the written agreement of the owner. The predicted soil settlements of the soil investigation report shall be taken into account.

19.16. A small crane is usually erected on the floating roof, hoisting the shell plates into position.

Prefabrication

19.17. For a hazardous location and/or close to existing tanks already storing light products, tanks can be prefabricated and moved to their permanent site, either by:

a. Prefabrication of the tank in the workshop. The maximum dimensions depend on the possibilities and limitations with respect to transport and is limited to tanks with diameters up to 12 meters.

b. Prefabrication of the tank, on a temporary foundation at a safe location nearby. The complete tank is then moved to its permanent foundation, e.g. by crane, on rollers or by air cushion.

c. The water test shall be carried out when the tank is standing on its permanent foundation.



Construction of Bottom Plate

19.18. Bottom plating shall be in accordance with the storage tank constructional drawing. Attention shall be paid to erection marks made on bottom plates according to a marking diagram which is supplied by the tank plate fabricator for the use of tank erector.

19.19. Manual gas cutting may be used for trimming the corners of bottom or roof plates where two lapped joints intersect and for cutting openings for fittings positioned on site.

19.20. Unless otherwise specified, after the bottom plates are laid out and tacked, they shall be joined by welding the joints in a sequence that the erector has found to result in the least distortion from shrinkage and thus to provide as nearly as possible a plane surface.

19.21. Welding of the shell to the bottom shall be practically completed before the start of the completion of welding of bottom joints that may have been left open to compensate for shrinkage of any welds previously made.

Secondary Containment

19.22. For tanks in constructed secondary containment, the bund should be built using reinforced materials, with no damp-proof course and rendered impermeable to oil.

19.23. The bund should be designed to reduce the risk of oil escaping beyond the containment area if the AST developed a hole (known as jetting):

a. Locate the AST as low as possible within the bund

b. Increase the height of the bund walls

c. Leave space between the AST and bund walls

19.24. A constructed bund should also have a sump fitted into the base for removal of rainwater for safe and legal disposal

Welding

19.25. All welding, including repair, tack and attachment welding, shall be carried out according to Sub-section 5.2 of API Standard 650 and the following supplementary requirements.

19.26. All welding of tank plates, steel framing, structural attachments and mountings done in the field shall be carried out by qualified welders or welding operators.

19.27. The erection contractor shall weld test plates using procedures that are suitable for making welds which conform to the specified requirements.



19.28. The sequence employed for tack welding and welding the bottom, shell and roof plates shall be such that the distortion due to welding shrinkage is minimized.

19.29. Tack welds used in the assembly of the vertical joints of tank shells and horizontal joints to be manually welded shall be removed and shall not remain in the finished joint.

19.30. Tack welds in the bottom, shell-to-bottom, roof and automatically welded horizontal joints of the tank shell and other joints, need not be removed provided they are sound and the subsequent weld runs are thoroughly fused into the tack welds.

19.31. Each run of weld metal shall be cleaned of slag and other deposits before the next run is applied. Slag shall also be removed from finished welds before inspection. Where air-arc gouging is used, the surfaces shall be chipped or ground back to bright metal before welding.

19.32. Peening of butt welds shall not be carried out except to the extent necessary to clean the weld.

19.33. No restraint of bottom plates by weights during welding is permitted.

19.34. In vertical joints in shell plates exceeding 13 mm thick all, but the root, runs shall be welded by the ’upwards’ technique. Root runs by either the ’upwards’ technique or by vertical-down welding in such plates over 13 mm shall be permitted but, in the latter case, the weld metal shall be completely removed by gouging or other suitable means to sound clean metal, before welding on the reverse side.

Tolerances

Shell

19.35. All construction tolerances for the AST shell shall be in accordance with API 650, API 2000 and BS 2654.

19.36. Plates to be joined by butt welding shall be matched accurately and retained in position during the welding operation.

19.37. Local departures from the design form for the shell horizontally and vertically should not exceed the defined tolerances when measured over a gage length of 2.5 m remote from weld seams

19.38. Deviation both inside and outside the tank of shell plate vertical joints from a true circle generated by tank radius, over a 1 m horizontal span centered on the weld, (peaking) shall be within 10 mm.

19.39. Deviation both inside and outside the tank of horizontal joints over a 1 m vertical span centered on the weld, from a vertical line (banding) shall be within 10 mm.



19.40. The tank shell shall be carefully checked for circularity, dimensions and level before the roof members (fixed roof tank) or the primary wind girder (floating roof tank) are erected.

Floating Roof

19.41. The variations in the gap between the shell and the periphery of the roof on completion of erection of roof shall not exceed ±13 mm from the nominal gap.

19.42. At any elevation of the roof other than that at which it was erected, this difference in gap shall not exceed 50 mm unless some other value has been agreed for a particular seal design.

Inspection

19.43. The inspector shall at all times have free access to all parts of the site while the work covered by the contract is in progress. The tank erection contractor shall afford him all reasonable facilities for ensuring that the work is being carried out in accordance with the requirements of this specification.

19.44. All welding shall be subjected to close visual inspection by competent welding inspectors of the contractor as the welding progresses, and any faults or bad practices shall be corrected as soon as possible.

19.45. Particular attention shall be paid to the vertical and horizontal joints in the shell plates, butt joints in bottom annular plates and other joints that pass under the shell plates.

20. Modifications

20.1. Modifications shall be performed in accordance with a professional engineer’s design requirements.

20.2. AST which are modified shall be inspected and tested according to API 650 before being put in service when a major modification has been performed on the tank shell, tank roof or tank bottom. Deficiencies shall be remedied before being returned to service.



21. Ancillary Equipment

General

21.1. Ancillary equipment shall be in good working order and maintained according to manufacturer’s specifications and API 2610. Ancillary equipment shall be compatible with the stored substance.

21.2. Ancillary equipment must be within the secondary containment system so any discharges of oil are retained.

Pipework

21.3. Piping shall be compatible with the substance stored and properly designed to resist internal and external wear, vibration and shock.

21.4. New and replacement piping shall be designed, fabricated and tested in accordance with current codes of practice.

21.5. Installation of piping shall meet or exceed current codes of practice and be in strict accordance with manufacturer’s specifications. Supporting and fixing shall be secure and the piping shall be not unduly exposed to mechanical damage.

21.6. Piping shall be tested for tightness before being placed in service and all deficiencies remedied.

21.7. Piping shall be tested and inspected in accordance with ASME/ANSI B31.3 - Chemical Plant and Petroleum Refinery Piping and ASME/ANSI B31.4Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia and Alcohols.

