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15 Feb 2015 Letter to US Senate Ctee on Energy & Natural Resources
Storage Requirements for the
Guide 55: Storage Requirements for the Upstream Petroleum Industry
640 – 5 Avenue SW
Telephone: (403) 297-8311
Fax: (403) 297-7040
Web site: <www.eub.gov.ab.ca>
Foreword.......................................................................................................................................... v
1 Introduction ............................................................................................................................... 1
1.1 Purpose ............................................................................................................................... 1
1.2 Intent ................................................................................................................................... 1
1.3 Storage Jurisdictional Overview ......................................................................................... 1
1.4 Effective Dates.................................................................................................................... 2
1.4.1 Facilities Operating Prior to January 1, 1996............................................................ 2
1.4.2 Facilities Constructed on or after January 1, 1996.................................................... 2
1.4.3 Changes to Guide 55 ................................................................................................. 3
1.4.4 Implementation Dates for New/Revised Requirements ............................................ 3
2 Scope ......................................................................................................................................... 5
2.1 Guide 55 Overview ............................................................................................................. 5
2.2 Containment Devices .......................................................................................................... 6
2.3 Applicable Material Types.................................................................................................. 6
2.4 Excluded Material Types and Storage Systems.................................................................. 6
2.5 Alternative Storage Systems ............................................................................................... 8
3 General Storage Practices and Requirements............................................................................ 9
3.1 Environmental Protection and Safety Practices .................................................................. 9
3.2 Release/Spill Prevention ..................................................................................................... 9
3.3 Storage Duration ............................................................................................................... 10
3.4 Permanent Storage ............................................................................................................ 10
3.4.1 Permanent Storage Devices Not Requiring Secondary Containment ..................... 11
3.5 Temporary Storage ........................................................................................................... 11
3.6 Siting................................................................................................................................. 12
3.7 Equipment Spacing ........................................................................................................... 12
3.8 Identification of Storage Facilities.................................................................................... 14
3.9 Compliance and Enforcement........................................................................................... 14
4 Requirements Summary .......................................................................................................... 17
5 Requirements for Aboveground Storage Tanks ...................................................................... 20
5.1 Aboveground Storage Tanks with an Internal Volume Less Than 5 m3 ........................... 20
5.2 Aboveground Open-Topped, Nonmetallic Tanks with an Internal Volume
Less Than 30 m3 ............................................................................................................... 20
5.3 Aboveground Storage Tanks with an Internal Volume Equal to or
Greater Than 5 m3 ............................................................................................................. 21
5.3.1 Construction......................................................................................................... 21
5.3.2 Single-Walled Aboveground Tanks with an Internal Volume of 5 m3 or
Greater ................................................................................................................. 22
5.3.2.1 Secondary Containment....................................................................... 22
5.3.2.1(a) Dikes ............................................................................................. 22
5.3.2.1(b) Impervious Liners ......................................................................... 23
5.3.2.2 Leak Detection..................................................................................... 23
5.3.2.3 Secondary Containment for Indoor Single-Walled Aboveground
Storage Tanks ...................................................................................... 23
5.3.3 Double-Walled Tanks .......................................................................................... 23
i • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
6 Requirements for Underground Storage Tanks ................................................................ 25
6.1 Construction................................................................................................................ 25
6.2 Secondary Containment and Leak Detection.............................................................. 26
7 Storage Requirements for Containers ............................................................................... 27
7.1 Secondary Containment ............................................................................................. 27
7.2 Leak Detection and Weather Protection..................................................................... 28
8 Requirements for Lined Earthen Excavations .................................................................. 29
8.1 Construction ............................................................................................................... 29
8.2 Secondary Containment and Leak Detection ............................................................. 29
9 Requirements for Bulk Pads ............................................................................................. 31
10 Inspection, Monitoring, and Record-Keeping Requirements ........................................... 32
11 Criteria for the Surface Discharge of Collected Surface
Run-On/Runoff Waters..................................................................................................... 34
12 Withdrawal of Storage Tanks from Service...................................................................... 35
12.1 Temporary Withdrawal from Service Not Exceeding 180 Days .............................. 35
12.2 Temporary Withdrawal from Service Exceeding 180 Days ..................................... 35
12.3 Permanent Withdrawal from Service........................................................................ 35
13 Liner Specifications. ......................................................................................................... 37
13.1 Compacted Clay Liners ............................................................................................ 37
13.2 Natural Liners ........................................................................................................... 38
13.3 Synthetic Liners ........................................................................................................ 39
13.3.1 Coated Fabrics and Laminates ...................................................................... 40
13.3.2 Extruded Film or Sheet ................................................................................. 40
13.3.3 Spray-on Coatings ......................................................................................... 40
Appendix 1: Glossary of Storage Terms ................................................................................. 41
Appendix 2: Storage Requirements for Existing Facilities, Well Sites, and Pipelines ........... 45
1 Discontinued Storage Options (Effective January 1, 2002) ....................................... 45
2 Storage Requirements for Existing Facilities, Well Sites, and Pipelines
Operating Prior to January 1, 1996 ............................................................................ 45
2.1 Aboveground Storage Tanks (Internal Volume ≥ 5 m3) ...................................... 46
2.1.1 Retrofitting.............................................................................................. 46
2.1.2 Integrity Testing...................................................................................... 46
2.1.3 Replacement of an Existing Aboveground Storage Tank or
Addition of a New Tank to an Existing Tank Farm................................ 47
2.1.4 Options to Replace the Requirements to Integrity Verify
Aboveground Tanks................................................................................ 47
2.2 Underground Storage Tanks ................................................................................ 48
2.2.1 Retrofitting.............................................................................................. 48
2.2.2 Integrity Testing...................................................................................... 49
2.3 Small Aboveground Tanks, Containers, Lined Earthen Excavations, and
Bulk Pads ............................................................................................................. 50
3 Existing Monitoring Programs ................................................................................... 50
ii • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Appendix 3: References .......................................................................................................... 63
Regulatory ........................................................................................................................ 63
Liners ................................................................................................................................ 65
Storage Tanks ................................................................................................................... 67
Construction Standards for Aboveground and Underground Storage Tanks.................... 67
Table 1. Summary of Requirements Applicable to Oilfield Material Storage.................... 7
Table 2. General Requirements for Containment Devices ............................................... 18
Table 3. A Summary of Inspection, Monitoring, and Record-Keeping Requirements..... 19
Table A1. Integrity Tests for Aboveground Storage Tanks.............................................. 51
Table A2. Integrity Tests for Underground Storage Tanks .............................................. 56
Table A3. Explanatory Notes............................................................................................ 61
Figure 1. Equipment Spacing Diagram............................................................................. 13
Figure 2. Facility Identification and Warning Signs......................................................... 15
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • iii
iv • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
The Alberta Energy and Utilities Board (EUB) first published Interim Directive (ID) 95-3
and Guide 55: Storage Requirements for the Upstream Petroleum Industry in July 1995.
The Storage Committee, which developed Guide 55, consisted of membership from the
EUB, Alberta Environment (AENV), and the Canadian Association of Petroleum
Producers (CAPP) and was under the umbrella of the Oilfield Waste Management
Steering Committee. This Steering Committee consisted of membership from EUB,
AENV, CAPP, Alberta Special Waste Management Corporation, Alberta Oilfield
Treating & Disposal Association, Environmental Services Association of Alberta, Toxic
Watch Society, and the Pembina Institute for Appropriate Development, with input from
Alberta Health and the Health Unit Association.
The Steering Committee oversaw the development of EUB Guide 58: Oilfield Waste
Management Requirements for the Upstream Petroleum Industry. Initially, one section of
the draft report that eventually became Guide 58 was on storage of oilfield waste.
Through the public review of the draft report, it was recommended that the storage
section be expanded to cover all materials used, produced, and generated by the upstream
petroleum industry. As a result, the storage requirements were removed from the draft
report and developed as Guide 55. Prior to publication, Guide 55 underwent stakeholder
review through the Steering Committee.
The Storage Committee recommended that the document be subject to future reviews. In
2000 the EUB initiated a technical review of Guide 55. The Guide 55 Review Committee
consisted of the following membership:
Susan Halla Alberta Energy and Utilities Board
Allison Wolfe Alberta Energy and Utilities Board
Elaine Wasylenchuk Alberta Environment
Joseph Feehan Alberta Environment
Raymond Ligenza Alberta Municipal Affairs
Don Edgecombe Petroleum Tank Management Association of Alberta
Karen Blank National Energy Board
Abby Dorval National Energy Board
Darryl Hass Canadian Association of Petroleum Producers
Richard Clark Canadian Association of Petroleum Producers
Allen Hein Canadian Association of Petroleum Producers
Michael O’Connell Environmental Services Association of Alberta
Jim Gordon Canadian Association of Petroleum Producers
Mark Blundell Canadian Energy Pipeline Association
The technical review of Guide 55 included an assessment of the Canadian Council
Ministers of the Environment (CCME) document Environmental Guidelines for the
Control of Volatile Organic Compounds from Aboveground Storage Tanks. As the
overall issue of the emission of volatile organic compounds from the upstream petroleum
industry and their appropriate control is very complex and broad, the Guide 55 Review
Committee recommended that this issue be reviewed independently of the Guide 55
process. Should Guide 55 be the appropriate document to contain any requirements
developed to address this issue for Alberta, they will be incorporated at a later date.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • v
The purpose of this guide is to identify requirements for the storage of materials produced,
generated (including wastes), or used by the upstream petroleum industry. Here the term
“upstream petroleum” industry is limited to facilities, well sites, and pipelines licensed or
approved by the EUB for the exploration, production, recovery, handling, processing,
treatment, disposal, or transmission of hydrocarbon-based resources or any associated
substances or wastes, but does not include oil sands mining operations or the underground
cavern storage of natural gas. The guide comprises a set of technical requirements
designed to provide an acceptable level of storage practices for the upstream petroleum
The intent of these requirements is to prevent soil, groundwater, and surface water
contamination at upstream petroleum sites. The implementation of appropriate storage
practices should reduce the long-term costs associated with decontamination activities and
enhance the capability for upstream petroleum sites to be reclaimed to conditions suitable
for the next intended land use.
Guide 55 establishes requirements that address
• primary containment (storage) devices,
• secondary containment systems,
• leak detection systems,
• spill prevention and loss control systems,
• weather protection, and
• operating procedures, maintenance practices, and inspection programs to maintain the
containment systems, as well as associated documentation and record retention
1.3 Storage Jurisdictional Overview
In Alberta there is no single jurisdiction that regulates the storage of all materials.
Jurisdictions that are involved with various aspects of storage include the Alberta Energy
and Utilities Board (EUB), Alberta Municipal Affairs (AMA), and Alberta Environment
(AENV).
With respect to Guide 55, the term “upstream petroleum” is intended to apply to facilities,
well sites, and pipelines licensed or approved by the EUB for the exploration, production,
recovery, handling, processing, treatment, disposal, or transmission of hydrocarbon based-
resources or any associated substances or wastes, but does not include oil sands mining
operations or the underground cavern storage of natural gas. The licensee or approval
holder of an upstream petroleum site is responsible for all activities occurring on its site,
including any incidents that occur during an activity/operation provided by a service
company. The site on which the service company resides typically is not under the
jurisdiction of the EUB, unless the service company is conducting an activity/operation on
the site that requires EUB approval (e.g., oilfield waste management). Therefore, in almost
all situations the storage of materials in tanks, containers, or other devices on a service
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 1
company’s site is under the jurisdiction of AMA, AENV, or perhaps even the local
authority (local by-laws and/or conditions specified in the development permit for the site)
or a combination thereof. See Appendix 1 for a glossary of storage terms.
AMA administers the Alberta Fire Code (AFC), which applies throughout Alberta and
regulates the storage, handling, use, and processing of flammable and combustible liquids
in buildings, structures, and open areas. The Petroleum Tank Management Association of
Alberta (PTMAA) has been delegated the responsibility for administering specific
portions of the AFC, including the registration of storage tank systems containing
flammable or combustible liquids. The AFC delineates the jurisdiction between upstream
raw exploration and production processes and the downstream use of refined products.
Specifically, Part 4 of the AFC does not apply to the storage and handling of raw
production flammable or combustible liquids and the incidental storage and handling of
hydrocarbon-based chemicals resulting from or used during crude oil or natural gas
exploration, production, or transmission, as mandated under the scope of Guide 55.
Where upstream petroleum sites use refined fuels for supplying vehicles, aircraft,
emergency generators, or other similar equipment, then the storage and handling of these
fuels in storage tanks, containers, or other devices are subject to the requirements of Part 4
of the AFC. In addition, storage tank systems for refined product use in these situations are
subject to tank registration through the PTMAA.
AENV regulates the storage of materials produced, generated, and used in activities or at
facilities subject to notification, registration, or approval as specified in the Activities
Designation Regulation under the Environmental Protection and Enhancement Act
(EPEA). In situations where an upstream petroleum facility requires both EUB and AENV
approval, Guide 55 sets the minimum storage requirements, while additional requirements
may be specified in the AENV approval.
1.4.1 Facilities Operating Prior to January 1, 1996
As outlined in Appendix 2 approval holders or licensees of upstream petroleum facilities,
well sites, and pipelines constructed and operating prior to January 1, 1996, are reminded
that they are required to
• reverify the integrity of aboveground and underground tanks at the frequency outlined
in Appendix 2 or retrofit them to meet the secondary containment and leak detection
• comply with the requirements for containers, lined earthen excavations, and bulk pads.
1.4.2 Facilities Constructed on or after January 1, 1996
Upstream petroleum facilities, well sites, and pipelines constructed between January 1,
1996, and January 1, 2002, are expected to have met the storage requirements outlined in
the 1995 edition of Guide 55. Subsection 1.4.3 highlights the changes introduced in this
2001 edition of Guide 55, while Subsection 1.4.4 outlines implementation dates for new or
revised storage requirements. For facilities, well sites, and pipelines that have
2 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
implemented storage options that are to be discontinued, see Appendix 2 for further
1.4.3 Changes to Guide 55
The changes made to Guide 55 include
• clarification of secondary containment requirements for small tanks (Section 5.1 and
Appendix 2, parts 2, and 2.3) and containers (Section 7 and Appendix 2, parts 2 and
• addition of requirements for the storage of produced water from shallow, low-pressure
gas wells in the Milk River, Medicine Hat, and Second Whites Specks pools in open-
topped, nonmetallic tanks (Section 5.2);
• minor adjustment of dike capacity (Section 5.3.2.1[a]);
• addition of requirements for double-walled aboveground tanks (Section 5.3.3);
• removal of the option to use single-walled underground tanks (Sections 1.4.4 and 6
and Appendix 2, parts 1 and 2.2.1);
• removal of the option to use concrete as primary containment in situations where
liquids are being stored or where there is potential for leachate to be generated
(Sections 1.4.4, 8, and 9 and Appendix 2, parts 1 and 2.3);
• consistent monitoring frequency (monthly) of all leak detection systems (Sections
1.4.4, 5, 6, 7, 8, and 9 and Appendix 2, parts 2.1.2, 2.1.3, 2.1.4, 2.2.1, and 2.3);
• clarification of the criteria for the surface discharge of collected surface run-on/runoff
waters (Section 11);
• addition of procedures to follow for the withdrawal of storage tanks from service
(Section 12);
• further information on liner specifications (Section 13);
• clarification of the frequency for repeating integrity verification tests and/or
inspections of aboveground and underground tanks and lined earthen excavations
installed prior to January 1, 1996 (Appendix 2, parts 2.1.2, 2.2.2, and 2.3); and
• further information on the types of integrity verification tests available for
aboveground and underground tanks (Appendix 2, Tables A1, A2, and A3).
1.4.4 Implementation Dates for New/Revised Requirements
As of January 1, 2002, the following requirements shall be effective:
• Any storage device installed shall meet the requirements presented in the 2001 edition
of Guide 55.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 3
• The frequency for the monitoring of all leak detection systems associated with all
storage devices shall be monthly.
• The use of single-walled underground tanks where a synthetic liner or the natural
impermeable soil conditions (i.e., hydraulic conductivity of 10-6 cm/s or less) are used
as secondary containment will no longer be allowed. Any such systems installed
between January 1, 1996, and January 1, 2002, must meet the requirements outlined in
• The use of concrete-lined earthen excavations with an underlying leakage monitoring
system (no secondary containment) and the use of concrete as primary containment for
lined earthen excavations or for bulk pads where there is potential for the stored
materials to generate a leachate will no longer be allowed. Any such systems installed
prior to January 1, 2002, must meet the requirements of Appendix 2.
For upstream petroleum facilities, well sites, and pipelines that were constructed and
operating prior to January 1, 1996, approval holders or licensees have until October 31,
2004, to meet the secondary containment requirements, as outlined in Section 5.3 for small
aboveground storage tanks exceeding the total combined volume of 5 m3 per site. For
further details, see Appendix 2, Section 2.3.
