Technical document
Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
February 2002
2002-0013
Disclaimer
This publication was prepared for the Canadian Association of Petroleum Producers (CAPP) by the Pipeline Technical Committee members. While it is believed that the information contained herein is reliable under the conditions and subject to the limitations set out, CAPP does not guarantee its accuracy. The use of this report or any information contained will be at the user’s sole risk, regardless of any fault or negligence of CAPP or its co-funders.
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The Canadian Association of Petroleum Producers (CAPP) represents 140 companies that explore for, develop and produce natural gas, natural gas liquids, crude oil, synthetic crude oil, bitumen and elemental sulphur throughout Canada. CAPP member companies produce approximately 95 per cent of Canada's natural gas and crude oil. CAPP also has 120 associate members who provide a wide range of services that support the upstream crude oil and natural gas industry. Together, these members and associate members are an important part of a $60-billion-a-year national industry that affects the livelihoods of more than half a million Canadians.
Review by July, 2005
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February 2002Recommended Practice for Mitigation of Internal
Corrosion in Sweet Gas Gathering Systems
Contents
1 Project Scope 1-1
2 Failure Statistics 2-1
3 Corrosion Mechanisms and Mitigation 3-1
4 Recommended Practices 4-1
5 Corrosion Mitigation Techniques 5-1
6 Corrosion Monitoring Techniques 6-1
7 Corrosion Inspection Techniques 6-1
8 Leak Detection Techniques 7-1
9 Repair and Rehabilitation Techniques 8-1
10 Pipeline Integrity Management Systems 9-1
11 PLRTG Participants and Acknowledgements 10-1
Figures
Figure 2-1: Natural Gas Pipeline Operating Failures—Total Failures and Failure Frequency by Reporting Year 2-1
Figure 3-1: An Example of Internal Corrosion in a Sweet Gas Pipeline 3-1
Tables
Table 3-1: Contributing Factors and Prevention of Internal Sweet Gas Corrosion 3-2Table 4-1: Recommended Practices 4-1Table 5-1: Corrosion Mitigation Techniques 5-1Table 6-1: Corrosion Monitoring Techniques 6-1Table 7-1: Corrosion Inspection Techniques 7-1Table 8-1: Leak Detection Techniques 8-1Table 9-1: Repair and Rehabilitation Techniques 9-1
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Corrosion in Sweet Gas Gathering Systems
1.1.1
Project Scope2
This recommended practice addresses design, maintenance and operating considerations for the mitigation of internal corrosion in sweet gas gathering systems constructed with carbon steel materials. For the purpose of this document, sweet gas service is considered to be where the CO2 to H2S ratio is greater than 500:1 (this limit is supplied as a guideline only and may not be absolute). Typically, these would be systems where the H2S concentration is in the low ppm level. This document does not address the deterioration of aluminum and non-metallic materials.
Corrosion is the dominant contributing factor to failures and leaks in pipelines in the province of Alberta. To deal with this issue, the Pipeline Leak Reduction Task Group (PLRTG) of the CAPP Pipeline Technical Committee has developed industry recommended practices to improve and maintain the mechanical integrity of upstream pipelines. They are intended to assist upstream oil and gas producers in recognizing the conditions that contribute to pipeline corrosion failures, and identify effective measures that can be taken to reduce the likelihood of corrosion failures.
These documents are intended for use by corrosion specialists involved with the development and execution of corrosion mitigation programs, engineering teams involved in the design of gathering systems, and operations personnel involved with the implementation of corrosion mitigation programs and operation of wells and pipelines in a safe and efficient manner to mitigate the risk of internal corrosion.
Additional recommended practices being developed by the PLRTG are given below:
Recommended Practice for Mitigation of Internal Corrosion in Sour Gas •Gathering SystemsRecommended Practice for Mitigation of Internal Corrosion in Multiphase •Emulsion Gathering SystemsRecommended Practice for Mitigation of Internal Corrosion in Produced •Water Injection SystemsRecommended Practice for Mitigation of External Corrosion of Pipelines•
For guidance on the standardized approach the Alberta Energy and Utilities Board (EUB) uses for dealing with corrosion-related failures, the reader should refer to the EUB publication Guide 66 – Pipeline Inspection Manual.