21.8. The layout shall take into account the needs for all operating access and shall ensure that any access way is not impeded.

21.9. The number of joints should be kept to a minimum.

21.10. Provision shall be made wherever necessary, for the expansion or contraction of the piping and its contents

21.11. Any buried piping shall be protected from superimposed loads, ground settlement etc.

21.12. Piping shall be painted and/or marked in a manner sufficient to permit ready identification of its contents.

21.13. Underground piping should be avoided where possible as they cannot be easily checked for damage or leaks and have a greater risk of causing pollution.



21.14. Underground piping should only be used when you cannot fit pipes above ground and should:

a. Be within coated to prevent corrosion or routed through ducting

b. Have as few joints as possible

c. Be marked clearly on site plans and when possible on the ground.

21.15. Underground pipework must also be protected against corrosion and from physical damage like that caused by excessive surface loading, ground movement or ground disturbance.

21.16. If mechanical joints are used, they must be readily accessible for inspection under a hatch or cover.

21.17. The terminal should have adequate facilities for detecting leaks from underground pipework. If a continuous leak detection device is installed, it should be maintained and tested regularly. Keep a record of the test results and any maintenance work completed.

21.18. If the site has no continuous leak detection system installed, the operator must test:

a. Pipework before use

b. Pipework with mechanical joints every five years in accordance with API 2610 Design, Construction, Operation, Maintenance, and Inspection of Terminal and Tank Facilities.

c. All other pipe work at least every ten years.

Vents

21.19. This allows oil vapor and air to escape from the tank when it is being filled and allows air in when fuel is being drawn off.

21.20. The size of the vent shall be such that pressure or vacuums resulting from filling, emptying or atmospheric temperature change, will not cause stresses in excess of the maximum design stress for the tank

21.21. Vent pipes must be arranged so that any discharge is directed vertically downwards into the bund.

21.22. The tank must be fitted with an automatic overfill protection device (which may include an alarm sounding device) if the filling operation is controlled from a place where it is not reasonably practical to observe the tank or any vent pipe.

Fill Point

21.23. The fill point is where the tanker delivery pipework connects to fill the tank.



21.24. There are different arrangements depending on tank type, size and location.

21.25. Coupling - If the AST fill point has a serviceable screw fitting or other fixed coupling, it must be used when filling the tank. The fill point should have a lockable fill cap with a chain and be marked clearly with the product type, tank capacity and, where appropriate, tank number. The cap should be replaced to the pipe after each delivery to protect it from damage and unauthorized use.

21.26. Position – the fill point should be at the tank and within the secondary containment system or in a suitable cabinet with a drip tray to catch any oil spilled during deliveries. Where the fill point is outside the secondary containment system, a drip tray must be used to catch any oil spilled during deliveries.

21.27. Fill point drip trays should be:

a. Any container that is specifically designed or manufactured to capture dripping product. It must be strong enough, made of oil resistant material and, ideally, have handles for lifting, emptying and cleaning.

b. Clean, free from water and other debris before each use

c. Large enough to hold all the oil that could be lost when the fill point shut off valve has been closed and the delivery hose is disconnected

d. Able to be moved without risk of spilling the oil and capable to hold least 3 litres

e. Checked after each delivery and if necessary safely emptied before being put away

f. Kept safely where it cannot collect rain water when not in use

g. Provided with earthing.

21.28. Provide separate fill pipes for each tank. Each fill pipe should have its own fill point shut off valve, and be marked with its corresponding tank/compartment number, volume and type of oil.

21.29. Flexible delivery pipes should only be used where there may be needed to move the end delivery point, for example when fuelling vehicles.

21.30. Fit the pipe with a tap or valve at the delivery end, which closes automatically when not in use. Where the pipe is not fitted with an automatic shut-off device, it must not be possible to fix the tap or valve in the open position. The pipe must either: • have a lockable valve where it leaves the tank which is locked when not in use and be kept in the secondary containment; or must be in an enclosed secure cabinet which is locked shut when not in use and has a drip tray.

21.31. Tanks shall be appropriately vented to protect the tank from over pressurization and excessive vacuums.



21.32. Vents shall meet or exceed the appropriate codes of practice developed by API. Normal venting shall allow the tank to breath when transferring the stored product. Emergency venting shall ensure that the safe pressure for the tank is not exceeded.

21.33. Tank connections through which regulated substance can flow shall be equipped with an operating valve adjacent to the tank to control flow of substance.

21.34. Valves shall be installed to meet or exceed current codes of practice and jurisdictional requirements. Valves shall be designed, installed and maintained according to ASME B16.34 - Valves, Flanged, Threaded and Welding End and API 600 Steel Gate Valves Flanged and Butt Welding Ends.

22. Release Prevention and Leak Detection

Overfill Protection

22.1. Tanks must be installed with the following:

a. A gauge or monitoring device which accurately indicates the level or volume in the tank and is visible to the individual responsible for the transfer of product.

b. The monitoring device shall be installed, calibrated and maintained in accordance with manufacturer’s specifications.

c. A high-level alarm with an automatic high-level cut-off device or a high-level alarm with a manned operator shutdown procedure in operation.

22.2. An existing tank system which is taken out of service to perform a scheduled out-of-service inspection or a major modification to the tank shall be upgraded with a high-level alarm with a cut-off device or a high-level alarm with a manned operator shutdown procedure prior to being put back in service.

Secondary Containment

22.3. Permeability of clay or existing soil RPB's (Reactive Permeable Barriers) must be determined by a professional engineer or certified geologist using a method capable of testing both horizontal and vertical permeability.

22.4. ASTM D 2434 covers the determination of the coefficient of permeability by a constant-head method for the laminar flow of water through granular soils.



22.5. The procedure is to establish representative values of the coefficient of permeability of granular soils that may occur in natural deposits as placed in embankments, or when used as base courses under pavements.

22.6. Containment structures must be compatible with the substance stored and minimize deterioration to the storage tank system.

22.7. Containment areas shall be designed, maintained and constructed in accordance with sound engineering practices adhering to recognized codes of practice such as NFPA, NACE, ACI or API and in compliance with KEBS requirements.

22.8. Secondary containment under the tank bottom and around underground piping must be designed to direct any release to a monitoring point to meet leak detection requirements.