This 2001 edition of Guide 55 requires
• aboveground storage tanks with an interval volume of 5 m3 or greater to have
secondary containment consisting of a dike and liner system or to be double-walled;
• underground storage tanks to be doubled-walled;
• small aboveground storage tanks (interval volume between 1 m3 and 5 m3) that exceed
a total combined volume of 5 m3 per site to have secondary containment or be double-
walled;
• containers (portable storage devices that do not exceed 1 m3 in volume) that exceed a
total combined volume of 1 m3 per site to have secondary containment;
• all lined earthen excavations to have secondary containment;
• bulk pads storing materials that may generate a leachate to have leak detection
• monthly monitoring of all leak detection systems, including visual and interstitial
space monitoring, associated with aboveground and underground tanks, containers,
lined earthen excavations, and bulk pads;
• monitoring and inspection information to be retained for a minimum of 5 years.
Licensees and approval holders are directed to Tables 2 and 3 on pages 18 and 19 and to
the appropriate section of Guide 55 that sets out the specific requirements for the storage
devices identified above.
4 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
2.1 Guide 55 Overview
Guide 55 outlines the minimum storage expectations that the upstream petroleum industry
must meet. The implementation of storage systems alternative to the ones described within
this guide requires EUB approval, as outlined in Section 2.5. For information pertaining to
the application, approval, or licensing of upstream petroleum developments, refer to the
following EUB documents:
• Guide 56: Energy Development Application Guide—covers oil/bitumen and gas
batteries, satellite batteries, gas processing facilities, straddle gas plants, compressor
stations, custom treating plants, injection/disposal facilities, pump stations, tank
farm/oil loading and unloading terminals, pipelines, and wells.
• Guide 58: Oilfield Waste Management Requirements for the Upstream Petroleum
Industry—covers oilfield waste management facilities and oilfield waste storage areas
constructed on an upstream petroleum facility for the purpose of collecting oilfield or
oily wastes from sites within the same production system
• Guide 23: Guidelines Respecting an Application for a Commercial Crude Bitumen
Recovery and Upgrading Project, Informational Letter (IL) 85-12: Oil Sands Primary
Production: Well Spacing Primary Recovery Scheme Approvals, and the Oil Sands
Conservation Act and Regulations—covers oil sands developments
The storage requirements in Guide 55 apply to upstream petroleum facilities, well sites,
and pipelines licensed or approved by the EUB, including
• well sites,
• gas batteries (single and multiwell),
• oil/bitumen batteries (single and multiwell),
• oil/bitumen satellites,
• custom treating plants,
• compressor stations,
• straddle plants,
• gas processing/fractionating facilities,
• pump stations,
• tank farms/oil loading and unloading terminals, and
• oilfield waste management facilities.
Note that Guide 55 does not apply to oil sands mining operations or to the underground
cavern storage of natural gas.
For those facilities that also require an approval from Alberta Environment (AENV) (e.g.,
sour gas plants, compressor stations, some in situ oil sands facilities), storage requirements
may also be specified in the AENV approval. The AENV requirements are generally
consistent with the requirement in Guide 55.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 5
2.2 Containment Devices
Containment devices addressed by this guide include
• aboveground tanks (single walled and double walled),
• underground tanks,
• lined earthen excavations, and
• bulk pads.
2.3 Applicable Material Types
Any material that could adversely affect the environment and is produced, generated, or
used on upstream petroleum sites under the jurisdiction of the EUB must be stored in
accordance with these requirements. Applicable material types (as noted below and in
Table 1) include, but are not limited to,
• produced water,
• crude oil,
• emulsions,
• condensates (C5+, nonpressurized storage),
• produced sand,
• lubricants other than for motor vehicle use,
• oilfield wastes,
• oily waste, and
2.4 Excluded Material Types and Storage Systems
The storage requirements for the following materials are currently addressed by other
requirements, regulations, or standards (as noted below and in Table 1) and are therefore,
not covered by these requirements:
• natural gas liquids (C2 to C4, pressurized storage),
• fuels, refined flammable liquids, and combustible liquids,
• sewage,
• scrap metal,
• sulphur,
• collected surface run-on/runoff waters (see Section 11 for surface discharge criteria),
• garbage,
• construction materials, and
• lime sludge (pond storage).
Note that lime sludge being stored in a cell system that is part of a landfill on an upstream
petroleum site must be designed, operated, and approved as an oilfield landfill (see Guide
58). However, lime sludge ponds at in situ oil sands plants are covered by EPEA
6 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Table 1. Summary of requirements applicable to oilfield material storage
Material stored Applicable Further reference
Bitumen Yes
Blowdown water from shallow gas operations Yes EUB IL 99-5
Coke No EUB IL 96-7
Condensate (C5+, nonpressurized) Yes
Construction debris No Oil and Gas Conservation Regulations, Section
8.150(6)1 and Guide 58
Crude oil/bitumen Yes
Drilling fluids No Oil and Gas Conservation Regulations, Section
8.150(3)2 and (4)2
EUB IL 96-13, Guide 50
Emulsions Yes
Fuels No Alberta Fire Code, Petroleum Tank
Management Association of Alberta
Garbage No EPEA, Waste Control Regulations, Code of
Practice for Landfills
Lubricants (motor vehicle) No Alberta Fire Code
Lubricants (nonmotor vehicle) Yes
Liquefied petroleum gas (LPG) No CSA International B 149.2-00, Propane Storage
and Handling Code
Natural gas (NG) C2 to C4 in pressurized storage No CSA International B 149.1-00, Natural Gas and
Propane Installation Code
Natural gas in underground cavern storage No EUB Guide 65
Oil sands tailings No EUB IL 96-7, EUB Guide 23
Oilfield wastes Yes Guide 58
Pipeline drip fluids No Canadian Standards Association Oil and Gas
Pipeline Standards, Z662-94
Produced sand Yes Guide 58
Produced water Yes Guide 51, Guide 58
Scrap metal No Oil and Gas Conservation Regulations, Section
Sewage No EPEA, Wastewater and Storm Drainage
Regulation; Domestic Wastewater Management
Guidelines for Industrial Operations, AENV
Solvents Yes
Sulphur No EUB IL 84-11, GB 92-4, EUB IL 96-7
Lime sludge-surface pond/oil sands site No EPEA approval
-landfill cell Yes EUB Guide 58
1 Proposed changes to the Oil and Gas Conservation Regulations are in progress. Upon publication of the changes, the requirements
currently in Section 8.150(6) will be found in Section 8.150(4).
2 Proposed changes to the Oil and Gas Conservation Regulations are in progress. Upon publication of the changes, the requirements
currently in Section 8.150(3) and (4) will be found in Sections 8.151 and 8.152.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 7
Aboveground and underground pressurized vessels that are part of an active production
process (e.g., flare knockouts and amine surge/drain tanks) and pipeline drip vessels are
not within the scope of these requirements provided that they have been designed for a
working pressure of 103.4 kilopascals (kPa) (15 pounds per square inch [psi]) and are
registered with the Alberta Boilers Safety Association (ABSA). All aboveground and
underground nonpressurized storage vessels not registered ABSA are subject to these
Tornado systems or other positive pressure systems used as a product stabilizer/
accumulator are considered a process vessel and not a conventional storage tank and,
therefore, are not required to meet the secondary containment requirements outlined in
Guide 55.
For storage of fuels (e.g., diesel and gasoline) in aboveground and underground storage
tanks, refer to the Alberta Fire Code, Part 4. These storage tanks also require registration
with the PTMAA.
For storage of natural gas (NG) and liquefied petroleum gas (LPG), see
• CSA International B 149.1-00, Natural Gas and Propane Installation Code, and
• CSA International B 149.2-00, Propane Storage and Handling Code.
The underground cavern storage of natural gas is covered under Section 26(1)(b) of the
Oil and Gas Conservation Act and Unit 4.3 of Guide 65: Resources Application for
Conventional Oil and Gas Reservoirs.
The storage of sulphur on upstream petroleum sites must conform to the requirements of
IL 84-11: Approval, Monitoring, and Control of Sulphur Storage Sites.
2.5 Alternative Storage Systems
The provisions of this guide are intended to permit the use of alternative storage systems if
it can be shown that the materials, systems, equipment, procedures, or new technologies
can meet the objectives and intent of the requirements described in the guide.
Approval holders or licensees wishing to implement storage systems alternative to the
requirements outlined in this guide must include the design details in the application for
the upstream petroleum development (either an application for a new development or for a
modification to an existing one). The application must contain sufficient information to
substantiate that an equivalent level of environmental protection and safety will be
achieved by the proposed storage system. If the application is made pursuant to Guide 56,
then it must be filed as nonroutine.
8 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
3 General Storage Practices and Requirements
3.1 Environmental Protection and Safety Practices
Any material produced, generated, or used by the upstream petroleum industry that may
cause an adverse effect if introduced into the environment must be stored in a manner that
meets the intent of these requirements. In addition to the specific measures addressed in
Sections 5 to 9, the following environmental protection and safety practices should be
• Selecting a storage site that minimizes the potential for environmental concerns.
• Implementing operating procedures, maintenance practices, and inspection programs
to maintain the integrity of the primary containment device and any associated
equipment such as valves, fittings, piping, or pumps.
• Implementing operating practices to prevent the buildup of static electricity during the
transfer of flammable liquids.
• Storing the materials in a manner such that
a) materials do not generate extreme heat or pressure or cause a fire or explosion,
b) materials do not produce uncontrolled fumes or gases that pose a risk of fire or
c) materials do not damage the structural integrity of a storage facility, and
d) incompatible materials are segregated to prevent contact even in the event of a
3.2 Release/Spill Prevention
The purpose of this guide is to ensure that materials stored in the upstream petroleum
industry are adequately contained to prevent soil, surface water, and groundwater
contamination through effective primary containment, secondary containment, and leak
detection. Experience has shown that when these prevention systems are in place, the next
most significant contributor to contamination is accumulated releases/spills.
While often small in nature (less than the release volumes that require reporting under
EUB requirements), these releases/spills may occur for a variety of reasons, such as load
line connection spills, tank overflows, truck overfilling, and flange, valve, and fitting
leaks. The occurrence of these types of releases/spills are an indication of opportunities for
improvements in operations.
Approval holders or licensees should include within their operating procedures proactive
measures to prevent the occurrence of these releases, such as plans and policies to prevent
releases, as well as documentation of their frequency and the cause of occurrence in order
to determine the overall program effectiveness. These measures should include contracted
services, as contractors are often responsible for the loading operations that may result in
intermittent releases. Some of the measures that have proven to reduce release volumes
and frequency include
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 9
• company inspection and maintenance programs,
• company operations handbooks/environmental bulletins,
• operator and contractor training on company expectations and reporting,
• contractor prejob orientations,
• detailed records (internal spill/incident reports), and
• a database of incidents to allow for analysis of spill cause and frequency.
Measures that prevent spills and releases are the most effective in terms of both cost and
environmental protection. This is recognized by Section 8.050 of the Oil and Gas
Conservation Regulations, which requires all spills to be immediately contained, cleaned
up, and reported to the appropriate agency, and Section 8.150(6)∗, which requires well
sites and facilities to be maintained in a clean condition. Failure to meet these
requirements is considered a noncompliance event and will result in escalating
consequences if not satisfactorily addressed. For further information pertaining to the EUB
enforcement process or release notification and site decontamination requirements, refer to
the following EUB informational letters:
• IL 99-4: EUB Enforcement Process, Generic Enforcement Ladder, and Field
Surveillance Enforcement Ladder,
• IL 98-1: Coordination of Release Notification Requirements and Subsequent
Regulatory Response, and
• IL 98-2: Suspension, Abandonment, Decontamination, and Surface Land Reclamation
of Upstream Oil and Gas Facilities.
In the interest of increased public safety and environmental protection, materials shall not
be stored indefinitely:
• Materials are expected to be consumed within a period of two years.
• Oilfield wastes and empty barrels must not be stored for longer than one year.
In the majority of cases, products, materials, and wastes will usually move through the
production system in less time. Where necessary, procedures should be implemented to
minimize the inventory of empty barrels stored at the upstream petroleum site.
3.4 Permanent Storage
Permanent storage refers to the storage of materials produced, generated, or used by the
upstream petroleum industry in a device that is a permanent, fixed part of an operating
facility. Such devices may include
• aboveground tanks,
• container storage areas,
Proposed changes to the Oil and Gas Conservation Regulations are in progress. Upon publication of the changes,
the requirements currently in Section 8.150(6) will be found in 8.150(4).
10 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
3.4.1 Permanent Storage Devices Not Requiring Secondary Containment
The following storage devices are not required to meet the secondary containment
requirements outlined in Sections 5 and 6:
• aboveground or underground tanks used to store water meeting surface water
discharge criteria (see Section 11 for surface discharge criteria),
• small tanks with a total combined volume not exceeding 5 m3 on a site (see Section
• open-topped, nonmetallic tanks with an internal volume less than 30 m3 used to store
produced water from only the Milk River, Medicine Hat, or Second White Specks
pools (see Section 5.2), and
• storage devices (aboveground or underground) used to infrequently store fluids for
very short durations, provided they are emptied immediately after use and are
regularly inspected to verify their integrity. Examples include
pop tanks and other emergency containment tanks,
compressor oil drain tanks,
wash water collection systems from floor drains, and
pigging fluid catchment devices.
Note that any spill, leak, or discharge from storage devices used infrequently must be
recorded as part of the monthly documentation requirements, along with any corrective
action that was undertaken to prevent the recurrence of a similar release.
If the characteristics of the site (e.g., topography, hydrogeology, and geology) are such
that the risks associated with surface water contamination, subsurface contaminant
migration, and impact to groundwater are high, leak detection and secondary containment
are required for any storage device regardless of its usage frequency.
3.5 Temporary Storage
Temporary storage refers to the storage of materials produced, generated, or used in
specific operations of the upstream petroleum industry and should typically not exceed
three months. Specific operations associated with temporary storage are
• plant turnarounds,
• construction operations,
• containment and cleanup of a spill,
• emergency conditions, and
• well drilling, completions, testing, and servicing operations (e.g., portable test tanks).
Temporary single-walled aboveground tanks used to store fluids in the above-cited
operations do not require an impervious liner; they do require diking unless the operation
qualifies for it to be optional. Diking is optional in situations where
• the site is manned for the duration that fluids are being produced into the tank,
• the tank is fitted with a high-level shutdown device to prevent fluids from
overflowing, or
• the fluids are not being produced to the tank, but are simply being stored.
Approval holders or licensees exercising the option to not dike a tank for well drilling,
completions, testing, or servicing operations must empty the tank or remove it from the
site within 72 hours of completing the operation. Approval holders or licensees must use
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 11
reasonable judgement to ensure that environmentally sensitive areas are protected and as
such should not consider the option to not dike a tank when it is located close to a water
The temporary storage of sludges or solids (e.g., contaminated soil, spill debris, oily
waste, drilling waste) from the above-listed operations in steel-fabricated, solids-storage
bins (e.g., lugger bins, drilling rig tanks) does not require diking or secondary
It is expected that temporary storage will meet the intent of these requirements to
minimize environmental impact and ensure public safety. Even in temporary storage
situations, contaminated materials or materials possessing the potential to leach must not
be stored directly on the ground. At the end of the specific operation, the stored materials
must be transferred to a permanent storage facility/area or be appropriately treated and/or
disposed. Application for the approval of temporary storage is not required.
Production batteries used for a temporary period of 12 months or less are not
required to install impervious liner systems. However, the equipment spacing and
diking requirements must be met.
3.6 Siting
Siting considerations must be incorporated into the design of storage areas/facilities. A
storage area/facility must be located so that it meets the following criteria:
• Readily accessible for fire fighting and other emergency procedures.
• Not located in a floodplain, unless appropriate alternative secondary containment
measures are incorporated into the design and installation.
• Chosen so as to minimize the risk of environmental damage, including any threats to
the integrity of the storage facility, the quality of soils, surface water, and
groundwater, and the health of humans, animals, and plants during the construction,
operation, and closure of the storage area/facility.
• Not located within 100 m of the normal high-water mark of a body of water,
permanent stream, or water well used for domestic purposes.
It is recognized that when temporary storage is associated with emergency situations,
fully implementing the above criteria may not be feasible.
3.7 Equipment Spacing
All storage areas/facilities must comply with the equipment spacing requirements
identified in the Oil and Gas Conservation Regulations, Sections 8.030(2), 8.080(2),
and 8.090 (see Figure 1).
12 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
1 The spacing requirements illustrated here are as specified in the Oil and Gas Conservation Regulations sections indicated
within square brackets alongside or underneath each measurement.
Note that there is no smoking within 25 m of a well, separator, oil storage tank, or other unprotected source of ignitable vapour
[Section 8.120(1)].