Failure Statistics3
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Over the period 2000-2001, failures on natural gas pipelines accounted for 420 •(44%) of the 952 pipeline failures recorded by the EUB. Natural gas as defined for the EUB reporting statistics is gas containing 10 moles per kilomole (1%) or less H2S by volume.In the last three years, internal corrosion has been responsible for •approximately 63% of the failures occurring on natural gas pipelines.In the last three years, over 82% of all pipeline failures have occurred on 2", 3" •or 4" lines.Most of the increase in failures has been occurring on shallow, low pressure •gas systems as commonly found in South Eastern Alberta.
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Figure 2-1: Natural Gas Pipeline Operating Failures—Total Failures and Failure Frequency by Reporting Year
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Corrosion Mechanisms and Mitigation4
Pitting corrosion along the bottom of the pipeline is the primary corrosion mechanism leading to failures in sweet gas pipelines. The common features of this mechanism are:
the presence of water containing any of the following; CO2, bacteria, O2, or •solids.pipelines carrying higher levels of free-water production with no means of •water removal, i.e. well site separation or dehydration.the presence of fluid traps where water and solids can accumulate.•
Vapor phase corrosion is a less common mechanism that has also led to failures. Although not specifically addressed in this recommended practice, many of the preventative measures described in this document will also mitigate this mechanism.
Figure 3-1: An Example of Internal Corrosion in a Sweet Gas Pipeline
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Table 3.1 describes the most common contributors, causes and effects of internal corrosion in sweet gas pipelines. The table also contains corresponding industry mitigative measures being used to reduce sweet gas corrosion.
Table 3-1: Contributing Factors and Prevention of Internal Sweet Gas Corrosion
Contributor Cause/Source Effect MitigationWater Holdup Low gas velocity and •
poor pigging practices allow water to stagnate in the pipelines
Absence of water •separation equipment leads to water wet pipelines
Water acts as the •electrolyte for the corrosion reaction
Chlorides increase the •conductivity of water and may increase the localized pitting rate
Install pigging •facilities and maintain an effective pigging program
Remove water at the •wellsite by separation or dehydration
Control corrosion •through effective inhibition
Solids Deposition
Mainly produced from •the formation
Originate from drilling •fluids, workover fluids and scaling waters
Insufficient gas •velocities and poor pigging practices
Can contribute to under-•deposit corrosion
Scaling can interfere •with corrosion monitoring and inhibition
Install pigging •facilities and maintain an effective pigging program
Initially, flow the •wells to tanks to minimize the effects of work over and completion activities
Scale suppression •
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Oxygen Ingress from •compressors or vapor recovery units (VRU)
Introduced through •endless tubing (ETU) well clean-outs
Ingress from portable •test equipment
Injection of methanol•
Oxygen can accelerate •pitting corrosion at concentrations as low as 50 parts per billion
Typical organic •inhibitor effectiveness can be reduced by the presence of oxygen
Use gas blanketing •and oxygen scavengers
Batch oxygen •scavenger downhole following ETU work overs
Avoid purging test •equipment into the pipeline
Optimize methanol •injection and/or use inhibited methanol
Critical Gas Velocity
Critical gas velocity is •reached when there is insufficient flow to sweep the pipeline of water and solids
A buildup of water and •solids accelerates corrosion
Design pipeline to •exceed critical velocity
Establish operating •targets based on critical gas velocity to trigger appropriate mitigation requirements e.g. pigging, batch inhibition
Detrimental Operating Practices
Ineffective pigging •
Ineffective inhibition•
Inadequate pipeline •suspension
Commingling of •incompatible produced fluids
Accelerated corrosion• Design pipelines to •allow for effective shut-in and isolation
Develop and •implement proper suspension procedures, including pigging and inhibition
Implement and follow •a Pipeline Operation and Maintenance Manual
Test for fluid •incompatibilities
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Carbon Dioxide
Produced with gas from •the reservoir
CO2 concentration can •be increased through fracturing and miscible floods
CO2 dissolves in water •to form carbonic acid
Corrosion rates •increase with increasing CO2 partial pressures
Effective pigging and •inhibition
Bacteria Contaminated drilling •and completion fluids
Contaminated •production equipment
Produced fluids from •the reservoir