22.9. Secondary containment shall be provided on a new tank at installation, and shall be provided on an existing tank at reconstruction or relocation of the tank or when the tank floor is replaced in accordance with API 650 Appendix I).

22.10. Permeability of the secondary containment must be less than 1 x 10-7 cm/sec at anticipated hydrostatic head and shall be verified at the time of installation.

22.11. ASTs must have emergency containment structures, such as dike fields, curbing and containment collection systems, which contain releases from overfills, leaks and spills.

22.12. Permeability of newly installed or replacement emergency containment structures must be less than 1 x 10-6 cm/sec at anticipated hydrostatic head and be of sufficient thickness to prevent the released substance from penetrating the containment structure for a minimum of 72 hours, and until the release can be detected and recovered.

22.13. Emergency containment structures for existing ASTs must be verified by a professional engineer to determine that the emergency containment structure, coupled with the tank monitoring program and response plan, is capable of detecting and recovering a release and is designed to prevent contamination of waters.

22.14. Verification of earthen structures should include determination of the containment structure permeability following ASTM Methods and Engineering Standards Listed in API Publication 351.

22.15. Verification of the containment structure is valid until conditions at the site, monitoring program, response plan or procedures change.

22.16. Transfers of regulated substances to a tank within the emergency containment shall be monitored by designated personnel for the duration of the transfer.



22.17. Emergency containment areas, such as dike fields, must be able to contain 110% of the capacity of the largest tank in the containment area.

22.18. Stormwater shall be removed from the emergency containment area as soon as possible or when the water is in contact with the tank or piping and prior to the capacity of containment being reduced by 10% or more.

22.19. Manually operated pumps or siphons and manually operated gravity drains may be used to empty the containment. If drain valves are used they shall be secured in the closed position when not in use. Discharge or disposal of substances from the containment structure must comply with applicable National and County requirements.

22.20. All oil terminal facilities must have diked areas designed, constructed and maintained to prevent oil from entering waters or adjacent property.

22.21. ASTs must be surrounded by a containment dike with a minimum height of 24 inches, and constructed as follows:

a. Where a diked area contains one storage tank, the diked area must retain not less than 110% of the capacity of the tank;

b. Where a diked area contains more than one storage tank, the diked area must retain not less than 110% of the capacity of the largest tank, deducting the volume of the other tanks in the diked area below the top surface of the dike; and

c. Containment capacity for all facilities must be verified when modifications to the diked areas, or the capacity of the storage tank are made. If no modifications are made, the containment capacity shall be verified every 10 years. Dike walls that have eroded or degraded over time must be regraded or repaired.

22.22. NFPA, Flammable and Combustible Liquids, Code 30, governs dike configuration for all facilities.

22.23. New facilities must have secondary containment with the base and walls designed for a permeability rate to water of 1 x 10-7

Leak Detection

cm/sec, except where asphalt is the only oil stored in the dike area.

22.24. ASTs shall be provided a method of leak detection at installation that is capable of detecting a release.

22.25. The leak detection method shall be monitored at least monthly and shall be installed, calibrated, operated and maintained in accordance with API Standard 650, Welded Steel Tanks for Oil Storage.

22.26. The area beneath the tank bottom shall be monitored for leakage by tell-tale pipe, visual, mechanical or electronic leak detection methods.



22.27. Observation wells outside of the secondary containment structure do not satisfy the leak detection requirements.

22.28. Existing ASTs with secondary containment shall implement a monthly leak detection method. Monthly visual inspections shall be an acceptable method of leak detection.

22.29. Existing ASTs without secondary containment under the bottom of the tank that are in contact with the soil, such as vertical flat bottom tanks, and do not have cathodic protection or an internal lining shall be leak tested at the next scheduled in-service inspection and continue to be leak tested at each in-service inspection thereafter, until the tank is upgraded.

22.30. Tank leak test must follow API 650 procedures that are based on a volumetric/mass measurement, an acoustic measurement, or a soil-vapor monitoring method as addressed in API Publication 334 ‘‘Guide to Leak Detection in Aboveground Storage Tanks.’’

22.31. The test shall be performed by a third-party inspector or a technician who has experience with the selected method and is qualified by the test equipment manufacturer and is not an employee of the tank owner.

22.32. ASTs and piping shall be visually checked for leaks in accordance with the facility operations and maintenance plan.

Liquid Sensing Probes and Cables

22.33. Liquid sensing probes and cables are commonly used in AST leak detection.

22.34. When monitoring single-wall tanks the probes and cables are buried beneath or immediately down-gradient of the AST.

22.35. In double-wall tank applications the probes or cable sensors may be installed in the tanks’ interstitial space to detect leaking liquid before it leaves the tank.

Volumetric and Mass Measurement Methods

22.36. Volumetric and mass measurements systems use suitably precise sensors to quantify the amount of liquid in the tank (API, 1996).

22.37. Volumetric methods of leak detection generally use a product level measurement device and a temperature probe in the tank.

22.38. The volume of product in the tank is calculated, taking temperature into account. If the calculated volume of product decreases inexplicably, a leak may be present.

22.39. Mass measurement methods generally measure the pressure that the liquid exerts on the tank. In this way, the temperature of the liquid does not play into the calculations of product in the tank. Similar to volumetric methods, an unexplained loss of mass may indicate the presence of a leak.



Statistical Inventory Control Methods

22.40. Statistical inventory control methods are among the least complex of the leak detection methods presently available. A detailed record is kept of additions or withdrawals to a tank over a specified period of time.

22.41. Level or mass of the liquid is monitored concurrently. At the end of the monitoring period, the two measurements are compared.

22.42. A discrepancy in the numbers may indicate a leak in the tank. This method of inventory control/leak detection has several sources for error including inaccurate measurement or recording of deliveries, sales volumes, product levels and product level-to-volume conversions.

22.43. A modification of this method has emerged into a more sophisticated and sensitive method of analysis. This method not only has greater sensitivity but also involves shorter data collection duration than traditional methods.

22.44. Statistical Inventory Reconciliation (SIR) involves statistical analysis that accomplishes two main objectives:

a. To separate out and quantify effects that are not “leak-related”

b. To react appropriately to those effects that are not compatible with leakage.

22.45. For each data set analyzed, SIR can determine not only whether or not a leak is present but also the smallest leak that could be detected, given the quality of data provided.

22.46. Qualitative SIR methods are designed to classify a tank system as Pass, Fail or Inconclusive.

22.47. A Pass means that, according to the data analyzed, the system is tight.

22.48. A Fail means that the system may be leaking; however, it could also mean that dispensers are miscalibrated, deliveries are inaccurately metered or product has been stolen.