2 Treaters and heaters without flame arresters are not to be housed in the same building unless air intakes, flues, vents, ignitable
vapours, etc., are vented outside above roof level and the building is cross-ventilated [8.090(6)a,b,c]. Treaters and heaters with
flame arresters must also be 25 m from a well, oil storage tank, or other source of ignitable vapour [8.090(4)].
3 “Surface improvement” means a railway, pipeline or other right-of-way, road allowance, surveyed roadway, dwelling, industrial
plant, aircraft runway or taxiway, building used for military purposes, permanent farm building, school or church [1.020(1)28].
Figure 1. Equipment Spacing Diagram
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 13
The following exceptions to the equipment spacing regulations are allowed for by
ID 91-3: Heavy Oil/Oil Sands Operations:
• No open flame shall be permitted within 25 m of a heavy oil/oil sands well, storage
tank, or other source of ignitable vapour, including Board-approved desand and oily
waste storage facilities.
• No oil storage tanks or desand and oily waste storage facilities may be located within
25 m of a heavy oil/oil sands well.
• Diesel engines operating within 25 m of an oil sands/heavy oil well, process vessel, or
production storage tank must be equipped with an adequate air intake shutoff valve.
3.8 Identification of Storage Facilities
All stand-alone storage facilities shall have signs, as per section 6.020 and Schedule
12 of the Oil and Gas Conservation Regulations, at the entrance to the facility
indicating the approval holder or licensee name, emergency phone number, and legal
description (see Figure 2). Within a storage facility and at storage areas that form part
of an operating upstream petroleum site, signs should indicate the materials that are
stored, warnings, and any general housekeeping practices that should be followed in
the storage area (e.g., segregation).
3.9 Compliance and Enforcement
The EUB considers compliance with the storage requirements outlined in this guide to be
extremely important in preventing soil, groundwater, and surface water contamination at
upstream petroleum sites. The EUB uses a combination of audits and inspections to ensure
compliance with all EUB regulatory requirements, including the storage requirements,
outlined in this guide. The following audits and inspections include a component to check
for compliance with Guide 55:
• facility application audits pursuant to Guide 56: Energy Development Application
• oilfield waste management facility audits pursuant to Guide 58: Oilfield Waste
Management Requirements for the Upstream Petroleum Industry,
• drilling rig inspections pursuant to Guide 36: Drilling Rig Inspection Manual,
• service rig inspections pursuant to Guide 37: Service Rig Inspection Manual,
• oilfield waste management facility inspections pursuant to Guide 63: Oilfield Waste
Management Facility Inspection Manual,
• production facility inspections pursuant to Guide 64: Facility Inspection Manual, and
• pipeline inspections pursuant to Guide 66: Pipeline Inspection Manual.
14 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Figure 2. Facility Identification and Warning Signs (from Schedule 12 in Oil and Gas Conservation
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 15
Failure to comply with Guide 55 requirements may result in enforcement actions. The
inspection manuals, which are revised as necessary when regulatory expectations are
introduced or updated, list specific noncompliant items and identify each item as being a
minor, major, or serious noncompliant event. Noncompliance is managed in accordance
with the EUB’s enforcement ladders, which are based on a concept of escalating
consequences for repeated noncompliance. For further information, see EUB
Informational Letter (IL) 99-4: EUB Enforcement Process, Generic Enforcement Ladder,
and Field Surveillance Enforcement Ladder and IL 99-4 Clarification.
16 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Storage requirements for materials produced, generated, and used by the upstream
petroleum industry are based on concern about
• the type of material being stored,
• the volume of material being stored,
• the environmental sensitivity of the site where material is being stored,
• the length of time the material is stored, and
• the nature and integrity of the primary containment device.
The following sections outline the primary containment, secondary containment, and leak
detection requirements for aboveground storage tanks, underground storage tanks,
containers, lined earthen excavations, and bulk pads.
Table 2 presents a summary of the general storage requirements for the above-
mentioned containment devices.
Table 3 presents a summary of the inspection, monitoring, and record-keeping
requirements applicable to the containment devices described in this guide.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 17
Table 2. General requirements for containment devices1
Primary containment Section in
device/size2 Guide 553 Design and construction Secondary containment Leak detection Weather protection
Aboveground tank 5.1 Supplier specifications. Not required. Monthly visual inspection. External weather-protective coating or made
(1-5 m3)4 Nonleaking hoses, fittings, and nozzles. from a weather-resistant material.
Spill control devices.
Aboveground open-topped 5.2 Supplier specifications. Not required. Monthly visual inspection. Not applicable.
nonmetallic tanks (<30 m3) Integrity verified every 5 years.
Single-walled aboveground 5.3.1 Cathodic protection in corrosive Graded containment area. Monthly visual inspection. External weather-protective coating or made
tank (>5 m3)4 5.3.2 environments. Dike (or curbing for indoor tanks) capacity Sand over liner and leakage from a weather-resistant material.
External coating for steel tanks and internal 110% of tank or 100% of largest tank plus collection area.
coating in corrosive environments. 10% of aggregate volume if more than one
Spill control devices. tank.
Impervious liner.
Double-walled aboveground 5.3.1 Cathodic protection in corrosive Double walls with interstitial space. Monthly monitoring of interstitial External weather-protective coating or made
tank (>5 m3)4 5.3.3 environments. space. from a weather-resistant material.
External coating for steel tanks and internal
coating in corrosive environments.
Spill control devices including overfill
Underground tank4 (any 6 Integrity testing of tank and piping prior to Double walls with interstitial space. Monthly monitoring of interstitial Not applicable.
size); includes tanks and servicing. space.
sumps) External coating and cathodic protection for
Possible internal coating.
Container or group of 7 Not applicable. Not required. Monthly visual inspection. Not required.
containers (≤1 m3 total)
Container or group of 7 Compatibility between container and stored Dike, curb, and/or collection tray with a Monthly visual inspection. Physical cover (e.g., covered container or roof)
containers (>1 m3 total) materials. capacity of 100% of largest container or 10% or protective coating.
Segregated areas. of aggregate volume, whichever is greater.
Lined earthen excavation 8 Specific to facility. Impervious liner. Weeping tile. Specific to facility and material type.
Spill control devices. Monitoring well.
Bulk pad (solid material) 9 Specific to facility. Impervious liner. Specific to material type. Specific to facility and material type.
Containment curb or dike.
1 Applies to new storage facilities constructed and operated after January 1, 2002. Applies to the permanent storage of produced water, crude oil, emulsions, condensates, chemicals, solvents, produced sand, lubricants
other than for motor vehicle use, oilfield wastes, oily waste, and bitumen. Maximum storage duration should not exceed 2 years, except for oilfield wastes which should not exceed 1 year. All inventory records must be kept
for 2 years. All leak-detection monitoring results must be kept for 5 years.
2 Internal volume.
3 See Guide 55 section cited for more detailed information.
4 Tank requirements apply unless the fluids being stored are waters that meet the surface discharge criteria (chloride < 500 mg/litre maximum; pH 6.0 to 9.0; no visible hydrocarbon sheen; and no other chemical
contamination) or are fluids that are infrequently stored in tanks and the tanks are emptied immediately.
18 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Table 3: A summary of inspection, monitoring, and record-keeping requirements
General Aboveground storage tanks Underground storage tanks Container storage areas Lined earthen excavations Bulk pads
• Field test retained surface • Monthly external visual inspection of • Monthly interstitial space • Monthly external visual • Monthly monitoring of leak • If storing materials
waters prior to discharge for Cl tank and diked area (Table 2, Section monitoring for double wall inspection (Table 2, detection system (Table 2, that may generate
(<500 ppm), pH (6-9), no visible 5.3.2.2). tanks (Table 2, Section 6.2). Section 7.2). Section 8.2). leachate, see
sheen, no chemical • Integrity verified every 5 years (if • Integrity verified every 3 - Field test any collected Section 8.2.
contamination, landowner installed prior to 1996 and >5 m3 or a years (if single wall tank and liquids for pH, Cl,
consent, no release to water tank under Section 5.2) (Table 2). installed prior to 1996) hydrocarbon odour, and
(Section 11). • Monthly interstitial space monitoring (Table 2). visible sheen. If any
for double wall tanks (Table 2) unless • Monthly monitoring of problems encountered,
equipped with a continuous monitor monitoring wells associated send to lab for analysis.
(Section 5.3.3). with single wall tanks with • Annual lab sample from leak
• Alternative inspection frequencies secondary containment. Field detection liquids for pH, EC,
allowed as per Section 4 of API test any liquids for pH, Cl, major ions, oil and grease, and
Standard 653 (Section 5.3.2.2). hydrocarbon odour, and any other parameter at EUB
visible oil sheen (Appendix discretion (Section 8.2).
• Maintain inventory records for • Maintain tank inspection • Maintain tank inspection • Document abnormal • Maintain monitoring results • If storing materials
wastes and chemicals for 2 records/results for 5 years, but records/results for 5 years, circumstances from (including field and laboratory that may generate
years (Section 10). preferably for the lifetime of the tank but preferably for the lifetime monthly visual analytical results) and any leachate, see
• Maintain groundwater (Section 10). of the tank (Section 10). inspections and retain for subsequent corrective actions Section 8.2.
monitoring records for 5 years, • Maintain corrosion monitoring records • Maintain corrosion 5 years (Section 7.2). from leak detection systems for
but preferably for the lifetime of for 5 years, but preferably for the monitoring records for 5 5 years (Section 10).
the facility (Section 10). lifetime of the tank (Section 10). years, but preferably for the • EUB notification required if
• Maintain alternative leak • Document abnormal circumstances lifetime of the tank (Section contamination found in leak
detection records (e.g., vapour and corrective actions from monthly 10). detection system. Report must
surveys, EM surveys) for 5 visual tank and dike inspections and • Document abnormal include 1) the parameters that
years, but preferably for the retain for 5 years, but preferably for circumstances and corrective changed, 2) investigative work
lifetime of the facility (Section the lifetime of the tank (Section 10). actions from monthly conducted, 3) remedial work
10). • Document abnormal circumstances interstitial monitoring of proposed (Section 8.2).
• Maintain copies of all required and corrective actions from monthly double wall tanks and retain
approvals, licences, interstitial monitoring of double wall for 5 years, but preferably for
registrations, and permits on tanks and retain for 5 years, but the lifetime of the tank
site or at the Field Centre preferably for the lifetime of the tank (Section 10).
(Section 10). (Section 10). • Maintain monthly monitoring
• Maintain names of all persons well results and any
conducting inspection and corrective actions from single
monitoring programs (Section wall tanks with secondary
10). containment (Appendix
• Maintain records of surface 2.2.1).
water discharges, including pre-
release field test results and
volume released (Section 11).
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 19
5 Requirements for Aboveground Storage Tanks
Aboveground storage tanks must be constructed from suitable metallic or nonmetallic
materials capable of containing the stored materials (e.g., steel-welded and/or skid-
mounted tanks, plastic totes or slips, or fibreglass-reinforced plastic tanks). Bolted tanks
are not a preferred containment device for new installations. Aboveground storage tanks
with an internal volume less than 1 m3 are considered to be containers (see Section 7,
Storage Requirements for Containers).
5.1 Aboveground Storage Tanks with an Internal Volume Less Than 5 m3
Aboveground storage tanks with an internal volume greater than 1 m3 but less than 5 m3
(e.g., mounted methanol/glycol/chemical tanks) must
• be visually inspected on a monthly basis to verify their integrity,
• have operable and nonleaking fittings, nozzles, and hoses,
• have preventive measures implemented to avoid spills and leaks at fluid transfer
points (e.g., piping, flanges, valves), and
• be either externally coated (e.g., painted, galvanized steel) or made from a weather-
and corrosion-resistant material (e.g., plastic, fibreglass).
Upstream petroleum sites can store a total combined volume of 5 m3 per site of fluids in
small tanks without secondary containment. However, nonvisual leak detection and
secondary containment provisions should be considered if a release or spill could not be
contained on site or if a spill or release could reasonably be expected to present a risk to a
stream, water body, or groundwater or cause other environmental concerns.
Small tanks exceeding the total combined volume of 5 m3 per site require secondary
5.2 Aboveground Open-Topped, Nonmetallic Tanks with an Internal Volume Less Than 30 m3
The storage of produced water from shallow, low-pressure gas wells in only the Milk
River, Medicine Hat, or Second Whites Specks pools is allowed in open-topped, non-
metallic tanks, provided the tank volume is less than 30 m3. These types of containment
devices are made of a thick synthetic material and do not require secondary containment
and leak detection. These tanks must be visually inspected monthly and be verified for
integrity every five years.
In the spirit of continuous improvement, EUB IL 99-5: The Elimination of the Surface
Release of Produced Water ended the exemption that allowed shallow gas producers in
the southeastern portion of Alberta to release produced fluids and solids to the well-site
surface. This was previously allowed in IL 93-10: Revised Measurement and Accounting
Procedures for Southeastern Alberta Shallow Gas Wells. As per IL 99-5, approval
holders or licensees of shallow gas wells are to have appropriate storage and disposal
systems for produced water in place as of September 30, 2000. The exemption from
produced water reporting requirements, as per IL 93-10, for qualified wells remains.
20 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
5.3 Aboveground Storage Tanks with an Internal Volume Equal to or Greater Than 5 m3
Aboveground storage tanks with an internal volume of 5 m3 or greater (except as detailed
in Section 5.2) and small tanks exceeding the total combined volume of 5 m3 (as outlined
in Section 5.1) must meet the construction, leak detection, secondary containment,
weather protection, and spill control provisions outlined in the following subsections.
General construction and installation factors for aboveground storage tanks are as
• Tanks must be designed, fabricated, tested, and installed to applicable engineering,
manufacturing, and regulatory standards.
• Tanks must either be made from or externally coated with a weather-resistant
• Steel tanks must be externally coated (e.g., painted, galvanized), and if storing
corrosive liquids, they should be internally coated or lined to minimize corrosion. In
corrosive environments, it may be appropriate to apply cathodic protection to
aboveground steel tanks.
• Transfer lines and hoses must be compatible with the material being transferred and
shall have leak-proof connections.
• Spill control devices must be used around hose connections at fluid transfer points to
help prevent the contamination of soil, surface runoff water, and groundwater. Spill
control devices should include methods to
keep precipitation or other materials out of the spill control device,
prevent rusting and allow for easy inspection of their integrity (e.g., elevation
above ground level), and
recover any spilled or leaked fluids from the device.
• Tank loading and unloading areas must be designed to contain any spills or leaks.
• Sites must be appropriately contoured to prevent the collection of surface water on
the ground immediately surrounding the secondary containment system (e.g., tank
farm area).
• Tanks that have been withdrawn from service are permitted to be reused if they
comply with Section 12, Withdrawal of Storage Tanks from Service.
• Measures must be incorporated to prevent the overfilling of tanks. Examples include
automatic sensing devices for interconnection with shutoff equipment at the supply
point, automatic overfill shutoff devices of a float valve or other mechanical type,
vent restriction devices, and overfill alarm devices of the audible or visual type
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 21
(single-stage or two-stage activation), inventory control, and any other appropriate
measure that will prevent overfilling.
For further information regarding the construction and installation of aboveground tanks,
see Appendix 3: References—Construction Standards for Aboveground and Underground
5.3.2 Single-Walled Aboveground Tanks with an Internal Volume of 5 m3 or Greater
5.3.2.1 Secondary Containment
The area around a single-walled aboveground storage tank must have a secondary
containment system designed to contain leakage and prevent it from impacting the
surrounding environment. Secondary containment systems must consist of an impervious
liner and a dike. At in situ oil sands operations, if a conventional dike interferes with
operations (e.g., production trucking and tank clean-outs), the secondary containment
system must be lined and graded to collection area(s) so that the system meets the
capacity requirement of a conventional diked system, as outlined in Section 5.3.2.1(a).
The area within the secondary containment system must be graded to a sump or low-lying
area (within the diked area) to allow for the collection of rainwater, snow-melt water, and
any possible leakage from the tanks. No uncontrolled discharge of collected fluids or
discharge of untested fluids is permitted. (See Section 11 for surface water discharge
5.3.2.1(a) Dikes
A dike must
1) be constructed of soil, steel, concrete, solid masonry, or synthetic material and
designed to contain liquids within the diked area, to be able to withstand the
hydrostatic head associated with it being full of liquid, and so that it will not
deteriorate or develop leaks during the projected life of the structure;
2) be sized to have a volumetric capacity of not less than 110 per cent of the capacity of
the tank when the diked area contains one tank or when the diked area contains more
than one tank of not less than the sum of
a) the capacity of the largest tank located in the diked area, and
b) 10 per cent of the greater of
• the capacity specified in (a), or
• the aggregate capacity of all other tanks located in the diked area;
3) have no openings in it (e.g., dike drains to the surrounding area); and
4) be maintained in good condition. The area encompassed by the dike must be kept free
from weeds, debris, and extraneous combustible material.