Acid producing and •sulfate reducing bacteria can lead to localized pitting attack
Solid deposits provide •an environment for growth of bacteria
Effective pigging •program
Eliminate •introduction of free water into pipelines
Treat with inhibitors •and biocides
Methanol Excessive quantities of •methanol
Use of contaminated •methanol
Methanol injection can •introduce oxygen into the system
High quantities of •methanol may reduce inhibitor effectiveness
Avoid over-injection •of methanol
Effective pigging and •inhibition
Remove free water•
Eliminate the use of •contaminated methanol
Drilling and Completion Fluids
Introduction of bacteria•
Introduction of spent •acids and kill fluids
Introduction of solids•
Accelerated corrosion• Produce wells to •surface test facilities until drilling and completion fluids and solids are recovered
Supplemental pigging •and inhibition of pipelines before and after work over activities
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Management of Change (MOC)
Change in production •characteristics or operating practices
Well re-completions •and work overs
Lack of system •operating history and practices
Changing personnel •and field ownership
Unmanaged change •may result in accelerated corrosion
Implement an •effective MOC process
Implement and follow •a Pipeline Operation and Maintenance Manual
Maintain integrity of •pipeline operation and maintenance history and records
Re-assess corrosivity •on a periodic basis
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Recommended Practices5
Table 4-1 describes the recommended practices for mitigation of internal corrosion in sweet gas pipelines. This table contains a consolidation of industry experience and knowledge used to reduce sweet gas corrosion.
The Alberta Pipeline Act and Pipeline Regulation adopt the requirements of the CSA Z662 Standard, Oil and Gas Pipeline Systems, except where the Act or Regulation specifies otherwise. This Recommended Practice provides some references to certain CSA Z662 sections for information and clarity. This recommended Practice further supports the development of corrosion control practices, and the development of a Pipeline Operation and Maintenance Manual, as required by CSA Z662 and the Alberta legislation.
A pipeline integrity management system provides a framework to document, implement and assure compliance to recommended practices. It is not the intention of this section to describe all components of an integrity management system (refer to section 10).
Table 4-1 Recommended Practices
Element Recommended Practice
Benefit Comments
Dehydration Install gas dehydration •facilities
Ensure dehydration •units are operating properly
Elimination of water •from the system eliminates corrosion
Consider mitigation •requirements for upset conditions
Water Removal
Install water separation •and removal
Removal of free water •from the system reduces the potential for corrosion
Only free water is •being removed therefore pigging and mitigation measures may still be required
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Materials of Construction
Use normalized ERW •line pipe that meets the requirements of CSA Z245.1 Steel Pipe
Use corrosion resistant •materials such as High Density Polyethylene (HDPE) or fiber reinforced composite materials as per CSA-Z662, Clause 13 Plastic Pipelines
Normalized ERW •prevents preferential corrosion of the weld zone
Non-metallic materials •are corrosion resistant
ERW seams should be •placed on the top half of the pipe to minimize preferential corrosion
Non-metallic •materials may be used as a liner or a free standing pipeline depending on the service conditions
Pipeline Isolation
Install valves that •allow for effective isolation of pipeline segments
Allows the effective •suspension and discontinuation of pipeline segments
Reduces the amount of •lost production and flaring during maintenance activities
Removes potential •“deadlegs” from the gathering system
Pipeline Sizing
Design pipeline system •to maintain flow above critical velocity
Using smaller lines •where possible increases gas velocity and reduces water holdup and solids deposition
Consider future •operating conditions such as changes in well deliverability
Consider the future •corrosion mitigation cost of oversized pipelines
Consider the impact •of crossovers, line loops and flow direction changes
Pigging Capability
Install or provide •provisions for pig launching and receiving capabilities
Use consistent line •diameter and wall thickness
Use piggable valves, •flanges, and fittings
Pigging is one of the •most effective methods of internal corrosion control
Multi-disc/cup pigs •have been found to be more effective than ball or sponge type pigs
Receivers and •launchers can be permanent or mobile
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Inspection Capability
Install or provide •capability for inspection tool launching and receiving
Use consistent line •diameter and wall thickness.