22.49. An Inconclusive results means that a determination of pass or fail could not be reached based on the data analysis.

22.50. Quantitative SIR methods also classify results as Pass, Fail or Inconclusive, but they also provide an estimated leak rate, usually in litres per hour.

22.51. Because the volume of leakage over any reasonable test period is so much smaller than the average tank volume, API has determined that it is not technically feasible to rely solely on inventory control and monitoring strategies such as SIR for leak detection.

22.52. Inventory control measures should only be used for their original intended purpose, stock loss control.



Automatic Tank Gauging

22.53. Automatic tank gauging continuously monitors the hydrostatic level of product in the tank using a series of electronically monitored floats, probes, and sensors to determine the temperature and level of product in the tank.

22.54. These sensors are connected to a controller, which may be connected to a PC.

22.55. The sensors continuously monitor temperature and fluid levels in the tank and compensate for daily fluctuations in the tank that may influence the liquid volume but are not related to detection of a leak.

Passive-Acoustic Sensing

22.56. Acoustic sensing technology is based on the principle that liquid escaping though a hole or fissure in an AST produces a sound that is detectable. It has been shown that a leak in the floor of an AST actually produces two different types of sound simultaneously.

22.57. One type, the “continuous” sound, is similar to the hissing noise that might be expected when liquid escapes from a container under pressure.

22.58. The second type is an intermittent popping sound that extends beyond the audible frequency range. Known as “impulsive” sound, it is created by the interaction between the flow field of the leak and the air bubbles trapped in the backfill material below the AST floor (API, 1996).

22.59. Passive-acoustic sensing technology is available in two basic formats, continuous monitoring and regularly scheduled testing. The sensors or transducers used in acoustic testing convert the energy from a sound wave into an electrical signal.

22.60. The two types of transducers suitable for acoustic testing are an accelerometer and hydrophone.

22.61. Accelerometers are mounted on the exterior wall of the tank and have the advantage of being non-intrusive. Non-intrusive methods are easier and less expensive to implement, are easily accessible in case of malfunction, and eliminate the need for contact with the product. Hydrophone transducers are submerged in the liquid.

22.62. Typically, arrays of acoustic sensors are either suspended from the tank roof or at evenly spaced intervals around the external circumference of the tank.

22.63. The sensors monitor the tank acoustic levels/locations. A background level of noise is documented by continuous tank monitoring. This background noise is used to create an “acoustic map” of the tank. A persistent anomalous or out of character acoustic signal in a consistent location within a tank may indicate a leak.



Vapor Monitoring

22.64. Leak detection using vapor-monitoring techniques is a fairly straightforward concept.

22.65. Liquids leaking from an AST into the soil or backfill under the tank volatilize filling the backfill or soil pore space. Perforated or screened pipes are arranged under or in monitoring wells surrounding the AST to gather the vapors and to act as a conduit through which soil vapors are extracted.

22.66. The soil vapor is collected and analyzed for either hydrocarbons or the presence of a chemical tracer or both. Tracers or chemical markers are often added to the product in the tank being monitored to differentiate leaking product from naturally occurring background vapors or vapors from previous spills.

22.67. Tracers or markers detected during analysis of the vapors may indicate a leak in the tank.

Fiber Optic Sensing Probes

22.68. Fiber optic sensing probe can be installed during construction or easily retrofitted to existing ASTs.

22.69. The probes are driven into the soil beneath an AST. The fiber optic probe has a covering that changes its refractive index in the presence of very small amounts of hydrocarbons. This change in refractive index is registered optically by the probe, and converted to a parts-per-million reading of the hydrocarbons.

22.70. The sensing probe is capable of detecting both liquid and vapor phase hydrocarbons. This system has been used in several leak detection applications for a little more than five years.

22.71. Existing ASTs without secondary containment under the bottom of the tank that are in contact with the soil, such as vertical flat bottom tanks, and do not have cathodic protection or an internal lining shall be upgraded.

Spill and Storm Run Off

22.72. Product–transfer areas shall be paved with concrete and graded, curbed, or diked to contain spills or overfills that occur during the transfer process in line with API 2610.

22.73. Containment area floors within dikes shall be sloped away from the tank base towards a sump at a slope greater than 1%.

22.74. An OWS used to treat stormwater runoff from the product transfer area should be:



a. Designed to produce a discharge of water that does not contain more than 15 mg/L of oil and grease as measured by the partition–gravimetric method or other protocol as defined by the authority having jurisdiction

b. Sized for a hydraulic flow rate of a 10 year return, 1–hour storm event (the 1–hour rainfall intensity data should be obtained for the nearest weather station)

c. Designed for an oil with a specific gravity of 0.90

d. Designed to capture a spill of petroleum product of a volume equal to the amount of petroleum product transferred in 2 minutes at the highest pumping rate normally used within the area that drains to the oil/water separator

e. Designed based on the hydraulic retention time required to separate oil with a particle droplet size of 60 µm (microns) from stormwater.

Ground Monitoring Wells

22.75. Monitoring wells must be a minimum of 2 inches in diameter in accordance with API 2610.

22.76. The screened zone must extend at least 300 centimeters into the water table and at least 150 centimeters above the ground water surface, as determined at the time of installation; or when installed within a secondary containment liner, the base of the well screen must extend to within 15 centimeters of the low point of the liner.

22.77. The screened portion of a well outside a liner must be a minimum of 4.5 metres in length and must be factory slotted with a slot size of 0.010 inch.

22.78. Monitoring wells must be installed with a cap at the bottom of the slotted section of the well.

22.79. Monitoring wells must be constructed of flush joint, threaded schedule 40 PVC or other types of PVC which have equivalent or greater wall thicknesses.

22.80. Monitoring wells must be numbered such that all monitoring and testing results may be easily correlated to a specific monitoring well location.

22.81. All monitoring wells must be equipped with liquid-proof lockable caps.

22.82. Monitoring wells must be properly distinguished from oil piping using American Petroleum Institute recommended symbols.

22.83. The area around the screened portion of the well must be surrounded by a porous medium (e.g., sand, gravel, or pea stone).

22.84. The outside of the well riser must be sealed to the wall of the boring using bentonite or a similar product to a depth of 1.5 feet below ground surface, or to 0.5 feet above the water table, whichever is shallower.