22 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
5.3.2.1(b) Impervious Liners
A liner must meet the following criteria:
1) consist of a material that is inert to or compatible (chemically resistant) with the
material being stored in the tank;
2) be impervious (i.e., a compacted clay liner meeting the criteria specified in Section
13.1, a natural liner meeting the criteria specified in Section 13.2, or a synthetic liner
as described in Section 13.3);
3) be durable and appropriate for the operating and ambient conditions; and
4) cover the area within the dike, including the area beneath the tanks, and be keyed into
the dike walls.
5.3.2.2 Leak Detection
Approval holders or licensees must be able to demonstrate the integrity of their tanks and
verify whether any material has escaped. Leak detection methods for aboveground
storage tanks include the following:
• Incorporation of a layer of porous material, such as sand, over the liner and
underneath the tanks to provide protection to the liner and to allow any leakage to
move preferentially through the porous material to a collection area within the diked
• Monthly visual inspections of tanks and the surface of the diked area for evidence of
problems, damage, or leakage. Any spills or leaks must be cleaned up immediately
and reported if required (see IL 98-1), and corrective action must be initiated as
required. Abnormal circumstances and corrective actions must be documented.
Additional leak detection provisions may also include the incorporation of subliner
leakage detection devices (e.g., weeping tile system). Refer to Section 10 for record-
keeping information. Approval holders or licensees should also be aware of the
inspection frequencies referenced in Section 4 of API Standard 653.
5.3.2.3 Secondary Containment for Indoor Single-Walled Aboveground Storage
Indoor aboveground storage tanks must be surrounded by a containment device (e.g. an
impervious containment base and wall or curbing) and/or drain and collection tank that
has a capacity as described in Section 5.3.2.1(a)(2). Additional provisions of the Alberta
Fire Code may also apply.
5.3.3 Double-Walled Tanks (Internal Volume ≥5 m3)
A double-walled aboveground tank may be used as an alternative to a single-walled
aboveground tank using a secondary containment system consisting of a liner and a dike.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 23
Aboveground storage tanks with double walls must
• have the primary tank separated from the secondary containment so as to provide a
continuous interstitial space below and around the primary tank;
• be equipped with a method of overfill protection that incorporates an audible or
visual alarm that alerts the approval holder or licensee of a potential overfill
condition or an automatic shutoff mechanism to prevent the overflow of the primary
• be equipped with an effective spill control device at the fill/delivery connection;
• have a system to monitor the interstitial space between the tank walls (e.g., pressure,
vacuum, electronic, or vapour monitoring or manual sampling);
• be protected against damage from vehicular traffic (e.g., controlled access to the site,
bollards, guard rails, or concrete barricades);
• be equipped with a valve as close as practical to the tank to prevent draining of the
tank should a leak or break occur in the piping; and
• for systems designed with delivery connections at grade level (bottom load), be
equipped with provisions to allow the delivery hose to be emptied and with a drip
catchment device for the hose.
Approval holders or licensees must check the interstitial-space monitoring device at least
monthly to ensure that the tank system is not leaking and must document any abnormal
circumstances, as well as any corrective actions taken. Monthly checks may not be
required if the interstitial space is equipped with a continuous monitoring system that will
indicate when the primary or secondary tank is leaking. Automatic shutdown systems
must be checked monthly and maintained to ensure continuous functionality, and
documentation pertaining to this and any abnormal circumstances from the
monitoring/sampling of the interstitial-space must be retained and made available to EUB
Any spills or releases must be cleaned up immediately and reported if required (refer to
IL 98-1). As required, corrective action must be initiated and abnormal circumstances and
corrective actions must be documented. Refer to Section 10 for more detail on record
24 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
6 Requirements for Underground Storage Tanks
Since aboveground storage tanks are preferable to underground storage tanks, the
decision to install an underground storage tank must include sound justification, giving
consideration to environmental, safety, operational, and economic factors. Underground
tanks may be of any volume and may include steel, fibreglass-reinforced plastic, plastic
storage tanks, and drip collection devices. Receiving tanks for incoming trucked fluids at
oil sands cleaning facilities may also be considered as underground tanks.
General construction factors for underground storage tanks are as follows:
• Underground storage tanks must be double-walled, designed, fabricated, tested, and
installed to applicable engineering, manufacturing, and regulatory standards.
• Newly installed underground storage tanks and associated piping must be tested for
integrity as a complete system prior to placing in service.
• Steel tanks must have cathodic protection and an external coating to minimize
corrosion. An internal lining may be installed to prevent internal corrosion of an
underground storage tank, but by itself is not considered to be an acceptable
corrosion protection measure.
have leak-proof connections.
prevent rusting and to allow for easy inspection of their integrity (e.g., elevation
• Tank loading and unloading areas must be designed to contain any spills and leaks.
• Breathing vents must be designed to prevent the overflowing of fluids onto the
• Tanks that have been withdrawn from service are permitted to be reused where they
automatic shutoff devices, high-level alarms, two-stage alarms, visual indicators, and
any other measure that will prevent overfilling.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 25
For further information regarding the construction and installation of underground tanks,
6.2 Secondary Containment and Leak Detection
Approval holders or licensees must provide a secondary containment system that will
contain any leakage and prevent it from impacting the environment. Secondary
containment is achieved through the use of double-walled tanks that allow monitoring of
the interstitial space between the two walls.
The interstitial space of the double-walled tanks must be monitored monthly using
pressure monitoring, vacuum monitoring, electronic monitoring, vapour detection,
manual sampling, or an equivalent method. Any abnormal circumstances must be
documented, as well as any corrective actions taken. Any spills or releases must be
cleaned up and reported if required (refer to IL 98-1). Refer to Section 10 for more detail
on record keeping.
26 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
7 Storage Requirements for Containers
It is recognized that in some circumstances the storage of material in containers may pose
an environmental hazard due to the nature of the stored materials, the material quantity,
and the topography, hydrogeology, and surficial geology of the site. The following
requirements have been prepared to address these concerns and are applicable to the
storage of both solids and liquids in containers.
A container is considered a portable aboveground storage device that does not exceed 1
m3 in capacity. The total combined volume of containers without secondary containment
cannot exceed 1 m3 (e.g., approximately five barrels or five 45-gallon drums) on any site.
However, secondary containment should be considered if a release or spill could not be
stream, water body, groundwater or cause other environmental concerns.
All containers that exceed the total combined volume of 1 m3 require secondary
containment (e.g., five or fewer barrels on a site do not require secondary containment,
but for sites with more than five barrels, the number of barrels exceeding five require
secondary containment). Weather protection may also be appropriate to maintain the
integrity of the container. The type of secondary containment and weather protection
depends on the nature of the contained material, the type of container, and the design of
the storage compound.
7.1 Secondary Containment
Secondary containment systems for containers (e.g., dikes, curbs, and collection trays)
must be constructed of materials that are impervious to the materials being stored and
• be constructed of material that will not react with or absorb any material being stored
and that has no openings that may provide a direct connection to the ground
underneath or surrounding the primary container;
• have a net capacity greater than that of the largest container within the storage area or
10 per cent of the total volume of all containers in the storage area, whichever is
• be achieved through the proper use of at least one of the following devices:
storage compound that meets the secondary containment criteria for aboveground
storage tanks (e.g., impervious liner and dike; see Section 5.3.2.1(a)(2)),
storage building with curbing,
storage trailer,
metal and plastic bins,
overpacks, or
drip trays or spill pallets.
Storage trailers and buildings must include the following:
• clad structures with concrete floors and curbing that is a minimum height of 15 cm
and is placed on the perimeter of the floor in such a manner that the contained
material cannot escape between the floor and curb,
• clad structures with a containment floor,
• sealed shipping containers with a containment floor, and
• loading dock buildings with a containment floor.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 27
Design considerations for trailers and buildings must include the following:
• compatibility of the construction materials with the materials being stored,
• proper ventilation of vapour emissions from the materials being stored,
• compliance with fire and electrical codes,
• security measures or procedures to prevent unauthorized entry, and
• absence of floor drains directly connected to the outside.
7.2 Leak Detection and Weather Protection
Leak detection systems, other than visual leak detection, are not required for the storage
of containers, provided that the approval holder or licensee can demonstrate that a
container storage area is protected from the elements and/or has an appropriate secondary
containment system. Any abnormal circumstances must be documented.
Weather protection is intended to preserve the condition of the primary container and
hence the usefulness of the material contained therein. Weather protection is considered
to be a physical cover/coating over containers. As a result of this protection, the
containers and its contents are preserved. Secondary containment systems for containers
often are designed, or can be designed, to include provisions for protection from the
28 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
8 Requirements for Lined Earthen Excavations
The storage systems described below are typically used to
• store oily wastes (produced sand/slop oil) from in situ oil sands operations,
• receive oilfield wastes or store process solids at an oilfield waste management
• receive blowdown fluids from shallow gas wells.
Acceptable designs include
• earthen excavations with a primary containment device, an impervious synthetic liner
system for secondary containment, and a leak detection system between the
secondary and primary containment devices;
• semi-buried metal tanks with external and internal corrosion protection and an
appropriate leak detection and secondary containment system; and
• steel or other storage devices constructed on grade and then backfilled on one or
more sides, with an appropriate secondary containment and leak detection system.
Operational procedures must be considered when choosing the primary containment
device. Although concrete provides a durable working surface, it is too porous and
susceptible to cracking to be considered primary containment. While synthetic liners
provide an impervious barrier, they often require protection from daily operations (e.g.,
from equipment used for loading or unloading operations).
The above storage systems must be designed to provide for the collection and
containment of spills that may occur during loading or unloading operations and to
operate with sufficient freeboard to prevent their overflowing. The bottom of these
storage systems must not be within 1 metre of the seasonably high-groundwater table.
Due to the nature of the operations typically associated with these types of storage
systems, they are usually of an open-top construction. In situations where fugitive odours
and access by wildlife are concerns, these storage systems should be fitted with
mitigative measures.
8.2 Secondary Containment and Leak Detection
For those storage systems that are below grade, the secondary containment system must
include an impervious synthetic liner, as detailed in Section 13.3. In order to protect the
liner, accommodate the leak detection system, and support the primary containment
device (which in some situations may be a tank or another liner), the secondary
containment liner must be laid down in the appropriately prepared earthen excavation
with an appropriate amount of sand or other material placed on top of the liner surface.
The earthen excavation receiving the liner must be sloped, with the low point being down
gradient of the directional flow of groundwater.
The leak detection system must have an engineered seepage pathway (e.g., weeping tile)
leading to at least one monitoring well. The monitoring well(s) must be completed at the
low end, positioned between the secondary containment liner and the primary
containment device. To avoid compromising the integrity of either the primary or
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 29
secondary containment device, the piping for the monitoring well(s) must not go through
For those storage systems constructed on grade and then backfilled on one or more
sides, the use of a compacted clay liner as described in Section 13.1 with an
appropriate leak detection system may be considered.
The leak detection system must be monitored on a monthly basis. Any collected
liquids must be field tested for pH (e.g., using test strips or meter), chlorides (e.g.,
using test strips), hydrocarbon odour, and a visible oil sheen. The results from the
monthly field tests must be recorded, and if there is indication of a problem,
laboratory analyses must be performed for verification and then, if necessary,
followed by appropriate corrective measures.
On an annual basis, a sample of the liquids collected from the leak detection system must
be analyzed by a laboratory for the parameters listed below:
• electrical conductivity,
• major ions (e.g., Ca, Mg, Na, K, NO3, SO4, Cl, PO4),
• oil and grease, and
• any other parameter deemed necessary by the EUB.
Note that if any of the parameters have changed significantly in comparison to previous
results or monitoring results indicate there may be a potential concern, additional
analyses should be performed for verification and, if necessary, followed by corrective
The EUB must be notified if any of the monitoring results indicate a concern. The
notification must describe
• the parameters that changed,
• the investigative work conducted, and
• any remedial or corrective work that has occurred or is proposed.
Refer to Section 10 for more detail on record keeping.
30 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
9 Requirements for Bulk Pads
Approval holders or licensees may require the construction of permanent bulk pads
on sites to be used for the storage of solid materials, such as contaminated soils, spent
desiccant, catalyst, or activated carbon. In such cases, the bulk pad storage area must
• a compacted clay or synthetic liner, concrete, or asphalt base pad with a slope
directed to a catchment device to allow for the collection of precipitation and any
generated leachate, and
• a continuous curb with a minimum height of 15 cm on at least three sides of the
bulk pad.
Materials must be stockpiled in a method that will not exceed the capacity of the bulk
pad (e.g., piled at an appropriate distance from the curbs and with an appropriate
slope to prevent the material from tumbling over the curbs surrounding the bulk pad).
In situations where the stored material(s) may potentially generate a leachate, concrete or
asphalt may be used as a durable working surface but are not considered adequate as
primary containment. The design of the pad must appropriately incorporate a compacted
clay or synthetic liner under the working surface. In these situations the incorporation of
a leachate collection system above the primary containment device and a leak detection
system under the primary containment device is also required. Refer to Section 8.2 for the
requirements for the design and monitoring of the leak detection system. Refer to Section
10 for more detail on record keeping.
For bulk pads, the liner or pad is considered the primary containment device and must
have a hydraulic conductivity of 10-7 cm/s or less. Compacted clay liners must also meet
the criteria specified in Section 13.1. Synthetic liners must be appropriate to serve as the
primary containment device and meet the requirements outlined in Section 13.3.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 31
10 Inspection, Monitoring, and Record-Keeping Requirements
The EUB requires companies to maintain records to demonstrate compliance. Inventory
records for production materials are typically handled through the use of standard EUB
production reporting forms, while the record retention and tracking requirements for
oilfield wastes are addressed in EUB Guide 58.
With respect to the storage requirements outlined in this guide, approval holders or
licensees of upstream petroleum sites must do the following:
• Maintain inventory records and retain the records (other than production reporting
forms) on site or at the local field office for 2 years. Where applicable, this includes
copies of dockets for material received and shipped.
• Maintain inspection and corrosion monitoring programs to provide an indication of
the integrity of tanks and piping. Records of test or maintenance checks must be
retained for a minimum of 5 years, but preferably for the lifetime of the tank or
• Document and retain for a minimum of 5 years, but preferably for the lifetime of the
tank(s), any abnormal circumstances identified from the monthly visual inspections
of aboveground storage tanks, the monthly interstitial space monitoring of double-
walled aboveground tanks, or the monthly interstitial space monitoring of double-
walled underground storage tanks, as well as any corrective actions taken to remedy
the situation and prevent it from reoccurring.
storage device(s), the monitoring results from the leak detection system for lined
earthen excavations and bulk pads, as well as any investigative work or corrective
actions taken to remedy a breach of the storage devices.
Note that in the event that a storage device has overflowed or its leak detection
system indicates that it may be leaking, the approval holder or licensee must
investigate the situation, verify the integrity of the storage device, report the release if
required (see IL 98-1), and, if required, implement corrective actions. The actions
must be documented and may include
repairing and testing the storage device,
replacing the storage device, or
implementing cleanup activities as required, including assessing the soil for
contamination (see IL 98-2).
• Where applicable, retain groundwater monitoring records for a minimum of 5 years,
but preferably for the lifetime of the upstream petroleum site.
• Maintain records from alternative leak detection systems (electromagnetic surveys,
soil vapour surveys, weeping tile monitoring wells, and inventory reconciliation, etc.)
for a minimum of 5 years, but preferably for the lifetime of the upstream petroleum
• Keep all required approvals, licences, and permits on site or at the field/plant offices.
32 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
• Maintain records on excavation or nearby construction that could affect the integrity
of the storage system.
• Maintain the names of all person who conducted the inspection and monitoring
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 33
11 Criteria for the Surface Discharge of Collected Surface Run-on/Runoff Waters
This section applies to EUB-only regulated upstream petroleum sites and to those
EUB/AENV jointly regulated sites that do not have conditions in the EPEA approval
pertaining to the discharge of collected surface run-on/runoff waters.
Provided the water has not been contaminated, surface run-on/runoff waters collected on
an upstream petroleum site (e.g., within a diked area of a tank farm, within the surface
water collection system) should be released back into the environment (hydrology cycle).
Collected waters must be tested and meet the following criteria prior to being released in
a controlled fashion to adjacent lands:
• chloride content 500 mg/L maximum (e.g., test strips),
• pH 6.0 to 9.0 (e.g., test strips and/or meter readings),
• no visible hydrocarbon sheen (roughly equates to less than 10 mg/L),
• no other chemical contamination (e.g., clean operating conditions such that collected
waters are not impacted by spills/releases),
• landowner or occupant consent,
• water not allowed to flow directly into any watercourse, and
• each release recorded, including the prerelease test data and the estimated volume of
water released.
Contaminated water must not be released into the environment. It should be sent to an
approved facility for treatment and/or disposal or, if possible, treated on site and then
released. The minimal parameters listed above are intended as screening parameters for
sites exhibiting good house-keeping practices. On sites where spills or releases have
occurred, the collected surface water should be tested for parameters that would
demonstrate that the water has not been affected.