Use piggable valves, •flanges, and fittings
Internal inspection •using intelligent pigs is the most effective method for confirming overall pipeline integrity
Proper design allows •for pipeline inspection without costly modifications or downtime
Consideration should •be given to the design of bends, tees, and risers to allow for navigation by the inspection devices
Corrosion Assessment
Evaluate operating •conditions (temperature, pressure, well effluent and volumes) and prepare a corrosion mitigation program
Integrate corrosion •mitigation program into a Pipeline Operation and Maintenance Manual
Communicate •corrosion assessment, operating parameters and the mitigation program to field operations and maintenance personnel
Re-assess corrosivity •on a periodic basis and subsequent to a line failure
Understand and •document design and operating parameters to effectively manage corrosion
Refer to CSA Z662 •Clause 9 – Corrosion Control
Define acceptable •operating ranges consistent with the mitigation program (See Section 10)
Consider the effects of •oxygen, methanol, bacteria and solids
Consider •supplemental requirements for completions and workover fluids
Completion and Workover Practices
Produce wells to •surface test facilities until drilling and completion fluids and solids are recovered
Removal of stimulation •and workover fluids reduces the potential for corrosion
Supplemental pigging •and inhibition of pipelines before and after workover activities
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Corrosion Inhibition and Monitoring
Integrate a corrosion •inhibition and monitoring strategy into a Pipeline Operation and Maintenance Manual
Communicate the •corrosion inhibition and monitoring program to field operations and maintenance personnel
Develop suspension •and lay up procedures
Allows for an effective •corrosion mitigation program
Refer to Section 5 for •Corrosion Mitigation Techniques
Refer to Section 6 for •Corrosion Monitoring Techniques
Refer to CSA Z662 •Clause 9 – Corrosion Control
Number and location •of monitoring devices is dependent on the predicted corrosivity of the system
Consider provisions •for chemical injection, monitoring devices, and sampling points
Inspection Program
Integrate an inspection •strategy into a Pipeline Operation and Maintenance Manual
Communicate the •inspection program to field operations and maintenance personnel
Provides assurance that •the corrosion mitigation program is effective
Refer to Section 7 for •Corrosion Inspection Techniques
Refer to CSA Z662 •Clause 9 – Corrosion Control
Management of Change
Implement an effective •MOC process
Maintain integrity of •pipeline operation and maintenance records
Ensures that change •does not impact the integrity of the pipeline system
Unmanaged change •may result in accelerated corrosion
Leak Detection
Integrate a leak •detection strategy into a Pipeline Operation and Maintenance Manual
Permits the detection of •leaks
Refer to Section 8 for •Leak Detection Techniques
Technique utilized •depends on access and ground conditions
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Repair and Rehabilitation
Inspect to determine •extent and severity of damage prior to carrying out any repair or rehabilitation
Based on inspection •results, use CSA Clause 10.8.2 to determine extent and type of repair required
Implement or make •modifications to corrosion control program after repairs
Prevents multiple •failures on the same pipeline
Prevents reoccurrence •of problem
Refer to Section 7 for •Corrosion Inspection Techniques
Refer to Section 9 for •Repair and Rehabilitation Techniques
Refer to CSA Z662 •Clause 10.8.5 for repair requirements
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Corrosion Mitigation Techniques6
This section describes common techniques that should be considered for the mitigation of internal corrosion in sweet gas pipelines.