22.85. Monitoring wells which are located in traffic areas must be cut off at ground level, clearly marked, with a raised limited access cover in accordance with PEI Publication RP100-90 (1990) or properly protected from vehicles.

22.86. Any damaged monitoring well must be repaired, replaced or properly abandoned as soon as possible after discovery of the damage.

22.87. Monitoring wells must be installed with a boring rig rather than a backhoe if they are not installed within a containment liner.

22.88. Monitoring wells within a diked area should be properly abandoned, or completed in such a way to prevent leakage of oil via the well should a spill occur within the diked area.

22.89. All wells completed as stick-ups should be completed with a protective steel casing.

23. Spacing and Dikes

22.90. Tank Spacing of ASTs and dikes must be separated in accordance with KS1967 or NFPA 30.

22.91. Tanks used only for storing Class III B liquids (Flash point 200°F and above) may be spaced no less than 3 feet apart unless within a diked area or a drainage path for a tank storing Class I or II liquid in which case the provisions of NFPA 30 apply.

23.1. All dikes, diversion walls and toe walls shall be suitable for the static hydraulic and temperature conditions which may be encountered, and shall be liquid tight.

23.2. AST piping for any tank or group of tanks enclosed by a dike shall not run through other diked areas. However, piping of tankage within a group may cross intermediate toe walls within that group.

23.3. Pumps shall be located outside the diked area, unless a high flash viscous stock requires the pump to be located within the diked area.

23.4. Dike arrangement for low-flash stocks shall be as follows:

a. Tankage may be grouped within a single dike, provided a combined capacity of 48000 m3

b. Each tank with a capacity of 8000 m

is not exceeded. 3 or greater or group of tanks with

a capacity of more than 8000 m3

c. Two tanks with a combined capacity exceeding 48000 m

shall be separated from other tanks in the same group by toe wall.

3, regardless of individual capacity, may be paired within a single dike. An intermediate dike shall be provided between paired tanks.



d. Single tanks which cannot be grouped or paired shall be enclosed by individual dikes.

e. If roofs are other than floating roofs, the tank diameter shall be limited to 45 m.

23.5. Dike arrangement for crude oil stocks shall be as follows:

23.6. Floating roof tanks shall be enclosed by individual dikes, or paired within a single dike. An intermediate dike shall be provided between paired tanks.

23.7. Fixed roof tanks shall be enclosed by individual dikes. Pairing is not allowed.

23.8. For high flash stocks, any number of tanks regardless of total capacity may be grouped within a single dike or toe wall.

23.9. The pairing principle for arrangement of low-flash stocks or crude oil in floating roof tanks may be extended to include a total of three tanks, but only in the case of an odd number of tanks.

23.10. For low flash stocks and crude oils, dike net capacities shall be as per the Table.

DIKE CAPACITIES TYPES OF STOCKS

AND TANKAGE

ONE TANK PAIRED TANKS GROUPED TANKS

LOW FLASHSTOCKS INFIXEDORFLOATING ROOF TANKS

75% CAPACITY

OF ENCLOSED

TANK

75% CAPACITY OF

LARGEST TANK

ALLOWING FOR THE

DISPLACEMENT OF

OTHER TANK(S)

100% CAPACITY OF

LARGEST TANK

ALLOWING FOR THE

DISPLACEMENT OF

ALL OTHER TANK(S)

CRUDE STOCKS ON

FLOATINGROOF TANKS

75% CAPACITY

OF ENCLOSED

TANK

75% CAPACITY OF

LARGEST TANK

ALLOWING FOR THE

DISPLACEMENT OF

OTHER TANKS

NOT PERMISSIBLE

CRUDE STOCKS IN

FIXED ROOF TANKS

100% CAPACITY

OF ENCLOSED

TANK

NOT PERMISSIBLE NOT PERMISSIBLE

23.11. At least one stairway shall be provided over earth and concrete dikes, however, at least two stair ways shall be provided for concrete dikes 1 m or more high and earth dikes over 2 m high. When two stairways are provided they shall be on opposite sides of the dike enclosure. At least one stairway shall be located as close as possible to a fire hydrant.



23.12. A drain system shall be installed to provide for rain run off

23.13. Grading of diked or toe wall enclosures shall direct the liquid from a leak in the vessels or piping to an area within the enclosure that is remote from the vessels and piping.

23.14. Minimum spacing between tanks shall be as shown in the Table below: TANKS SPACING MINIMUM SPACING BETWEEN:

TYPE OF STOCKS AND TANKAGE

SINGLE OR PAIRED

TANKS

GROUPED TANKS ADJACENT ROWS OF TANKS IN SEPARATE GROUPS

LOW-FLASH STOCKS INFLOATING ROOF TANKS

¾ TANK DIAMETER.

NEED NOT EXCEED 60 m

½ TANK DIAMETER

NEED NOT EXCEED

60 m

¾ TANK DIAMETER, NOT LESS THAN 22.5 m. NEED NOT EXCEED 60 m

LOW-FLASH STOCKS IN

FIXED ROOF TANKS

1 TANK

DIAMETER

½ TANK DIAMETER 1 TANK DIAMETER.

NOT LESS THAN 30 m

CRUDE OIL STOCKS IN FLOATING ROOF TANKS

¾ TANK DIAMETER.

NEED NOT EXCEED 60 m

NOT PERMITTED ___

CRUDE OIL STOCKS IN FIXED ROOF TANKS

1.½TANK DIAMETER.

(PAIRING NOT PERMITTED)

NOT PERMITTED ___

HIGHFLASH STOCKS IN ANY TYPE TANK

½ TANK DIAMETER

NEED NOT EXCEED

60 m

½ TANK DIAMETER.

NEED NOT EXCEED

60 m

½ TANK DIAMETER NOT LESS THAN 15 m. NEED NOT EXCEED 60 m

24. Vapour Emission Control

Expected Emissions

24.1. Emissions from storage tanks occur because of evaporative losses of the liquid during storage (breathing losses) and as a result of changes in liquid level (working losses).

24.2. Due to higher average ambient temperatures during the hot season, the vapor pressure of an organic liquid will increase

24.3. AST emissions can include VOC, HAP, toxic, and inorganic emissions from flashing, landing, breathing, and working losses.

24.4. Storage tank emissions may also include emissions from degassing, cleaning, and defective tank seals and fittings.

24.5. All storage tank emissions, whether routine or not, should be quantified and reported in the emissions inventory.



Associated Emissions

24.6. Equipment leaks and loading losses from trucks, railcars, tank cars, etc., are two other emissions sources generally associated with liquid storage operations.