The discharge of collected surface waters into a watercourse is not permitted unless
otherwise specified in an EPEA approval. Approval holders or licensees wishing to use
collected surface waters in a facility’s process must consult with AENV regarding the
need for a water diversion licence.
34 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
12 Withdrawal of Storage Tanks from Service
This section applies to the procedures to be followed when aboveground or underground
storage tanks used for upstream petroleum fluids are taken out of service.
12.1 Temporary Withdrawal from Service Not Exceeding 180 Days
When an aboveground or underground storage tank is taken out of service for a period
not exceeding 180 days, the approval holder or licensee must
• isolate the tank,
• empty the tank or measure and record the fluid level in the tank and then repeat this
procedure on a monthly basis, making records available to EUB staff upon request,
• maintain the impressed current cathodic corrosion protection system, if applicable,
• maintain monthly leak detection monitoring.
12.2 Temporary Withdrawal from Service Exceeding 180 Days
exceeding 180 days, the approval holder or licensee must
• remove all liquids and vapours from the storage tank and its connecting piping,
• isolate the tank and mark it to clearly indicate that it is empty,
• verify the integrity of the tank prior to reactivation if the tank has been out of service
for longer than 1 year (refer to Appendix 2 for integrity verification requirements)
and then appropriately relabel the tank.
Should the approval holder or licensee wish to change the service of a tank, prior to
reactivation the tank must be cleaned and refurbished if necessary and then verified for
compatibility with the new service.
12.3 Permanent Withdrawal from Service
Aboveground and underground tanks permanently taken out of service must have all
fluids and sludges removed and be purged of all combustible vapours. It is expected that
aboveground tanks will be removed from the active part of the upstream petroleum site
and either be relocated in an appropriate storage area on the site or sent for disposal. It is
also preferred that underground tanks be removed from the active part of the upstream
petroleum site. If this activity might compromise the operation of the upstream petroleum
site, the underground tank must be appropriately isolated and then removed when the
upstream petroleum site is decommissioned.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 35
Upon removal of a tank, the soil surrounding the tank must be assessed and appropriately
decontaminated. Excavated contaminated soils must be managed in accordance with
Guide 58, while all in situ remediation programs must be managed to the satisfaction of
Alberta Environment. Also refer to IL 98-2 for further information regarding the
contamination management. All decontamination work, including verification (through
confirmatory soil samples) that remediation objectives were achieved, must be
documented and made available upon request to the EUB or Alberta Environment.
36 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
13 Liner Specifications
Natural and synthetic liners are used in storage and treatment areas to impede the
movement of materials that could adversely impact soil or groundwater. The initial
decision in the installation of any liner is whether the liner type is appropriate for the
given application. It is important to remember that the purpose of a secondary
containment liner is not to function as a tank or other primary containment. When the
leak detection system is activated, the tank or storage system must be shut down,
inspected, and repaired.
There are two modes of mass transfer through a barrier such as a liner: liquid transfer
(through hydraulic conductivity) and vapour transfer (through molecular diffusion).
Hydraulic conductivity is applicable to natural materials, where mass transfer depends on
the movement of liquid through pore structure of a soil and the driving force is hydraulic
pressure or head. Vapour transfer is applicable to polymer barriers, where the driving
force is the concentration gradient of the permeating substance across the barrier.
Although no material is completely impermeable, the type, design, and installation of a
liner is extremely important in achieving the desired level of impermeability for both
primary and secondary containment liners.
13.1 Compacted Clay Liners
Clayey soils may be suitable material from which to construct a compacted clay liner. For
the purpose of secondary containment, the clayey soil must be compacted to achieve a
hydraulic conductivity of 1 x 10-6 cm/s or less determined in situ or 1 x 10-7 cm/s or less
determined in a laboratory from a representative disturbed sample (material must meet
hydraulic conductivity requirements under full hydrostatic head). For use as primary
containment, compacted clay liners must have a hydraulic conductivity that is at least one
order of magnitude less than that required for secondary containment.
Literature suggests that a hydraulic conductivity of ≤ 1 x 10-7 cm/s is achievable if
suitable starting material (clayey soil) is excavated, reworked, or homogenized and laid
down in lifts following appropriate construction protocol on a properly prepared sub-
base. Key properties in achieving low hydraulic conductivity are the Plasticity Index and
clay content of the soil. There are reasons to prefer a soil of low plasticity over highly
plastic clay, as soils with low plasticity are often easier to mix, hydrate, and homogenize
in the field and tend to be less susceptible to desiccation cracking. The ideal situation
involves small, soft, weak clods of clay that are easily remolded and compaction with a
heavy roller that effectively remolds and melds the clay clods together.
Literature identifies that the most important factors in achieving low hydraulic
conductivity in compacted clay liners include
• using suitable clayey soils that meet the following specifications:
greater than 30 per cent fines (defined as dry weight percentage passing the No.
200 sieve)
greater than 20 per cent clay (0.002 mm or smaller as determined by hydrometer
well graded (no excess of particles in any size range and no intermediate sizes
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 37
Liquid Limit (LL) equal to or greater than 30
Plasticity Index (PI) equal to or greater than 10
• laying the clayey soil down in lifts
a minimum of four lifts, with each being 15 to 20 cm thick (loose thickness)
• properly preparing the surface to receive a lift of soil
if placing the soil on sub-grade, the sub-grade must be adequately compacted
if placing the soil on a previously compacted lift, the surface should be scarified
to a nominal depth of 2.5 cm prior to placing the next lift of soil
• using the clayey soil at the correct water content
each lift must be placed at approximately 2 to 3 per cent wet of optimum
• compacting each lift to a minimum of 95 per cent of the Standard Proctor maximum
dry density using the proper type of compactor with an appropriate number of passes
the best type of compactor in most instances is a heavy, footed roller with feet
that fully penetrate the loose lift of soil
the compactor must be heavy enough to ensure that adequate compactive energy
is delivered to the soil and that the feet fully penetrate the full depth of the lift to
kneed it and bond it to the previous lift
the number of compactor passes over a given area varies between soil and
compactor type, but sufficient passes must be conducted to achieve the desired
• placing down sufficient lifts to achieve a final compacted thickness of 0.6 m or
• protecting each compacted lift from damage
a smooth-drum roller is often used to compact the surface of a completed lift, as
this forms a hard skin, which helps to minimize desiccation and sheds water
the smooth surface should be roughened with a disc prior to placing the next lift
upon completion of the liner, an appropriate overlying material must be used to
protect the liner from mechanical damage and weathering
The construction of a compacted clay liner requires application by qualified personnel
overseen by a professional geotechnical engineer. The specifications of the clayey
material used for the liner and the details of the liner construction (quality
assurance/quality control [QA/QC] data) must be documented and made available to
EUB staff upon request.
13.2 Natural Liners
Natural liners involve scarification and recompaction of in situ clay, without excavating
the underlying clay, and placing it in lifts as for a compacted clay liner. Natural liners
may only be used at sites that have a deposit of appropriate clayey soils with a minimum
thickness of 0.9 m and where the seasonal high groundwater table is greater than 1 m
below the expected bottom of the liner.
38 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
The potential for in situ clayey deposits to serve as natural liners should only be
investigated when sites are located in relatively low-permeability clay or till. Delineation
of the in situ clayey deposit requires a site investigation by a qualified person. Attention
should be focused on looking for hydraulic defects, such as sand seams, cracks, and
fissures. A minimum of three boreholes, arranged in an approximate equilateral triangle,
is required to establish orientation of any significant geologic plane. Depth of sampling
from the surface to characterize underlying soil materials must be at least 3 m. One
sampling must be extended to establish depth to groundwater. The clayey soil must be
analyzed in a lab to determine Liquid Limit, Plasticity Index, clay content, and fines
content (refer to criteria in Section 13.1).
Literature identifies that the most important factors in achieving suitable natural liners
• preparing the site for the construction
remove the topsoil from the site and appropriately salvage and store it
remove rocks or clumps greater than 50 mm in size
• scarifying and recompacting the in situ clayey deposit to 95 per cent of the Standard
Proctor maximum dry density
only scarify the in situ clayey deposit to a depth that can be recompacted using
the in situ clay must be at 2 to 3 per cent wet of optimum
• smoothing out the completed liner with a smooth barrel compactor and applying
overlying material to protect the liner from mechanical damage and weathering.
The completed liner must achieve a hydraulic conductivity as specified in Section 13.1. A
variety of geochemical, geophysical, and engineering tools are available for investigating
the hydraulic integrity of natural liners. Literature indicates that for natural liners, in situ
hydraulic conductivity tests can be more accurate than laboratory tests.
The construction of a natural liner requires application by qualified personnel overseen
by a professional geotechnical engineer. The specifications of the clayey deposit,
including the site delineation information, and the details of the liner construction
(QA/QC data) must be documented and made available to EUB staff upon request.
13.3 Synthetic Liners
A wide array of synthetic liners are available, many of which were developed for
applications such as waste containment. The long-term integrity of a synthetic liner is
dependent on the physical strength of the liner, its resistance to effects of aging or
environmental degradation, upkeep and maintenance of cover, and its resistance to the
substance contained in the storage system. As secondary containment application does
not require long-term, continuous contact with the contained substances, the requirements
for liner performance in secondary containment systems may be less rigorous than those
for primary containment systems.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 39
Most synthetic liners are impermeable to liquid transfer but are permeable to vapour to a
degree that depends on the solubility of the liquid in the polymer, temperature, and the
thickness of the membrane. The most important physical and mechanical attributes of the
liner that determine its suitability for a given application are thickness, density, mass per
unit area, tensile properties, tear resistance, hydrostatic resistance, and puncture
resistance. Other key physical properties include linear expansion properties, cold
temperature properties, resistance to ultraviolet light, resistance to soil burial, and
The physical configuration of the liner determines the seaming and construction
procedures used to install it. Therefore, the installation of synthetic liners must follow the
manufacturer’s specifications and be conducted by qualified personnel. The
specifications of the liner material (suitability for its intended use) and the details of its
installation (QA/QC data) must be documented and made available to EUB staff upon
request. To be suitable for secondary containment, the synthetics liner must be a
minimum of 30 mils.
Synthetic liners used for secondary containment in the petroleum industry include
• coated fabrics or laminates,
• extruded film or sheet, and
• spray-on coatings.
13.3.1 Coated Fabrics and Laminates
These geomembranes include polymer films coated or laminated onto a textile substrate
by means of a manufacturing process such as calendaring or coating. Polymer
formulations include chorosulfonated polyethylene, neoprene, ethylene, interpolymer
alloy, butyl rubber, epichlorohydrin rubber, ethylene proylene diene monomer (EPDM),
and various combinations. The coatings are typically elastometric or rubbery in character,
and the substrates are usually high-strength textiles with a broad weave (e.g., nylon,
13.3.2 Extruded Film or Sheet
Geomembranes of this kind are manufactured in a one-step process without the use of a
textile backing or substrate and are made from polyvinyl chloride (PVC), high-density
polyethylene (HDPE), polyethylene of lower densities, and elastomers. Because of its
chemical resistance, HDPE is widely used and is available in thickness ranging from 20
mils to greater than 100 mils.
13.3.3 Spray-on Coatings
These products are usually installed by spraying elastomers (e.g., polysulfide,
polyurethane) onto a geotextile or other material for backing. The coating thickness is
variable and is a function of the spray dwell time, flow rate, and operator technique. Both
polysulfide and polyurethane have good resistance to petroleum products. The resulting
sprayed-on coating has added durability and strength because of the geotextile backing.
40 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Appendix 1 Glossary of Storage Terms
The words and terms used in Guide 55 have the following meanings unless otherwise
indicated in a particular context.
Aboveground storage tank: A tank that sits on or above the ground surface and whose
top and complete external sides can be visually inspected.
Adverse effect: An impairment of or damage to the environment, human health or safety,
Bulk pads: A ground surface area designated for the segregated storage of materials
without the use of a container or tank.
Cathodic protection: A method of preventing corrosion to a metal surface by
introducing another metal (anode) into the ground to create a corrosion cell in which the
surface to be protected becomes a cathode. If deterioration or corrosion occurs at the
anode (introduced metal), the cathodic protection may be of a sacrificial type or
impressed current design.
Condensate: A mixture mainly of pentanes and heavier hydrocarbons that may be
contaminated with sulphur compounds, that is recovered or is recoverable at a well from
an underground reservoir, and that may be gaseous in its virgin reservoir state but is
liquid at the conditions under which its volume is measured or estimated.
Container: Any portable aboveground containment device (e.g., drums, pails, bags,
boxes, totes) with a capacity not exceeding 1 m3.
Containment device: See “Primary containment device” and “Secondary containment
Crude bitumen: A naturally occurring viscous mixture, mainly of hydrocarbons heavier
than pentane, that may contain sulphur compounds and that in its naturally occurring
viscous state will not flow to a well.
Crude oil: A mixture mainly of pentanes and heavier hydrocarbons that may be
an underground reservoir, and that is liquid at the conditions under which its volume is
measured or estimated and includes all other hydrocarbon mixtures so recovered or
recoverable except raw gas, condensate, or crude bitumen.
Environment: All components of the earth including air, land, and water; all layers of
the atmosphere; all organic and inorganic matter and living organisms; and interacting
Facility: Any building, structure, installation, equipment, or appurtenance over which the
EUB has jurisdiction and that is connected to or associated with the recovery,
development, production, handling, processing, treatment, or disposal of hydrocarbon-
based resources or any associated substances or wastes and includes, without limitation, a
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 41
battery, a processing plant, a gas plant, an oilfield waste management facility, a central
processing facility as defined in the Oil Sands Conservation Regulation (AR 76/88), a
compressor, a dehydrator, a separator, a treater, a custom treating plant, a produced water
injection plant, a produced water disposal plant, a miscible flood injection plant, a
satellite, or any combination of them, but does not include a well, a pipeline as defined in
the Pipeline Act, a mine site or processing plant as defined in the Oil Sands Conservation
Regulation (AR 76/88), or a mine or coal processing plant as defined in the Coal
Freeboard: The unused upper portion of a primary containment device.
Impervious: A natural material that demonstrates a hydraulic conductivity of 10-6 cm/s
or less as determined in situ or of 10-7cm/s or less as determined in a laboratory from a
representative disturbed sample, or a synthetic membrane liner or barrier appropriately
selected to control the migration of specific fluids.
Leachate: Interstitial fluids separated from materials or fluids generated by the
percolation of liquids (e.g., water) through materials.
Leachate collection system: A seepage pathway and collection system constructed on
the surface of the primary containment device to allow for the drainage, collection, and
removal of any generated leachate.
Leak detection system: A system designed for the early detection of any leakage from a
primary containment device; may include visual, electronic, or statistical inventory
Liquid: A substance that contains free liquids as determined by the US EPA Method
9095 Paint Filter Liquids Test, Test Methods for Evaluating Solid Wastes
Physical/Chemical Methods (EPA Publication No. SW 846).
Monitoring well: A well used to detect liquid or vapour leakage from a primary or
secondary containment device or to sample a groundwater aquifer or unsaturated zone to
detect the presence of any contaminants.
Oilfield waste: An unwanted substance or mixture of substances that results from the
construction, operation, abandonment, or reclamation of a facility, well site, or pipeline
but does not include an unwanted substance or mixture of substances from such a source
that is received for storage, treatment, disposal, and/or recycling at a facility regulated by
Albert Environment.
Oilfield waste storage area: An area of an EUB-licensed or approved facility (on-site
oilfield waste management component) that is used for the purpose of collecting and
storing in containers, tanks, bulk pads, or lined earthen excavations oilfield or oily wastes
from sites within the same production system.
Oilfield waste storage facility: An EUB-approved stand-alone storage facility
constructed for the purpose of collecting and storing one company’s oilfield wastes until
volumes are sufficient for economic transfer of the wastes to treatment/disposal facilities.
42 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Oily waste: A specific type of oilfield waste that contains oil or bitumen generated
primarily during heavy oil production and typically consists of mainly produced sand and
slop oil.
Petroleum product: A single product or a mixture of at least 70 per cent hydrocarbons
refined from crude oil, with or without additives, that is or could be used as a fuel,
lubricant, or power transmitter. Without restricting the foregoing, such products include
gasoline, diesel fuel, aviation fuel, kerosene, naphtha, lubricating oil, fuel oil, and engine
oil (including used oil) and exclude propane, paint, and solvents.
Primary containment device: A device used to physically contain materials produced,
generated, or used in processes regulated by this guide. Primary containment devices
include, but are not limited to, single-walled tanks, the internal wall of double-walled
tanks, containers, and the liners of lined earthen excavations and bulk pads.
Same production system: An interconnected system of upstream production facilities
(e.g., wells, pipelines, batteries). An oil/gas production site receiving oilfield waste for
on-site management or storage must be within the same interconnected system of
upstream production facilities as the oil/gas production site from which the oilfield waste
originated. Both the receiving site and originating site shall have the same licensee or
approval holder.