Table 4-1 Corrosion Mitigation Techniques
Technique Description CommentsPigging Periodic pigging of pipeline •
segments to remove liquids, solids and debris
Common practice to help •producibility of low volume gas wells
Can be an effective method of •cleaning pipelines and reducing potential for bacteria colonization and under-deposit corrosion
Selection of pig type and sizing •is important if cleaning of the line desired
Requires facilities for launching •and receiving pigs
Batch Corrosion Inhibitor Chemical Treating
Periodic application of a batch •corrosion inhibitor to provide a protective barrier on the inside of the pipe
Provides a barrier between •corrosive elements and pipe surface
Application procedure is •important in determining effectiveness (eg. volume of chemical, diluent used, contact time, and application interval)
Should be used in conjunction •with pigging to remove fluids and clean line.
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Bactericide Chemical Treating
Periodic application of a •bactericide to kill bacteria in the pipeline system.
Effective in killing bacteria in •systems known to contain bacteria
Batch application typically most •effective (e.g. application down-hole leads to ongoing treatment of produced fluids)
The use of improperly selected •bactericides can create a foam that can be a serious operational issue
Oxygen Control
Use gas blanketing and oxygen •scavengers
Batch oxygen scavenger •downhole following ETU work overs
Avoid purging test equipment into •the pipeline
Optimize methanol injection •and/or use inhibited methanol
Oxygen ingress will accelerate •the corrosion potential
Continuous Corrosion Inhibitor Chemical Treating
Continuous injection of a •corrosion inhibitor to reduce the corrosivity of the transported fluids or provide a barrier film
Less common technique due to •low treatment volumes and equipment requirements (pumps and tanks)
Chemical pump reliability is •important in determining effectiveness
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Corrosion Monitoring Techniques7
This section describes the most common techniques for monitoring corrosion and operating conditions associated with internal corrosion in sweet gas pipelines.
Table 6-1: Corrosion Monitoring Techniques
Technique Description CommentsWell Effluent Testing
Initial and periodic testing of well •effluent constituents and production rates
Fluids analysis and production rates •are used to initially determine corrosion potential and should be periodically re-assessed
Water Analysis Ongoing monitoring of water for •chlorides, dissolved metals, bacteria, suspended solids and chemical residuals
Changes in water chemistry will •influence the corrosion potential
Trends in dissolved metal •concentration can indicate changes in corrosion activity
Chemical residuals can be used to •confirm the level of application
Sampling location and proper •procedures are critical for accurate results
Production Monitoring
Ongoing monitoring of production •conditions such as pressure, temperature and flow rates
Changes in operating conditions will •influence the corrosion potential. Production information can be used to assess corrosion susceptibility based on fluid velocity and corrosivity
Mitigation Program Compliance
Ongoing monitoring of mitigation •program implementation and execution
The corrosion mitigation program •must be properly implemented to be effective
The impact of any non-compliance to •the mitigation program must be evaluated to assess the effect on corrosion
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Corrosion Coupons
Used to indicate general corrosion •rates, pitting susceptibility, and mitigation program effectiveness
Coupon type, placement, and data •interpretation are critical to successful application of this method
Coupons should be used in •conjunction with other monitoring and inspection techniques
Bio-spools Used to monitor for bacteria presence •and mitigation program effectiveness
Bio-spool placement and data •interpretation are critical to successful application of these methods
Bio-spools should be used in •conjunction with other monitoring and inspection techniques
Electrochemical Monitoring
There are a variety of methods •available such as electrochemical noise, linear polarization, electrical resistance, and field signature method
The device selection, placement, and •data interpretation are critical to successful application of these methods
Continuous or intermittent data •collection methods are used
Electrochemical monitoring should be •used in conjunction with other monitoring and inspection techniques
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Corrosion Inspection Techniques8
This section describes common techniques that should be considered for the detection of internal corrosion in sweet gas pipelines.