Requirements

24.7. Where vapor monitoring is to be considered level 2 leak detection, a Hydrogeologist or other person experienced in the design of vapor monitoring systems shall assess the site and establish the number and positioning of the monitoring wells so that product releases from any portion of the storage tank system that routinely contains a petroleum product will be detected

24.8. The vapor monitoring equipments shall have their performance calibrated by an accredited third–party testing organization

24.9. The vapor monitoring equipments shall be designed and operated to detect significant increase in concentration above the background level of:

a. Petroleum product stored

b. Component or components of the petroleum product

c. Tracer compound placed in the storage tank system.

24.10. If more than one monitoring well is necessary to monitor an installation effectively, the monitoring wells shall be numbered so that all monitoring and testing results shall be easily correlated to a specific monitoring location.

24.11. Vapor monitoring wells shall be equipped with liquid–proof caps.

24.12. Monitoring wells shall be distinguished from fill pipes

24.13. Monitoring wells shall be secured to prevent unauthorized access and tampering.

24.14. Vapor monitoring wells that are located in traffic areas shall be cut off at ground level and/or properly protected from vehicles.

24.15. Vapor monitoring wells installed within the interstitial space shall not penetrate the liner.

25. Gauging

25.1. Each AST must employ:

a. A mechanical or electronic product level gauge



b. An audible or visual high-level alarm that is triggered within 378 litres of capacity

c. Manual gauging

25.2. If manual gauging is used, documentation of available tank capacity must be transmitted to delivery personnel prior to delivery

26. Commissioning

General

26.1. Prior to the site becoming operational, measures should be taken to ensure that all valves, fill pipes, vent pipes and monitoring wells are readily identifiable and cannot be confused.

26.2. Prior to operation the following checks should be carried out:

a. Testing of manhole chambers for integrity

b. Drainage systems, including separators completed and tested

c. Separators to be charged with water to make them operational

d. Emergency equipment installed and operational

e. Loading Gantries and staging areas completed

f. All tanks, pipework, dispensers and pressure relief systems to be tested, to demonstrate integrity and safety.

26.3. Other commissioning procedures include the following:

a. Safety signs and notices in place

b. Emergency equipment in place and working correctly

c. Fill points, tanks, pipework and dispensing equipment clearly marked

26.4. Where drainage systems have been installed, they are connected, leak tested and free from debris and the interceptor charged with its water seal.

Labelling

26.5. Each AST must be labeled in accordance with API650 with the following minimum requirement :

a. tank number

b. tank contents

c. tank capacity

d. Installation, inspection and calibration date



26.6. Each AST must be issued with a completion certificate and valid Tank Calibration Chart showing volume conversion from millimeters of product to litres at observed temperatures

26.7. Piping must be labeled with the product type carried at the tank inlet and at the point of delivery.

26.8. Manifolded delivery points must have all valves labeled as to product distribution.

Tank Testing

26.9. Product connections shall not be made to the AST until the AST is tested and accepted by a certified inspector.

26.10. Pneumatic testing of the reinforcing plates shall be done in accordance with API 650 and API 653.

26.11. The roof drain of the floating roof AST shall be installed prior to the hydraulic test on the tank and during the test the drain shall be examined to ensure that it is not leaking due to external pressure.

26.12. Roof manholes shall be open while filling or emptying a fixed roof tank for test purposes, so that the tank is not damaged by excessive vacuum or pressure loading.

26.13. Hydrostatic test of the tank include filling and emptying. The temperature of the test water shall be not lower than 20°C.

26.14. The cathodic protection systems must be inspected to ensure that they are functioning properly.

26.15. On completion of all tests, the entire storage tank must be free from leaks to the satisfaction of the certified inspector in accordance to API 650 and API 653.

26.16. Hydrostatic tests shall commence and finish during daylight hours.

Initial Filling

26.17. The first delivery of fuel must be carried out with great care to avoid the release of large amounts of vapor through the fill pipes openings of the tanks.

26.18. While it is normal practice to test all tanks by filling with water before commissioning, this filling should be done under controlled conditions to ensure that foundation failure does not occur during filling. The hydrostatic test pressure is an integral part of the foundation design and should be agreed with a soil mechanics specialist.

26.19. All tank tests will be carried out to provide adequate measure load/settlement records in line with API 650.



26.20. The first AST in a new area will be the most critical and subsequent testing arrangements on other tanks should be adjusted in the light of the first test results where the tanks are on similar sub-soil conditions.

26.21. The water filling rate for testing shall not exceed than the rates shown in the Table below.

BOTTOMCOURSE THICKNESS mm

TANK PORTION FILLING RATE

mm/hr

< 22

TOP COURSE BELOW TOP COURSE 300

450

≥ 22

TOP THIRD MIDDLE THIRD

BOTTOM THIRD

225

300

450

26.22. Uneven settlement of the tank on its foundation shall be reported immediately to the owner’s representative, and filling shall be stopped at any signs of excessive settlement pending a decision by the owner’s representative on the action to be taken.

26.23. The shells of fixed roof tanks shall be tested after completion of the roof and those of open top or floating roof tanks after completion of the wind girder.

26.24. Continuous inspection shall be maintained for the whole filling period. All leaks found shall be repaired with the water level at least 300 mm below the point being repaired.

26.25. ASTs showing evidence of leakage from the bottom during water test should be emptied immediately. The source of such leaks should be determined and rectified. Where there is risk that the leakage may have caused washout of the foundation material, the foundations are to be inspected.

26.26. The center deck plate, pontoon bottom plate and rim plate welded joints shall be tested by spraying with a penetrating oil, such as light gas oil, on the bottom side and inspecting visually on the top side and inside of rim plates.

26.27. Each completed compartment of pontoon roof shall be individually tested with an air pressure of 7 mbar gage, a soapy water solution being applied to all welded joints under pressure which have not been previously tested with penetrating oil.

26.28. The roof shall be given a floatation test while the tank is being filled with water and emptied. During this test, the upper side of the lower deck and



all pontoon compartments shall be examined for leaks. Rainwater shall be prevented from entering the pontoon compartments during this test.

26.29. It is recommended that a similar tightness check is made during the first filling with oil, as the roof will immerse deeper in oil than in water.