Secondary containment system: An impervious barrier or liner used for the purpose of
containing and preventing any leakage from the primary containment device from
impacting the environment.
Site: The area defined by the boundaries of a lease site for an upstream petroleum facility
or well site.
Small quantity exemption: Oilfield wastes (other than those substances listed in
AENV’s Alberta Users Guide for Waste Managers, Schedule, Table 4, Part B) are not
considered dangerous and are exempt from the storage requirements if they are produced
at any single site in an amount less than 5 kilograms (kg) per month if a solid or 5 litres
(L) per month if a liquid and the total quantity accumulated does not exceed 5 kg or 5 L
Solid: A substance that does not contain free liquids as determined by the US EPA
Method 9095 Paint Filter Liquids Test and is not gaseous at standard conditions.
Spill control device: A device (e.g., load box) used to physically collect and recover
spills and leaks of materials from process equipment, piping valves, flanges, and other
equipment, especially at material transfer points. Spill control devices must be
maintained to ensure their integrity and that they are of sufficient capacity to be
functional (e.g., free of precipitation).
Storage: The holding of materials produced, generated, and used by the upstream
petroleum industry for a period of time until the products or wastes are transported,
treated, or disposed.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 43
Tank: A device designed to contain liquid materials that has an internal capacity of more
than 1 m3 and is constructed of impervious materials that provide structural support and
may include such materials as plastic, fibreglass-reinforced plastic, or steel but does not
include piping.
Underground storage tank: A tank, of any volume, that is partially or completely
buried and does not allow for the visual inspection of the top, complete sides, and bottom
of the tank without excavation.
Watercourse: The bed and shore of a river, stream, lake, creek, lagoon, swamp, marsh,
or other natural body of water or a canal, ditch, reservoir, or other man-made surface
feature, whether it contains or conveys water continuously or intermittently.
Weather protection: A structure, protective coating, or cover that ensures that the
integrity of the primary containment device and its labelling are not compromised by the
44 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Appendix 2 Storage Requirements for Existing Facilities, Well Sites, and Pipelines
1 Discontinued Storage Options (Effective January 1, 2002)
1996, and January 1, 2002, are expected to meet the storage requirements outlined in the
1995 edition of Guide 55. This 2001 edition of Guide 55 discontinues the following
options as of January 1, 2002:
impermeable soil conditions (i.e., hydraulic conductivity of 10-6 cm/s or less) are
used for secondary containment,
system, but no secondary containment, and
• the use of concrete as primary containment for lined earthen excavations or for bulk
pads where there is potential for the stored materials to generate a leachate.
Any of the above storage systems installed prior to January 1, 2002, will be required to
meet the requirements within the appropriate sections of this appendix.
Upstream petroleum facilities, well sites, and pipelines constructed as of January 1, 2002,
must meet the storage requirements as outlined in the body of this 2001 edition of Guide
2 Storage Requirements for Facilities, Well Sites, and Pipelines Operating Prior to January 1, 1996
Approval holders or licensees of upstream petroleum facilities, well sites, and pipelines
operating prior to January 1, 1996, were required to demonstrate by October 31, 2001,
that their storage practices and devices met the intent of the 1995 edition of Guide 55 and
follow existing EUB regulations. For aboveground tanks (internal volume 5 m3 or
greater) and underground tanks, approval holders or licensees had the option to either
retrofit their upstream petroleum sites to meet the secondary containment and leak
detection requirements outlined in Sections 5 and 6 (or if applicable, the requirements
outlined in this appendix) or to test/inspect the tanks to verify their mechanical integrity.
For small aboveground tanks where the total combined volume per site exceeded 5 m3,
approval holders or licensees were to either have met the secondary containment
requirements outlined in Section 5.3 or to have verified the integrity of these tanks by
October 31, 2001. Approval holders or licensees will be required to meet the secondary
containment requirements for small aboveground tanks exceeding the total combined
volume of 5 m3 per site by October 31, 2004. For containers, lined earthen excavations,
and bulk pads, approval holders or licensees must meet the requirements outlined in
Sections 7, 8, and 9 or, if applicable, the requirements outlined in this appendix.
The objective of the requirements for existing facilities, well sites, and pipelines is to
verify and possibly enhance the integrity of their existing primary containment devices.
Approval holders or licensees were and will continue to be responsible to select and
implement a suitable testing/inspection program to verify the mechanical integrity of
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 45
existing storage devices. It is expected that professional engineering judgement was and
will be exercised when selecting methodologies and integrity verification companies to
ensure that the type of test planned is appropriate for the specific storage device
application and the materials it stores.
Due to the large number of upstream petroleum sites, six years were provided to allow
approval holders or licensees the opportunity to establish a schedule for the retrofitting or
testing/inspection of their primary containment devices, as well as a schedule for the
frequency to repeat the integrity verification tests/inspections. Factors to be considered in
scheduling the retrofitting or testing/inspection of primary containment devices include
age of device, type of service, site-specific environmental sensitivities, general lack of
available information on the device, as well as the opportunity to combine it with a plant
Approval holders or licensees repairing or replacing storage devices are reminded that the
potential for contamination as a result of leaks or failures must be investigated and then
managed in accordance with EUB IL 98-2: Suspension, Abandonment, Decontamination,
and Surface Land Reclamation of Upstream Oil and Gas Facilities.
The results of the retrofitting, repairing, tests/inspections, or any corrective action (e.g.,
site investigation, decontamination work) must be documented, retained by the approval
holder or licensee, and made available to the EUB upon request.
2.1 Aboveground Storage Tanks (Internal Volume ≥ 5 m3 )
2.1.1 Retrofitting
Approval holders or licensees that have retrofitted their upstream petroleum sites to meet
the secondary containment requirements for aboveground tanks (i.e., installed double-
walled tanks or secondary containment consisting of a dike and liner system meeting the
requirements outlined in Section 5) are not required to integrity test these tanks, but must
meet the monthly monitoring requirements for leak detection.
2.1.2 Integrity Testing
Approval holders or licensees that chose to verify the mechanical integrity of their
aboveground tanks were to have the initial test/inspection completed by October 31,
2001. The intent of the 1995 edition of Guide 55 was to provide industry with enough
time to work out a schedule that would fit operations, especially for those companies with
numerous facilities. It was intended that the integrity test/inspection be repeated on a
five-year frequency, which was to be established by the date of the initial integrity test.
However, this intent was not stated clearly. The revised integrity test/inspection schedule
for aboveground tanks is as follows:
Year of first test Year of second test Year of third test
1998 or earlier 2003 2008
46 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Note that except for the duration between the first and second test for those tanks initially
tested before 1998, integrity tests for aboveground tanks must be repeated at a minimum
of every five years.
For information on the methodologies available for integrity testing aboveground storage
tanks, see Table A1; for further explanatory notes, see Table A3. Approval holders or
licensees must be able to verify that the test method used was appropriate for the specific
situation and that the results were reliable. Approval holders or licensees may conduct
alternate inspection schedules based on Section 4 of API Standard 653.
If the initial integrity test identified a problem with the aboveground storage tank,
approval holders or licensees had the option to replace the tank with one that was
integrity verified and appropriate for the type of service or to repair the tank and then
retest it. If the results of the retest did not confirm the integrity of the tank, the tank was
to be replaced with one that was integrity verified and appropriate for the type of service.
These requirements are also applicable when the tanks are being reverified.
Note that approval holders or licensees must conduct monthly visual inspections of all
aboveground tanks and the diked area for evidence of problems, damage, or leakage. Any
spills or leaks must be cleaned up and, as required, corrective action initiated. Any
abnormal circumstances must be documented.
2.1.3 Replacement of an Existing Aboveground Storage Tank or Addition of a New Tank
to an Existing Tank Farm
When replacing an existing tank, it is not mandatory to upgrade the tank farm to meet full
secondary containment and leak detection requirements as outlined in Section 5. As these
sites were constructed prior to January 1, 1996, the capacity of the dike must as a
minimum be 100 per cent the volume of the largest tank within the tank farm. Upon
removal of the old tank, any contamination must be managed, and then the ground must
be compacted and appropriately prepared for placement of the new tank.
Should an existing multi-tank farm have sufficient capacity to accommodate an
additional tank, it may be added. However, if the addition of a new tank results in
reconstruction of the tank farm area, it is expected that the reconstruction will meet the
secondary containment and leak detection requirements outlined in Section 5.3.2.
Approval holders or licensees replacing a tank or adding a new one to an existing tank
farm must meet the construction requirements outlined in Section 5.3.1. These tanks must
be integrity verified every five years, unless the tank farm area has been reconstructed to
meet the secondary containment and leak detection requirements outlined in Section 5.3.2
or an option to replace the integrity verification requirement (next section) has been
2.1.4 Options to Replace the Requirement to Integrity Verify Aboveground Tanks
The replacement of an existing tank or the addition of a new tank to an existing tank
farm presents approval holders or licensees with the opportunity to install a liner or
weeping tile system under the tank (see leak detection method in Table A1).
Although not mandatory, the installation of a weeping tile system or liner, combined
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 47
with monthly monitoring, may be used to replace the requirement to reverify the
integrity of the tanks every five years. Any liquids collected in the weeping tile
system must be field tested for pH (e.g., using test strips or meter), chlorides (e.g.,
investigative work must be conducted, followed by any necessary corrective
Integrity verified, single-walled aboveground tanks within a diked area (on sites
constructed prior to 1996) may be retrofitted with a second bottom and a system to
monitor the interstitial space between the two bottoms. Provided the interstitial space is
monitored monthly, this option may be used to replace the requirement to reverify the
tank every five years.
Any abnormal circumstances from the monthly monitoring must be documented, as well
as any corrective actions implemented to remedy the abnormal circumstance.
2.2 Underground Storage Tanks
2.2.1 Retrofitting
Approval holders or licensees that have replaced single-walled underground storage tanks
with double-walled tanks meeting the requirements in Section 6 or that have retrofitted
their single-walled underground tanks with secondary containment (i.e., synthetic liner or
natural soil conditions exhibiting a hydraulic conductivity of 10-6 cm/s or less) and leak
detection were not required to integrity verify these underground storage tanks. The leak
detection systems for these tanks must be monitored monthly.
As of January 1, 2002, the option to retrofit single-walled underground storage tanks will
no longer be available. For those tanks that have been retrofitted, the following
requirements are expected to have been met.
• For synthetic liners surrounding the underground tank with a monitoring well
positioned between the tank and liner:
The bottom of the liner should be sloped to encourage any leakage from the tank
to collect at the low point, which should be down gradient of the directional flow
At least one monitoring well must be completed in the low point and positioned
between the secondary containment liner and the tank for the purpose of
monitoring any leakage from the tank.
• For weeping tile systems installed with single-walled underground storage tanks:
Such a system is only permitted where there are low-permeable soil conditions
(i.e., the hydraulic conductivity of the soil is 10-6 cm/s or less) and the seasonal
high groundwater table is not within 1 m of the bottom of the tank.
48 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
A continuous loop of weeping tile should be placed around the tank at a depth
approximating the deepest portion of the tank and in such a fashion as to
encourage the movement of groundwaters that may occur under the tank towards
the weeping tile.
The weeping tile should be sloped to encourage the collection of fluids at the
lowest point, which should be down gradient of the directional flow of
At least one monitoring well must be completed at the collection point for the
purpose of monitoring any leakage from the tank.
Criteria for the installation of weeping tile may be found in the Drainage and
Plumbing Act.
The leak detection systems for the above options must be monitored monthly. Any
liquids collected in the monitoring well(s) must be field tested for pH (e.g., using test
strips or meter), chlorides (e.g., using test strips), hydrocarbon odour, and a visible oil
sheen. The results from the monthly field tests must be recorded, and if there is
indication of a problem, investigative work must be conducted, followed by any
necessary corrective measures. The results from the monthly monitoring must be
retained for a minimum of 5 years, but preferably for the lifetime of the facility.
2.2.2 Integrity Testing
underground tanks were to have the initial test/inspection completed by October 31,
numerous upstream petroleum sites. It was intended that the integrity test/inspection be
repeated on a three-year frequency, which was to be established by the date of the initial
integrity test. However, this intent was not stated clearly. The revised integrity
test/inspection schedule for underground tanks is as follows:
1999 or earlier 2002 2005
tested in 1999 or earlier, integrity tests for underground tanks must be repeated at a
minimum of every three years.
For information on the methodologies available for integrity testing underground storage
tanks, see Table A2; for further explanatory notes, see Table A3. Approval holders or
situation and that its results were reliable.
If the integrity test identified a problem with the underground storage tank, approval
holders or licensees had the option to replace the tank with a double-walled one as per the
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 49
requirements outlined in Section 6 or to repair the tank and then retest it. If the results of
the retest did not confirm the integrity of the tank, the tank was to be replaced as per the
requirements outlined in Section 6.
2.3 Small Aboveground Tanks, Containers, Lined Earthen Excavations, and Bulk Pads
Appendix 1 of the 1995 edition of Guide 55 did not differentiate between small and large
aboveground tanks. Therefore, approval holders or licensees of pre-1996 facilities that
have small aboveground tanks (internal volume greater than 1 m3 but less 5 m3) where the
total combined volume per site exceeds 5 m3 were to either provide secondary
containment or verify the integrity of the tanks by October 31, 2001. This 2001 edition of
Guide 55 drops the option to verify integrity, and approval holders or licensees have until
October 31, 2004, to provide secondary containment, as outlined in Section 5.3 for small
aboveground tanks that exceed the total combined volume of 5 m3 per site.
Appendix 1 of the 1995 edition of Guide 55 required approval holders or licensees of
facilities, well sites, and pipelines to have met, by October 31, 2001, the storage
provisions for containers, oily waste storage facilities (lined earthen excavations), and
bulk pads.
Note that approval holders or licensees that prior to January 1, 2002, installed concrete-
lined earthen excavations with an underlying leakage monitoring system but no
secondary containment are allowed to continue to use these storage systems provided that
the integrity can be verified and then reverified, following the frequency established for
Approval holders or licensees that have prior to January 1, 2002, used concrete as
primary containment for lined earthen excavations or for bulk pads where there is
potential for the stored materials to generate a leachate are allowed to continue to use the
storage systems provided that the associated leak detection systems do not indicate a
breach of containment.
The leak detection systems for the lined earthen excavations and bulk pads described
above must be monitored and the results recorded and reported as per the requirements
detailed in Section 8.2.
3 Existing Monitoring Programs
Results from existing monitoring programs can also be used to help determine whether or
not storage devices are leaking. Methods used to detect contaminants such as salts and
hydrocarbons in the soil or groundwater within the immediate vicinity of a storage device
are considered indirect methods, as opposed to direct methods that actually verify or test
the integrity of the storage device. Examples of existing monitoring programs include
• groundwater or soil vapour monitoring wells installed in the immediate vicinity (e.g.,
down gradient of the groundwater flow) of the storage device,
• electromagnetic surveys (for tanks containing brine or brine-equivalent liquids), and
• soil vapour surveys for hydrocarbons (for tanks containing hydrocarbons).
50 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Table A1. Integrity tests for aboveground storage tanks1
Method Description Pros Cons Applications
Ultrasonic test Ultrasonic testing checks components and • Only one side of the • Requires specialized equipment that needs an Works on most
structures to detect internal and surface breaking surface needs to be experienced approval holder or licensee to interpret the aboveground
defects and measures wall thickness. Ultrasonics assessed. results. storage tanks.
operates on the principle of infecting a very short • It can locate areas of • The tank may need to be cleaned before the inspection
pulse of ultrasound into a component or structure both leaks and potential can take place.
and then receiving and analyzing any reflected leaks. When these areas
sound pulses. of potential leaks are
identified, they can be
There are different kinds of ultrasonic tests. The revisited on subsequent
A-Scan point-to-point technique, used for inspections.
decades, involves taking a thickness reading at
one point on a section of the tank and repeating
this process several times on the same tank to
The B-Scan technique can take ultrasonic
thickness readings over every 0.04 inch of the
surface, which results in almost 100% coverage of
the tank surface. This eliminates the problems
associated with the A-Scan technique missing
problem areas. The B-Scan can also scan
through coatings, unlike the A-Scan technique.
Internal visual An internal visual inspection can be performed by • Inexpensive. • The tank needs to be emptied and cleaned before Works on most
inspection emptying and cleaning the inside of the tank and • Easy to perform. inspection. aboveground
then visually inspecting it for signs of weakness or • The whole inside of the • There is the possibility of overlooking smaller leaks. storage tanks.
holes. These inspections should be performed in tank can be inspected.
conformance with API Standard 653 and may be
combined with an ultrasonic test.