Table 7-1: Corrosion Inspection Techniques
Options Technique CommentsIntelligent pigging
Magnetic flux leakage is the most •common technique
Effective method to accurately •determine location and severity of corrosion
Intelligent pigging can find internal •and external corrosion defects
The tools are available as self •contained or tethered
The pipeline must be designed or •modified to accommodate intelligent pigging
Non-Destructive Examination (NDE)
Ultrasonic inspection, radiography or •other NDE methods can be used to measure metal loss in a localized area
Evaluation must be done to •determine potential corrosion sites prior to conducting NDE
NDE is commonly used to verify •intelligent pig results, corrosion at excavation sites and above ground piping
The use of multi-film radiography is •an effective screening tool prior to using ultrasonic testing
Corrosion rates can be determined •by performing periodic NDE measurements at the same locations
Video Camera Used as a visual inspection tool to •locate internal corrosion
Can be used to determine the •presence of corrosion damage, but it is difficult to determine severity
This technique may be limited to •short inspection distances
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Boroscope Used as a visual inspection tool to •locate internal corrosion
Can be used to determine the •presence of corrosion damage, but it is difficult to determine severity
This technique is limited to short •inspection distances
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Leak Detection Techniques9
This section describes common techniques that should be considered for the detection of pipeline leaks caused by internal corrosion in sweet gas pipelines. Proactive leak detection can be an effective method of finding small leaks and mitigating the consequences of a major product release or spill.
Table 8-1: Leak Detection Techniques
Technique Description CommentsFlame Ionization Survey
Electronic instrumentation used to •detect very low concentrations of gas
Equipment is portable and very •sensitive
Infrared Thermography
Thermal imaging is used to detect •temperature change on Right-of-Way due to escaping gas
Need sufficient volume of escaping •gas to create an identifiable temperature difference
Normally completed using aerial •techniques
Right-of-Way (ROW) Surveillance
Visual inspection by ground access or •aerial surveillance to look for indications of leaks
Indications include soil subsidence, •gas bubbling, and water, soil, or vegetation discoloration
Can be used in combination with •infrared thermography and flame ionization surveys
Odor Detection Odorant detection using trained •animals and patented odorants
Capable of detecting pinhole leaks •that may be otherwise non-detectable
Production Monitoring
Volume balancing or pressure •monitoring to look for indications of leaks
Changes in production volumes or •pressure can indicate a pipeline failure
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Repair and Rehabilitation Techniques10
This section describes common techniques used for repair and rehabilitation of pipelines damaged by internal sweet gas corrosion.
Prior to the repair or rehabilitation of a pipeline the appropriate codes and guidelines should be consulted, including:
CSA Z662-99, Oil and Gas Pipeline Systems, Section 10.8, “Permanent and •Temporary Repair Methods”CSA Z662-99, Oil and Gas Pipeline Systems, Section 13, “Plastic Pipelines” •for requirements for polymer liners, polymer pipes, and composite pipes EUB Guide 66 Pipeline Inspection Manual, Appendix 3 “EUB Pipeline •Inspectors' Guide to Corrosion Failure Procedures” for pipeline restoration follow up activities
Table 9-1: Repair and Rehabilitation Techniques
Technique Description CommentsPipe Section Replacements
Remove damaged section(s) and •replace.