26.30. Roof drain pipe systems shall be tested with water to a pressure of 3.5 bars.

26.31. The sealing mechanism shall be checked to ensure proper functioning over the full height of the shell.

26.32. Pressure and vacuum relief vents shall normally be installed after completion of the tank water test or alternatively shall be blanked-off during the testing of the roof. After installation or immediately following the roof pressure test all vents shall be carefully examined to ensure that all packing and blanks have been removed and that all moving parts function normally.

26.33. When the tank shell is tested with water the roof joints shall be tested by applying an internal air pressure equal to 7.5 mbar for non-pressure tanks and 3 mbar above the design pressure

26.34. A safe method of introducing fuel into the tanks is to individually unload 1,000 Litres of fuel into one tank at a time until all tanks are charged with sufficient fuel to provide a seal at the drop tube.

26.35. After this stage of the commissioning procedure is completed the remainder of the product can be offloaded in the normal manner.

Installation and Modification Inspections

26.36. AST Systems shall be inspected by a certified inspector. Pressurized vessels shall be inspected by a DOSHS certified inspector at the time of installation for the in accordance to recognized code of practice and manufacturer’s specifications.

26.37. Inspections Reports shall be kept for the operational life of the tank.

26.38. Major modifications shall be inspected by an API 653 certified inspector at the time of modification prior to being put back in service. When substantial modifications are made to the tank floor, the next inspection date projections shall be determined based on the condition of the tank subsequent to those modifications

26.39. Tanks which are relocated or reconstructed shall be inspected by an API 653 certified inspector and tested for tightness in accordance with codes of practice prior to being put in service.



Third Party inspections

26.40. AST owners and operators shall have their storage tank systems inspected by a API 653 certified AST Inspector

26.41. Inspections will check for compliance with ERC requirements and adherence to current codes of practice developed by tank manufacturer’s instructions and design engineer’s specifications.

26.42. Only API 653 certified inspectors shall be used to satisfy requirements for installation and modification inspections.

27. Decommissioning

Out of Service AST Requirements

27.1. When an AST is no longer used, it must be taken out of service or removed.

27.2. If product has not been added to or removed from an AST for a year or more, the owner must maintain and monitor the tank, declare the tank inactive and out of service, or remove the tank.

27.3. If the tank is declared inactive and taken out of service, the terminal operator has to:

a. Remove all AST and piping and other appurtenances.

b. Secure the AST by bolting and locking all manways and valves and cap or plug fill lines, gauge openings, or pump lines.

c. Completely remove all product, sludge, solids, and residuals inside of AST and piping.

d. Dispose of tank bottom sludge according to NEMA Waste Management Regulations.

e. Rid the tank of vapors so an explosive atmosphere cannot exist.

f. Secure the AST to prevent unauthorized entrance or tampering.

g. Thoroughly clean the interior of the tank and piping of all sludge, solids, and residuals.

h. Label the tank exterior “Out of Service,” and the date the tank was removed from service.

Permanent Closure or Change in Service

27.4. Before permanent closure or change-in-service is completed, the owner/operator shall comply with the following:



a. Complete a site assessment to measure for the presence of any release from the storage tank system and a closure report.

b. If contaminated soil, sediment, surface water or groundwater, or free product is discovered or confirmed by either direct observation or indicated by the analytical results of sampling, the owner/operator shall proceed with the corrective action

c. Regulated substance and contents removed from the tank system including piping shall be reused, treated or disposed of in a manner consistent with applicable NEMA waste management requirements.

d. Tank systems shall be cleaned, rendered free of hazardous vapors and ventilated if left onsite or tank systems shall be emptied and removed from the site in a manner consistent with current industry practice

e. Tanks to be permanently closed and left onsite shall be legibly marked with the date of permanent closure.

27.5. Tanks that are to be closed in place shall:

a. Be rendered inoperable and incapable of storing liquid substance.

b. Be secured against unauthorized entry.

27.6. The results of the site assessment and the closure report shall be retained for 3 years.

Temporary Removal from Service

27.7. A tank system shall be emptied and regulated substances and contents shall be reused, treated or disposed of in accordance with NEMA requirements.

27.8. A tank shall be secured against unauthorized entry and all piping entering or exiting the tank, excluding vents, shall be capped or blinded.

27.9. Tank integrity shall be maintained throughout the temporary removal-from-service time and the tank shall be protected against flotation. For example, ASTs in flood plains must be safeguarded against buoyancy and lateral movement by flood waters in accordance with operating standards set forth in NFPA No. 30, section 2-5.6 (see subdivision 613.1(g)). If such safeguards include ballasting of tanks with water during flood warning periods, tank valves and other openings must be closed and secured in a locked position in advance of the flood. Ballast water removed from the tank after the flood must not be discharged to the waters.

27.10. In-service and out-of-service inspection intervals may be delayed for a tank that is temporarily removed from service. The delayed inspections shall be conducted prior to placing regulated substance in a tank and returning the tank to operating status.



27.11. Deficiencies noted during inspection shall be addressed and remedied prior to returning the tank to operating status.

27.12. Tanks which are temporarily removed-from-service for 5 years or longer must meet the requirements for permanent closure as outlined under section 23.2, unless the time frame for retaining the tank or tanks in temporary removal-from-service status is extended.

Removing Recoverable Product

27.13. Employers should establish, and tank cleaning entry supervisors should implement, procedures for removing recoverable product from the tank that cover items such as the following:

a. Area protection, potential sources of ignition and electrical classification.

b. Bonding and grounding.

c. Entry onto fixed and floating roofs.

d. Removing recoverable product through product lines.

e. Recoverable product removal by suction pump through fixed connections.

f. Recoverable product removal by flotation through open manholes or connections.

g. Recoverable product removal by vacuum pump.

h. Recoverable product removal through open manholes.

Tank Isolation

27.14. "Isolation" means the process by which a permit space is removed from service and completely protected against the release of energy and material into the space by such means as: blanking or blinding; misaligning or removing sections of lines, pipes, or ducts; a double block and bleed system; lockout or tag out of all sources of energy; or blocking or disconnecting all mechanical linkages.

27.15. Employers must develop and implement the isolation means, procedures, and practices necessary for safe tank entry.

27.16. Before entry is made, employers must document the completion of these measures and entry supervisors must verify that all procedures have been followed before endorsing the permit.

27.17. The isolation plan should address:

a. Tank isolation requirements

b. Tank suction and discharge lines

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c. Other tank lines, appurtenances and connections

d. Energy sources - electrical, mechanical and pressure

e. Cathodic protection systems

f. Vapor recovery systems

Vapour and Gas Freeing

27.18. Vapor and gas freeing occurs after all product, tank bottoms and residue has been removed from a tank and the tank has been properly isolated.