External visual An external visual inspection can be performed on • Inexpensive. • There is the possibility of overlooking smaller leaks. Works on most
inspection all aboveground storage tanks that are visible on • Easy to perform. • It is only possible to inspect the part of the tank not aboveground
all sides. These inspections should be performed • The whole outside of the resting on the ground storage tanks.
in conformance with API Standard 653 and may tank can be inspected. • If bottom of tank cannot be inspected, the inspection
be combined with an ultrasonic test. must be combined with some other method.
1 The integrity tests are listed in random order without regard for the accuracy or cost of the test.
See Table A3 for explanatory notes.
Underground storage tank (UST) integrity tests are not directly transferable for use on aboveground storage tanks (AST). ASTs are subject to larger temperature fluctuations,
influenced more by atmospheric pressure changes and wind, and usually larger than USTs.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 51
Table A1. Integrity tests for aboveground storage tanks1 (continued)
Vacutect system All openings to the tank are sealed off and a • Allows the technician to • The expertise of the approval holder or licensee is Works on tanks up
mild vacuum (less than half of 1 psi) is applied perform trouble shooting crucial for this test to effectively determine the to 500 barrels (16
to the tank using a vacuum pump. The vacuum to determine whether the location of the leak. feet in diameter).
level is constantly monitored and maintained system is leaking and the • Vibrations from nearby equipment or vehicles may Larger tanks may
by the computer in the testing unit. While nature and location of the interfere with the test, making testing difficult on prove difficult for
under vacuum, Vacutect monitors for three leak. active sites. obtaining a vacuum.
things: water level, noise (via a hydrophone), • Same-day results. • May be ineffective in clay soils because it may plug
and the pressure in the tank. • Product may remain in up holes in the tank bottom (see under Vacuum Test
the tank. and Pressure Test for additional problems).
This test has been modified from the test • Not affected by • May be influenced by tank sludge and sedimentary
performed on USTs for use on ASTs. temperature. accumulations.
Mass-based The test is designed to measure any changes • Same-day results. • Testing at low product levels could allow a leak to Works on most
systems in the buoyancy force acting on a probe • The tank doesn’t have to remain undetected. ASTs.
inserted into the tank. Uses mass be completely empty. • Tests only the portion of the tank containing product.
measurement technology to determine if • The test is not affected • There are several mass-based systems being used
product is entering or leaving the tank. The by temperature. in the industry today. However, they are not
technology is based on the fact that buoyancy designed to handle the large temperature
force only varies as a direct result of a change fluctuations or the changing atmospheric pressures
in the mass of the liquid. Buoyancy force is not associated with ASTs. These systems were
affected by changes in product temperature, designed for USTs, where different types of forces
since the change in volume due to are present.
temperature change is offset by a • Results are affected by wind, vibration, and tank
corresponding change in liquid density. shell dynamics.
Vigilant test The method is based on sensing the vacuum • There are no fill or • The tank liner must be carefully fitted to the tank. May be used on
changes that occur in the interstitial space underfill requirements. Liners that are too small will produce larger tanks that have
between an outer rigid tank and an inner wall • Will work on all products. interstitial spaces, decreasing the sensitivity of the liners and are under
formed by installing a flexible membrane liner in • The tank needs very little leak detection system. 400 barrel capacity.
the tank. Vacuum changes are analyzed time after product is • A baseline behaviour must be established for each
continuously with a microprocessor to added before the tank is tank. An error in establishing the baseline could
determine the rate of change. Very slow stable enough for testing. result in either missed detections or masked leaks.
changes occur on tight tanks due to molecular
permeation through the membrane into the
interstitial space. This baseline behaviour is
determined experimentally for each tank after
installation of the membrane is complete. The
vacuum behaviour will vary significantly if a leak
is present. Both liquid and air leaks may be
detected using this method.
52 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Table A1. Integrity tests for above ground storage tanks1 (continued)
Method Description • Pros • Cons Applications
Pressure test This test involves the introduction of slight • Inexpensive. • Potential to damage the tank if too much pressure is Only works on
pressure (nitrogen gas) to the tank. A decrease • Easy to perform. applied. Many of the tank manufacturers warn smaller tanks.
in pressure is measured over a time interval. If against pressure testing.
the pressure decreases, the tank may have a • The tank may be difficult to isolate if there are a
leak. This test requires the pneumatic isolation number of lines connecting to it.
of the tank and/or lines being tested. The tank • If there is sludge in the tank that can’t be removed,
must also be empty of fluids. this method may be ineffective, as the sludge could
act as a plug when pressure is applied, concealing
any leaks the tank might have underneath the
• Only reveals that there is a leak, not the size or
location of the leak.
Vacuum test A vacuum test involves the introduction of a • Inexpensive. • Potential to collapse the tank. Many of the tank Only works on
slight vacuum to the tank. A decrease in • Easy to perform. manufacturers warn against vacuum testing. smaller tanks.
vacuum is measured over a time interval. If the • The tank may be difficult to isolate if there are a
vacuum decreases, the tank may have leak. number of lines connecting to it.
This test requires the pneumatic isolation of • If there is sludge in the tank that can’t be removed,
the tank and/or lines being tested. The fluid this method may be ineffective, as the sludge could
level in the tank should be noted. act as a plug when pressure is applied, concealing
• Soil beneath the tank may plug holes and mask a
In-fill test This test involves the overflowing of a tank • Least expensive. • Does not account for varying temperatures. Works on most
(preferably with water) and the subsequent • Easy to perform. • The tank has to be full and all vapour pockets need aboveground
recording of liquid levels over time. This • Stored product does not to be identified and removed. storage tanks, but is
requires the hydraulic isolation of the tank. always have to be • There is the potential for product being leaked into impractical for larger
removed. the surrounding soils. tanks.
• Only identifies there is a leak, not the size or location
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 53
Hydrostatic test The tank is completely filled and stabilized. • Inexpensive • Does not account for varying temperatures. Only works on
Tank pressure is raised by 5 to 7 psi by a • Easy to perform test. • It could cause a tank rupture. This method is not smaller tanks.
pump or by adding a similar hydrocarbon. If • Stored product does not recommended by tank manufacturers.
pressure is maintained for 1 hour, tank is leak always have to be • The tank has to be full and all vapour pockets need
free. removed. to be identified and removed.
• There is the potential for product being leaked into
• The presence of sludge in a tank may mask any
leaks underneath the sludge.
Tracer test A tracer gas (or liquid) is injected into the tank. • The production system • Lab results are generally not available until 10 to 14 Works for most
Soil gas samples are taken from probes can remain in service days after the start of the test. tanks placed on the
installed into the ground around the tank. A through the entire • The test can be strongly affected by the type of soil ground.
leak is declared if tracer is detected outside the procedure. (i.e., the test will not work well in low-porosity soils).
tank. • There are no fill or • Only able to test for leaks on the tank bottom.
underfill requirements. • Underground piping could be damaged during probe
• The system is designed installations.
for easy retesting, since
the probes are
• Can test any size of tank
without a loss in test
• Not affected by
hydrocarbons from
previous leaks or spills.
Mass Integrity test A small trickle of nitrogen is forced into the • Corrects for thermal • It only tests for leaks below the product line. Works on most
bottom portion of the tank (in the product) and expansion and • Affected by large fluctuations in barometric pressure. aboveground
the pressure required to maintain a continuous temperature stratification. storage tanks.
flow of bubbles is measured (measuring for • Will work on any size of
head pressure). The test procedure measures tank.
the change in the product mass during an • Compensates for tank
overnight data collection. The rate of mass shell dynamics.
change is determined and described in a leak • Third-party performance
rate. rated.
54 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Table A1. Integrity tests for aboveground storage tanks1 (concluded)
Inventory The approval holder or licensee maintains • Easy to implement. • May not be accurate due to the inaccuracy of Works on most
reconciliation records on all of the product that enters and • Can be done while the measuring the volumes entering and leaving the tanks, but the most
leaves the tank. By examining these records, tank is in operation. tank. Also, the volume of product entering and practical application
the approval holder or licensee should be able leaving the tank isn’t usually corrected for is on manifolded
to tell if there is a leak in the tank. There are a temperature. tanks and large
number of companies that offer software • Does not take into account evaporation from the tanks.
programs that use leak detection algorithms for tank.
analyzing inventory, sales, and delivery data to • Location of the leak can’t be identified.
conduct leak-detection testing. • Will overlook smaller leaks.
• Results are open to interpretation and additional
Robotic A visual inspection can be performed internally • Can be performed while • A very expensive piece of equipment, requiring Works on larger
inspection on an aboveground storage tank while it is in the tank is in operation. specialized people to operate the robot and interpret tanks.
operation. The robot is lowered into the tank • Can be used on very the results.
and performs ultrasonic testing on the floor of large tanks. • Expensive.
the tank, providing video footage of the tank • Will inspect the entire
bottom for analysis. The robot also has the tank bottom for areas of
capability of cleaning the tank. weakness and holes.
Permanent leak- There are ways of installing a tank so that • Cost effective. • Relies on the release of product (this is the same for Works on most
detection devices when there is a leak it will be noticed by the • Continuous monitoring by all of the other tests except for ultrasonic testing, aboveground
approval holders or licensees. approval holders or which is capable of finding signs of weakness). storage tanks.
licensees. • Must lift the tank for installation or be installed prior
One is setting the tanks on liners in the shape • Early leak-detection to placement of the tank within tank farm area.
of coasters. When the tank is leaking, product capabilities.
will appear on the edges of the coaster,
alerting the approval holder or licensee to the
Another is the weeping tile system. A system is
installed under the tank with the capability of
collecting fluids leaked out of the tank and
directing them to a collection device. The
approval holder or licensee can check the
collection device regularly for product, which
would indicate a leak.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 55
Table A2. Integrity tests for underground storage tanks1
Pressure decline Involves the introduction of slight pressure (nitrogen • Inexpensive (see • Potential to damage the tank if too much pressure Most underground
test procedure gas) to the tank (approximately 5 psi or less). A Table A3). is applied. Many tank manufacturers recommend tanks (see Table
decrease in pressure is measured over a time • Easy to perform (see against applying pressure to a tank. A3).
interval. If the pressure decreases over time, the tank Table A3). • The tank may be difficult to isolate if it has a
may have a leak. The test requires the pneumatic • Same-day results. number of lines coming into it.
isolation of the tank and lines being tested. The fluid • If there is sludge in the tank that can’t be
level in the tank should be noted. removed, this method may be ineffective, as the
sludge could act as a plug when pressure is
applied, concealing any leaks the tank might have
underneath the sludge.
Vacuum decline Involves the introduction of a slight vacuum to the • Inexpensive. • Potential to collapse the tank. Many tank Most underground
test procedure tank. A decrease in vacuum is measured over a time • Easy to perform. manufacturers recommend against applying tanks.
interval. If the vacuum decreases, the tank may have • Same-day results. vacuum to a tank.
a leak. This test requires the pneumatic isolation of • The tank may be difficult to isolate if it has a
the tank and lines being tested. The tank must also number of lines coming into it.
be empty of fluids. • If there is sludge in the tank that can’t be
removed, this method may be ineffective, as the
• Soil on the outside of the tank may plug holes and
mask a leak.
56 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Table A2. Integrity tests for underground storage tanks1 (continued)
Fill test Involves the overflowing of a tank (preferably with • Least expensive. • Does not account for varying temperatures. Most underground
water) and the subsequent recording of liquid levels • Easy to perform. • The tank has to be full and all vapour pockets tanks.
over time. This requires the hydraulic isolation of the need to be identified and removed.
tank and/or lines being tested. • Trapped air pockets, line swags, and other
difficulties impact the evaluation of the
connected underground piping.
• If there is high groundwater or if the tank is
surrounded by thick clays, a leak could be
• There is the potential for product being leaked
into the surrounding soils.
Out-fill test Involves the emptying of the tank and the subsequent • Least expensive. • Only reveals that there is a leak, not the size or Will work for most
recording of liquid levels over time. This requires the • Easy to perform. location of the leak. tanks situated in
hydraulic isolation of the tank and/or lines being • Useful for areas • Only works in high groundwater situations. soils with a high
tested. where there is a high • If the leak is small, it may take a long time for a groundwater table.
groundwater table. measurable amount of groundwater to infiltrate
• May not evaluate risers, connections, and
Hydrostatic test The tank is completely filled and stabilized. Tank • Inexpensive. • Does not account for varying temperatures. Most underground
pressure is raised by 5-7 psi by a pump or by adding • Easy to perform. • Could cause tank or piping to rupture. Many tanks.
a similar hydrocarbon. If pressure is maintained for • Stored product does tank manufacturers recommend against
1 hour, tank is leak free. not always have to applying pressure to a tank.
be removed. • Tank has to be full and all vapour pockets need
• Same-day results. to be identified and removed.
• Trapped air pockets, line swags, and other
• Difficult to interpret the result.
• Potential for product being leaked into the
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 57
Suretest A probe is inserted into the tank (product). The probe • The test is not • Important that technician is trained. Most underground
volumetric leak is sensitive to the outflow or inflow of any liquids affected by • Product volume level restrictions. tanks.
detection within the tank and can detect product loss or gain to temperature. • Product type and temperature change
procedure an accuracy of .001 litres per hour. Temperature • Same-day results. limitations.
sensors are spaced to take the temperature at each • Third-party • Evaluates the lower tank portion, which
level of product. The probe’s microprocessor corrects performance rated. contains product. An alternative test procedure
for volume changes that are due to thermal expansion • Can detect the is required to test above the product level,
or contraction of the product. presence and rate of risers, connections, and underground product
a leak. piping.
• Groundwater level must known to ensure that
equilibrium does not occur within the tank
product level. Product does not leave or enter
the tank during the test procedure and
groundwater does not infiltrate the tank.
Tracer test A tracer gas (or liquid) is injected into the tank. Soil • The production • Lab results are not generally available until 10 Most underground
gas samples are taken from probes installed into the system can remain in to 14 days after the start of the test. tanks.
ground around the tank. A leak is declared if tracer is service through the • The test can be strongly affected by the type of
detected outside the tank. entire procedure. soil (i.e., the test will not work well in low-
• There are no fill or porosity soils) and the groundwater level
underfill around the tank.
requirements. • Tank and piping system may have to be sealed
• The leak location can and pressurized with tracer gas in order to
be determined. evaluate risers and connected underground
• The system is piping.
retesting, since the
probes are
58 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Ullage acoustics The fluid is removed from the tank and a microphone is • Same-day results. • The expertise of the approval holder or licensee Most underground
leak detection test placed into the tank. The storage tank and connected • Can identify the is crucial for this test to effectively determine tanks.
procedure openings are sealed off. A computer connected to the location of leaks. the location of the leak.
microphone measures the amount of background noise • Allows for trouble • Vibrations from nearby equipment or vehicles
present in the tank. 2-3 psi nitrogen pressure is placed shooting while the may interfere with the test, making testing
in the sealed tank system. The computer determines a test is being difficult in some situations.
leak by measuring a change in the background noise performed. • High groundwater levels may affect results.
(caused by the vibrations created by escaping nitrogen). • Nonvolumetric, and
A pressure decline procedure is performed not affected by
simultaneously to evaluate the connected piping. temperature or
vapour pockets.
Underfill leak The underfill test is designed to measure any changes in • Same-day results. • Minimum 40% and maximum 95% product Most underground
detection buoyancy force acting on a probe inserted into the tank. • Not affected by levels required. tanks.
procedure (e.g., It uses mass measurement technology to determine if temperature. • Tank’s product must be a consistent type,
PetroTite II, Alert product is entering or leaving the tank. The technology • Third-party otherwise stratification will affect results.
1000) is based on the fact that buoyancy force only varies as a performance rated. • If the groundwater is above the bottom of the
direct result of a change in the mass of the liquid. It is tank, it increases the product level that will be
not affected by changes in product temperature, since required to perform the test.
the change in volume due to temperature change is
offset by a corresponding change in liquid density.
Vacutect leak All openings to the tank are sealed off and a mild • Can perform • Expertise of the approval holder or licensee is Most underground
detection system vacuum is applied to the tank using a vacuum pump. trouble shooting to crucial for this test to effectively determine the tanks.
The vacuum level is constantly monitored and determine not only location of the leak.
maintained by the computer in the testing unit. While if the system is • Vibrations from nearby equipment or vehicles
under vacuum, vacutect monitors for three things: leaking, but the may interfere with the test. This makes testing
water level, noise (via a hydrophone), and pressure nature and location difficult in some situations.
in the tank. of the leak. • Using the vacuum or the pressure may be
• Same-day results. ineffective in clay soils because it may plug up
• Product can holes in the tank.
• The test is not
performance rated.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 59
Table A2. Integrity tests for underground storage tanks1 (concluded)
Visual inspection In some of the tanks with large manways it may be • Inexpensive. • Tank must be completely emptied and cleaned Will only work on
possible to inspect the tanks visually for leaks. • Easier to locate before a thorough visual inspection can be tanks with large
the leak than other performed. enough manways
methods. • Might overlook smaller leaks. for someone to
• The whole inside • An alternative procedure is required to evaluate enter through.
of the tank can be the connected underground piping.
inspected. • Tank must be completely isolated for safety
• Outside of the tank can’t be visually inspected
unless the tank is unearthed.