When determining the quantity of pipe •to replace consider the extent of corrosion and the condition of the remaining pipeline
Impact on pigging capabilities must •be considered (use same pipe diameter and similar wall thickness)
The replaced pipe section should be •coated with corrosion inhibitor prior to commissioning
Repair Sleeves Reinforcement and pressure-•containing sleeves may be acceptable for temporary or permanent repairs of internal corrosion as per the limitations stated in CSA Z662
For internal corrosion it may be •possible in some circumstances for the damaged section to remain in the pipeline as per the requirements in CSA Z662 Section 10.8
Different repair sleeves are available •including composite, weld-on and bolt-on types. The sleeves must meet the requirements of CSA Z662 Section 10.8
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Polymer Liners A polymer liner is inserted in the steel •pipeline
The steel pipe must provide the •pressure containment capability
A variety of materials are available •with different temperature and chemical resistance capabilities
Impact on pigging capabilities must •be considered
Polymer liners may eliminate the need •for internal corrosion mitigation, corrosion monitoring and inspection
Reduction of inhibition programs may •impact the integrity of connecting headers and facilities constructed from carbon steel
Composite or Plastic Pipeline
Freestanding composite or plastic •pipe can be either plowed-in for new lines, or pulled through old pipelines
This pipe must be designed to provide •full pressure containment
A variety of materials are available •with different temperature and chemical resistance capabilities
Freestanding plastic pipelines may be •limited to low-pressure service
Freestanding composite pipelines may •not be permitted for gas service
Impact on pigging capabilities must •be considered
Composite or plastic pipelines may •eliminate the need for internal corrosion mitigation, corrosion monitoring and inspection
Reduction of inhibition programs may •impact the integrity of connecting headers and facilities constructed of carbon steel
Pipeline Replacement
Alteration or replacement of pipeline •allows proper mitigation and operating practices to be implemented
Must be piggable and inspectable•
Refer to Section 4 “Recommended •Practices ” in this document for details
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Pipeline Integrity Management Systems11
Describing an entire pipeline integrity management system is outside the scope of work undertaken by the PLRTG. One fundamental component of such a system is valid practices to mitigate corrosion. Compiling these recommended practices was the primary goal of the PLRTG. However, to properly manage corrosion of pipelines, the operator should develop and implement a pipeline integrity management system. The pipeline integrity management system should encompass all aspects of the pipeline design, operation and maintenance. Some of the aspects that need to be considered include:
Design•Risk Assessment Methodology•Deterioration, Corrosion and Failure Modes Assessments•Maintenance Strategies•Operating Practices•Corrosion Control Strategy•
Inspection •Mitigation •Monitoring •
Repair Strategies•
Two key processes that need to be in place to support an effective pipeline integrity management system are:
Management of Change (MOC) Process11.1
MOC should address not only mechanical changes to the design, but all •types of change including mechanical, process, operating and personnel changes that could impact on the safe operation of the pipeline. The MOC process provides the opportunity for the key operating, maintenance, technical and management groups to assess the impact of a potential change, and address any additional measures that need to be implemented and documented as part of the change.
Operating Parameters Monitoring Process11.2
It is essential to establish a set of operating parameters that form the •premises used for the design of the pipeline and the required corrosion control strategy and program. It is important to have the capability to monitor the key operating parameters and limits, notify the necessary personnel when a deviation from the specified operating limits has occurred, and implement the required corrective actions to address the variance.
The key operating parameters include:•Gas, water and hydrocarbon compositions•
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
Gas, water and hydrocarbon flow rates•Inhibitor, methanol and biocide application rates•Operating temperatures and pressures •Pigging, monitoring and inspection frequencies •
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February 2002 Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems
PLRTG Participants and Acknowledgements12
The members of the CAPP Pipeline Leak Reduction Task Group (PLRTG) included:
Alan Miller – PanCanadian Resources•Randy Damant – Skystone Engineering Inc.•Ray Goodfellow – Chevron Texaco•Colin McGovern – Devon Energy Canada•Kevin Goerz – Shell Canada Limited•Dave Grzyb – Alberta Energy and Utilities Board•Ray Price – BP Canada Energy Company•Scott Oliphant – Rio Alto Exploration•Gordon Tunnicliffe – Anadarko Canada Corporation •Joe Dusseault – AEC Oil & Gas•Bob Shapka – Talisman •
The members of the PLRTG would like to express their gratitude and appreciation to Ms. Tanis Jenson, Ms. Christianne Street and Ms. Camila McKenna for their assistance in the preparation of the Recommended Practice for Mitigation of Internal Corrosion in Sweet Gas Gathering Systems.