27.19. Employers must establish and implement safe vapor and gas freeing procedures. The requirements and additional guidance to employers and employees who participate in activities related to entry into petroleum ASTs include:

a. Preplanning

b. Training and Rescue

c. Setting up equipment for tank entry and cleaning

d. Removing recoverable product from tanks using fixed connections and piping (decommissioning)

e. Removing remaining product and tank bottoms through an entryway (without entry)

f. Tank isolation

g. Vapor and gas freeing the tank (degassing)

h. Atmospheric testing the tank interior with relevant certified equipment

i. Cleaning the tank

j. Working inside and around the tank

k. De-isolation and returning the tank to service

l. Recommissioning

27.20. API RPs also provides guidance related to worker protection including:

a. Recommended Practice 2219, Safe Operating Guidelines for Vacuum Trucks in Petroleum Service.

b. Recommended Practice 2220, Improving Owner and Contractor Safety Performance.

c. Recommended Practice 2221, Contractor and Owner Safety Program Implementation.

27.21. Acceptable entry conditions must be specified and verified through appropriate testing and monitoring, prior to tank entry.

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Cleaning

27.22. Tank cleaning entry supervisors must determine, administer and implement safe work procedures and appropriate safe limits for employee's exposure to hydrocarbon vapors and gases and toxic gases, and required oxygen concentrations both when working outside of tanks and when entering and working in tanks during tank cleaning operations, in accordance with applicable regulations and facility confined space entry requirements.

27.23. The safe work procedures should include:

a. Permit requirements

b. Personal protective equipment

c. Sludge and residue removal from outside the tank

d. Cleaning the tanks from the inside

27.24. Proper operation of the cathodic protection systems must be confirmed within six months after initial installation, and annually thereafter

28. Recommissioning

General

28.1. When reactivating an out-of-service AST, it must be inspected and meet leak detection requirements before it is put back in service.

28.2. Determining the disposition of a tank prior to installation and selection of an LDS is an important consideration. If the tank is aged and has a history of previous leaks, this information will influence the type of LDS applicable for that particular tank and situation.

28.3. Proper identification of previous leaks, their locations and the approximate quantity of product that escaped will help minimize possible sources of noise after selection and installation of an LDS.

Temporary Requirements

28.4. Temporary ASTs store product at a site for more than 30 days, but less than one year.

28.5. The exterior of temporary storage tanks must be clearly labeled with the words “Temporary Storage” and the date storage began at the site.

28.6. A terminal that does not have a person at the site 24-hours-a-day must have a sign with the name, address, and telephone number of the facility owner, operator, or local emergency response unit. The sign must be



posted in a conspicuous place and legible from outside any secondary containment area.

28.7. Temporary ASTs must in accordance with API 653 have 100 percent containment capacity of the largest tank in the secondary containment basin. An additional ten percent containment capacity is required if exposed to precipitation. Basin materials must be compatible with the products stored in the tanks.

28.8. To minimize corrosion or rust on the tank exterior and maintain the integrity of the secondary containment area, keep tanks, containment areas, and substance transfer areas free of cracks, open seams, open drains, and vegetation other than grass. Precipitation also needs to be removed from the secondary containment areas to ensure proper containment volume.

29. Record Keeping

29.1. AST records kept for the life cycle include:

a. Maintenance and repair documentation of tank systems

b. Third-party certifications of equipment

c. As built drawings of tank foundations, tank bottom designs, volume and design of the secondary containment basin including dike walls and the area directly under the tank (certified by a professional engineer for field-erected tanks)

d. Classification of soils used in containment area construction

e. Soil descriptions and logs of each sample location in secondary containment areas

f. Permeability testing data for containment areas

g. Hydraulic conductivity of the soil expressed as cm/sec. for each sample location and containment area

h. Documentation of corrosion protection, internal and external tank inspections, and written summaries of the results

i. Documentation for out-of-service tank requirements

j. All documentation addressing service check and equipment calibrations on tank systems



30. References

30.1. API

30.2. NFPA

30.3. ASTM

30.4. Energy Act 2006

30.5. Environmental Management and Co-ordination Act, 1999.

30.6. Environment Management and Coordination (Water Quality) Regulations, 2006

30.7. Environment Management and Coordination (Waste Management) Regulations, 2006

30.8. Environmental Management and Co-ordination (Controlled Substances) Regulations 2007.

30.9. Occupational Health and Safety Act 2007

30.10. KS 200 (2002) - Specification for storage tanks for

PETROLEUM INDUSTRY - Part 1: Carbon steel welded horizontal cylindrical storage tanks (Second Edition).

30.11. KS ISO 1998 – 5 - PETROLEUM INDUSTRY –

Terminology –Part 5: Transport, storage and distribution.

30.12. KS 1968 (2006) - The petroleum industry – Electrical

Installations in the distribution and marketing sector - Code of practice.

30.13. KS 1967 - The petroleum industry – The



31. Contacts

31.1.

Head Office: Eagle Africa Centre - Upper Hill

ENERGY REGULATORY COMMISSION (ERC)

Telephone: 254-020-2717627/31/75; 254-020-2847000/200

Cell Phone: 0722200947; 0734414333

Fax: 254-02-2717603

Postal Address: P.O. Box 42681 - 00100 NAIROBI, KENYA

Email (General Information): Website: www.erc.go.ke

31.2.

Popo Road, Off Mombasa Road

KENYA BUREAU OF STANDARDS (KEBS)

Behind Bellevue Cinema

P.O Box 54974-00200

Nairobi – Kenya

Tel: (+254 20), 605506,605550, 605573,605574,605610,605634, 605642,605673,603482, (+254 20) 6948000/605490

Mobile: +254722202137/8, +254734600471/2

Fax: (+254 20) 60403, 609660

Email: [email protected]

Website: www.kebs.org

31.3.

Popo Road, Off Mombasa Road

NATIONAL ENVIRONMENT MANAGEMENT AUTHORITY (NEMA)

Behind Bellevue Cinema

P.O Box 67839 – 00200

Nairobi – Kenya

Tel: (+254 20) 6005522/6/7

Mobile: 0724 - 253 398 /0728-585 829 / 0735-013 046 / 0735-010 237

Fax :( 254)-020-6008997

Email:[email protected]

Website: www.nema.go.ke

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design, commissioning, decommissioning and recommissioning

Documents