60 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Table A3. Explanatory notes
Item Explanation/discussion
Costs The terms “inexpensive” and “expensive” are used in relative terms in this report. Some examples of
costs are that
• ultrasonic testing can cost thousands of dollars;
• a precision leak test can cost approximately $500 and up;
• an external visual inspection performed by an approval holder or licensee working at the facility
has no real cost associated with it.
So in relative terms the external visual inspection is inexpensive compared to the relatively expensive
Note that costs can vary within each test method depending on the availability of equipment, how
difficult the tank is to isolate, whether product needs to be added or removed from the tank, what type
of product is stored in the tank, the size of the tank, and the amount of time required to perform the test.
Additional costs that occasionally need to be factored in are the potential costs associated with taking
the tank out of service while performing the test. This is especially true for larger tanks, where it is more
economical to consider using a testing method that allows the tank to stay in service even if that test is
Difficulty of performing In this report, the statements on the difficulty of implementing a test are used in relative terms. For
the test example, a pressure test is listed as easy to perform. This means that a pressure test is easier to
perform relative to performing something like a tracer test. This designation is only in regards to the
general case. There will be many cases where it is impossible to isolate a tank from the lines connected
to it. Then it would be easier to perform the tracer test (which does not require the complete isolation of
a tank), rather than the pressure test. However, the tester will not be able to identify a test failure as a
tank problem or line problem.
Certification The US EPA has issued protocols that test methodologies must meet in order to be classified as a
precision test. With respect to the downstream petroleum industry, most Canadian jurisdictions have
adopted those parameters, which include the ability to identify a leak as small as 0.38 L/hour, 95%
accuracy, and false positive outcomes of 5% or less. This certification applies to test methodologies for
underground tanks only. Some aboveground tank testing methodologies have had third-party
performance evaluations, but the parameters for sensitivity and accuracy have not been established by
any government body.
For various reasons, the use of only certified, precision tests is not required for the upstream petroleum
industry. However, owners of tanks should consult with the tester to determine if an evaluation has
been completed by a third party to ensure that the test is appropriate.
Applications The application section of the table is vague due to the diversity of tanks used in the industry. A test
may be applicable/inapplicable to a tank based on factors such as size, shape, positioning, environment
(e.g., climate), product stored, material the tank is made out of, how many lines are connected to the
tank, and if the tanks are manifolded.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 61
62 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Alberta Energy and Utilities Board Documents
General Bulletin (GB) 92-4: Requirements for Sulphur Storage Facilities
Informational Letter (IL) 84-11: Approval, Monitoring, and Control of Sulphur Storage Sites
Informational Letter (IL) 85-12: Oil Sands Primary Production Well Spacing Recovery Scheme
Informational Letter (IL) 93-10: Revised Measurement and Accounting Procedures for Southeastern
Alberta Shallow Gas Wells
Informational Letter (IL) 96-7: EUB/AEP Memorandum of Understanding on the Regulation of Oil Sands
Informational Letter (IL) 96-13: Revision of Guide 50 Drilling Waste Management
Informational Letter (IL) 98-1: Coordination of Release Notification Requirements and Subsequent
Informational Letter (IL) 98-2: Suspension, Abandonment, Decontamination, and Surface Land
Reclamation of Upstream Oil and Gas Facilities
Informational Letter (IL) 99-4: EUB Enforcement Process, Generic Enforcement Ladder, and Field
Surveillance Enforcement Ladder
Informational Letter (IL) 99-5: The Elimination of the Surface Release of Produced Water
Interim Directive (ID) 91-3: Heavy Oil/Oil Sands Operations
Interim Directive (ID) 95-3: Storage Requirements for the Upstream Petroleum Industry
Interim Directive (ID) 96-3: Oilfield Waste Management Requirements for the Upstream Petroleum
Guide 23: Guidelines Respecting an Application for a Commercial Crude Bitumen Recovery and
Guide 36: Drilling Rig Inspection Manual
Guide 37: Service Rig Inspection Manual
Guide 50: Drilling Waste Management
Guide 51: Injection and Disposal Wells
Guide 55: Storage Requirements for the Upstream Petroleum Industry (1995 edition)
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 63
Guide 56: Energy Development Application Guide
Guide 58: Oilfield Waste Management Requirements for the Upstream Petroleum Industry
Guide 63: Oilfield Waste Management Facility Inspection Manual
Guide 64: Facility Inspection Manual
Guide 66: Pipeline Inspection Manual (to be released in fall 2001)
Alberta Environment, EPS, 1988, Hazardous Waste Storage Guidelines.
Alberta Environmental Protection, 1994, Remediation Guidelines for Petroleum Storage Tank Sites.
Alberta Environmental Protection, Industrial Wastewater Branch, 1997, Domestic Wastewater
Management Guidelines for Industrial Operations.
Canadian Council of Ministers of the Environment, 1993. “Environmental Code of Practice for the
Measurement and Control of Fugitive VOC Emissions from Equipment Leaks”.
ISBN: 1-895925-12-6
Canadian Council of Ministers of the Environment, 1993, Environmental Code of Practice for
Underground Storage Tank Systems Containing Petroleum Products and Allied Petroleum Products
Canadian Council of Ministers of the Environment, 1994, Environmental Code of Practice for
Aboveground Storage Tank Systems Containing Petroleum Products. (Publication CCME-EPC-LST-71E,
Canadian Council of Ministers of the Environment, 1995, Environmental Guidelines for Controlling
Emissions of Volatile Organic Compounds from Aboveground Storage Tanks, Publication CCME-EPC-
87E, June 1995. (With Supporting Document)
Canadian Standard Association, 1994, Oil and Gas Pipeline Systems Z662-94, Oil and Gas Industry
Environmental Protection and Enhancement Act, Waste Control Regulation, Alberta Regulation 129/96.
Fire Technical Council, Safety Codes Council, November 1997, Alberta Fire Code. (Published by the
National Research Council of Canada) (parts 1-4).
National Fire Code of Canada, 1995. Part 2, “Building and Occupant Fire Safety”; Part 3, “Indoor and
Outdoor Safety”; Part 4, “Flammable and Combustible Liquids.”
National Fire Protection Association 30, 1993 edition, Flammable and Combustible Liquids Code.
National Fire Protection Association 59, 1995 edition, Storage and Handling of Liquefied Petroleum
Gases at Utility Gas Plants.
64 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
National Fire Protection Association 59A, 1996 edition, Standard for the Production, Storage and
Handling if Liquefied Natural Gas.
National Standard of Canada, Propane Installation Code CAN/CGA-B149.2-M91.
Oil and Gas Conservation Act and the Oil and Gas Conservation Regulations as periodically revised.
Alberta Environmental Protection, Environmental Sciences Division, October 1999, Clay Mineralogy
American Petroleum Institute, Health and Environmental Affairs Department, 1993, Assessment of
Tankfield Dike Lining of Materials and Methods (API Publication Number 315, July 1993.
American Petroleum Institute, Health and Environmental Affairs Department, 1998, A Survey of Diked-
Area liner Use at Aboveground Storage Tank Facilities (Publication Number 341, February 1998).
American Petroleum Institute, Regulatory Affairs Department, 1999, Overview of Soil Permeability Test
Methods. (Publication Number 351, April 1999).
ASTM, 1968, reapproved 1994, Standard Test Method for Permeability of Granular Soils (Constant
Head), Annual Book of ASTM Standards 1968 (D 2434, ASTM, 202-206).
ASTM, 1990, reapproved 1997, Standard Test Method for Measurement of Hydraulic Conductivity of
Saturated Porous Materials Using a Flexible Wall Permeameter, Annual Book of ASTM Standards 1990
(D 5084, ASTM, 62-69).
ASTM, 1990, Standard Guide for Comparison of Field Methods for Determining Hydraulic
Conductivity in the Vadose Zone, Annual Book of ASTM Standards 1990 (D 5126, ASTM,
101-109).
ASTM, 1994, Standard Test Method for Infiltration Rate of Soils in Field Using Double-Ring
Infiltrometer, Annual Book of ASTM Standards 1994 (D 3385, ASTM, 331-337).
ASTM, 1997, Standard Test Method (Field Procedure) for Instantaneous Change in Head
(Slug) Tests for Determining Hydraulic Properties of Aquifers, Annual Book of ASTM
Standards 1997 (D 4044, ASTM, 451-453).
Bagchi, Amalendu, 1990, Design, Construction, and Monitoring of Sanitary Landfill (John Wiley &
Sons, Inc.).
Benson, Craig H., and Boutwell, Gordon P. 1992, “Compaction Control and Scale-Dependent
Hydraulic Conductivity of Clay Liners,” Proc., 15th Annual Madison Waste Conference, Madison,
Wisconsin, 62-83.
Benson, Craig H., Zhai, Huaming and Wang, Xiaodong, 1994, “Estimating Hydraulic Conductivity of
Compacted Clay Liners,” Journal of Geotechnical Engineering, Vol. 120, No. 2, February 1994.
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 65
Bjerrum, L., and Huder, J., 1957, “Measurement of the Permeability of Compacted Clays,” Proceedings
of the 4th International Conference on Soil Mechanics and Foundation Engineering, Vol. 1: 6-8.
Craig, R.F, 1997, Soil Mechanics, 6th ed. London: 6-37. (Chapman and Hall).
Daniel, David E., 1990, “Earthen Liners for Land Disposal Facilities,” Waste Containment
Systems: Construction, Regulation, and Performance, GSP No. 26, R. Bonaparte (ed.)
New York: ASCE 21-39.
Daniel, David E., 1990, “Summary Review of Construction Quality Control for Compacted Soil
Liners,” Waste Containment Systems: Construction, Regulation, and Performance,
GSP No. 26, R. Bonaparte (ed.) New York: ASCE 175-189.
Daniel, David E., and Trautwein, Stephen J., 1986, “Field Permeability Test for Earthen Liners,”
Proceedings, In Situ 1986, Blacksburg, Va.: ASCE, 146-160.
Daniel, David E., Anderson, David C., and Boynton, Stephen S., 1985, “Fixed-Wall Versus
Flexible-Wall Permeameters,” Hydraulic Barriers in Soil and Rock, STP 874, ASTM,
107-126.
Johnson, Gary W., Crumley, William S., and Boutwell, Gordon P., 1990, “Field Verification of
Clay Liner Hydraulic Conductivity,” Waste Containment Systems: Construction, Regulation,
and Performance, GSP No. 26, R. Bonaparte (ed.) New York: ASCE, 226-245.
Kenney, T.C., et al., 1992, “Hydraulic Conductivity of Compacted Bentonite-Sand Mixtures,”
Canadian Geotechnical Journal, Vol. 29: 364-374.
Lambe, T. William, 1954, “The Permeability of Fine Grained Soils,” Symposium on
Permeability of Soils, 57th Annual Meeting, STP No. 163, ASTM, Chicago, 56-67.
McBean, Edward A., Rovers, Frank A., and Farquhar, Grahame J., 1995, Solid Waste Landfill
Engineering and Design, New Jersey: Prentice Hall, 209-218.
Mesri, Gholamreza and Olson, Roy E., 1971, “Mechanisms Controlling the Permeability of
Clays,” Clays and Clay Minerals, Vol. 19: 151-158.
Mitchell, James K., Hooper, Don R., and Campanella, Richard G., 1965, “Permeability of
Compacted Clay,” Journal of the Soil Mechanics and Foundations Division, Proceedings of the
American Society of Civil Engineers, Vol. 91, No. 4: 41-65.
Olsen, Harold W., 1962, “Hydraulic Flow Through Saturated Clays,” Clay and Clay Minerals,
Vol. 11: 131-161.
Olson, R.E., and Daniel, D.E., 1981, “Measurement of the Hydraulic Conductivity of Fine
Grained Soils,” Permeablity and Groundwater Contaminant Transport, STP 746,
T.F. Zimmie and C.O. Riggs (eds.), ASTM, 18-64.
Seed, H. Bolten, 1964, Journal of the Soil Mechanics and Foundations Division Proceedings of the
American Society of Civil Engineers, Vol. 90, No. 4: 107-131.
66 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
Seed, H. Bolton, Woodward Jr., Richard J., and Lundgren, Raymond, 1964, “Clay Mineralogical
Aspects of the Atterberg Limits,” Journal of the Soil Mechanics and Foundations Division,
Proceedings. of the American Society of Civil Engineers, Vol. 90, No. 4: 107-131.
Underwriter’s Laboratories of Canada, 1993, “Secondary Containment Liners for Underground
and Aboveground Flammable and Combustible Liquid Tanks” (ULC/ORD-C58.9).
See section below for a list of construction standards for aboveground and underground storage tanks.
American Petroleum Institute, 1994, Design, Construction, Operation, Maintenance, and Inspection of
Terminal and Tank Facilities, API Standard 2610, (first edition, July 1994).
American Petroleum Institute, 1994, Safe Entry and Cleaning of Petroleum Storage Tanks: Planning and
Managing Tank Entry from Decommissioning Through Recommissioning, API Standard 2015, (fifth
edition, May 1994).
American Petroleum Institute, 1996, A Guide to Leak Detection for Aboveground Storage Tanks
(Publication 334, First edition, March 1996).
American Petroleum Institute, 1996, Closure of Underground Petroleum Storage Tanks, API
Recommended Practice 1604 (third edition, March 1996).
American Petroleum Institute, 1996, Inspection of Atmospheric and Low-Pressure Storage Tanks, API
Recommended Practice 575 (First edition, November 1995).
American Petroleum Institute, 1996, Overfill Protection for Storage Tanks in Petroleum Facilities, API
Recommended Practice 2350, (second edition, January 1996).
American Petroleum Institute, 1997, Lining of Aboveground Petroleum Storage Tank Bottoms, API
Recommended Practice 652, (second edition, December 1997).
American Petroleum Institute, October 1997, Liquid Release Prevention and Detection Measures for
Aboveground Storage Facilities, API Publication Number 340.
Myers, Phillip E., 1997, Aboveground Storage Tanks, New York McGraw-Hill Companies Inc., New
Petroleum Equipment Institute, 1994, Recommended Practices for Installation of Underground Liquid
Storage Systems. (EI RP100-94).
Underwriter’s Laboratories of Canada, 1992, Overfill Protection Devices for Flammable Liquid Storage
Tanks (ULC/ORD-C58.15-1992).
Construction Standards for Aboveground and Underground Storage Tanks
API-12B: Bolted Tanks for Storage of Production Liquids
API-12D: Field Welded Tanks for Storage of Production Liquids
EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001) • 67
API-12F: Shop Welded Tanks for Storage of Production Liquids
API-12P: Fiberglass Reinforced Plastic Tanks
API-620: Design and Construction of Large, Welded, Low-Pressure Storage Tanks
API-650: Welded Steel Tanks for Oil Storage
API-653: Tank Inspection, Repair, Alteration, and Reconstruction
ULC-S601: Shop Fabricated Steel Aboveground Horizontal Tanks for Flammable and Combustible
ULC-S602: Aboveground Steel Tanks for Fuel Oil and Lubricating Oil
ULC-S603: Steel Underground Tanks for Flammable and Combustible Liquids
ULC-S603.1: Galvanic Corrosion Protection Systems for Steel Underground Tanks for Flammable and
ULC-S615: Reinforced Plastic Underground Tanks for Flammable and Combustible Liquids
ULC-S630: Shop Fabricated Steel Aboveground Vertical Tanks for Flammable and Combustible Liquids
ULC-S643: Shop Fabricated Steel Aboveground Utility Tanks for Flammable and Combustible Liquids
ULC-S652: Tank Assemblies for Collection of Used Oil
ULC-S653: Aboveground Steel Contained Tank Assemblies for Flammable and Combustible Liquids
ULC/ORD-C58.10: Jacketed Steel Underground Tanks for Flammable and Combustible Liquids
ULC/ORD-C142.5: Concrete Encased Steel Aboveground Tank Assemblies for Flammable and
ULC-S655: Aboveground Protected Tank Assemblies for Flammable and Combustible Liquids
ULC/ORD-C142.18: Rectangular Aboveground Steel Tanks for Flammable and Combustible Liquids
ULC/ORD-C142.21: Aboveground Used Oil Systems
ULC/ORD-C142.22: Contained Vertical Steel Aboveground Tank Assemblies for Flammable and
ULC/ORD-C142.23: Aboveground Waste Oil Tanks
ULC/ORD-C142.13: Mobile Refueling Tanks
ULC/ORD-C142.6: Storage Vaults
ULC/ORD-C142.1: Secondary Containment Tank Assemblies for (Upstream Industry) Unrefined
68 • EUB Guide 55: Storage Requirements for the Upstream Petroleum Industry (December 2001)
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