A recent trend worldwide has been the movement towards standardization
and increased vigilance in the monitoring of pipeline and storage vessel
operations. Regulatory boards and local government departments typically
undertake this monitoring, with the end goal of reducing leaks and failures
that pose risks to the safety of employees and the general public, and
to the environment. The impact to pipeline and production facility operators
is that corrosion monitoring is becoming mandatory in many jurisdictions.
Canadian jurisdictions are moving towards mandatory monitoring, one example
being Alberta, the top energy-producing province in the country. After
studying performance records and trends of oilfield production and transmission
facilities in the 1990’s, the Alberta Energy and Utilities Board
revised its regulations in 2001. Revisions included standardizing pipeline
inspection requirements and a new system of measuring and penalizing noncompliance.
aspect to pipeline operations that came out of the study was the recognition
of the importance of an internal corrosion monitoring program. The revised
regulations, entitled Guide 66, now categorize this type of monitoring
as mandatory for operations.
66 cites specific regulatory requirements detailed in the Alberta Pipeline
Act and Regulation and the CSA Z662 Standard, Oil and Gas Pipeline Systems.
The guide also includes the EUB Pipeline Inspectors' Guide to Corrosion
Failure Procedures, which details the requirements specific to follow-up
of corrosion incidents. The EUB developed this section in consultation
with industry pipeline corrosion specialists.
lists Satisfactory and Minor (U) / Major (M) / Serious (S) unsatisfactory
inspection criteria, as well as consequences for noncompliance as per
the EUB's enforcement process. A summary of the guide’s application
to internal corrosion control is as follows:
51. Internal Corrosion Control - Appropriate methods to detect
and mitigate internal corrosion are employed to protect pipelines transporting
any liquid or gas or combination thereof that may cause the interior to
corrode (CSA Standard Z662, Clause 9; Pipeline Regulation, Section 53(a,b,c).
must monitor to determine the effectiveness of mitigation procedures (CSA
Standard Z662, Clauses 9.4.3 and 9.5). The results of the inspection or
tests must be recorded and retained for a minimum of six years (Pipeline
Regulation, Section 53).
in corrosive environment
in non-corrosive environment
and mitigation in corrosive environment
of inspection and corrosion monitoring programs not available
monitoring or mitigation program in place and/or company is not following
or mitigation program in place for pipelines with major potential
public and environmental consequences, as referenced in Appendix 3,
to follow the investigative procedures detailed in Corrosion Guide,
Sections 2, 3, and 4 (Appendix 3).
to follow the investigation procedures detailed in Corrosion Guide,
Sections 1.1, 1.2, and 3 (Appendix 3).
pipe body failures, stress corrosion cracking, hydrogen-induced cracking,
brittle cracks, running cracks, failure of plastic pipes, failure due
to fatigue and lamination separations.
Corrosion Mitigation Plan
If a failure indicates a corrosive condition, the operator must have a
documented plan to prevent further corrosion failures. This plan must
consider other lines within the same pipeline system and include details
of the mitigative measures to be adopted. The Pipeline Regulation, Sections
52 and 53, requires the operator to maintain records of any corrosion
maintenance activities for at least six years. Typical mitigative and
monitoring measures for internal corrosion could include combinations
of the following:
- corrosion coupons
- electronic monitoring devices
- inhibition (continuous and/or batch)
- lab analysis to determine failure cause
- pipeline cleaning by pigging or chemicals
- fluids analysis
- flow modelling
expertise is insufficient, the operator should enlist expert third-party
assistance. A pressure test alone will not be considered as adequate proof
of long-term integrity. Note that sour natural gas lines require pressure
testing to 1.4 x MOP. Random cutouts, ultrasonic inspection, and shadow
shots are not adequate proof of integrity.
The EUB has
adopted an enforcement process that includes guidelines for EUB enforcement
actions when dealing with regulatory noncompliance. Companies failing
to meet requirements or follow EUB direction will be subject to escalating
Guide 66 on-line, click: http://www.eub.gov.ab.ca/bbs/products/guides/g66.pdf
EUB Report 98-G, Pipeline Performance in Alberta, 1980-1997 examines operating
trends over the past 18 years. Several conclusions reached were:
comprise about 87% of all failures.
of leaks are caused by corrosion. Of these, half are caused by internal
failures occur on water and multiphase oil effluent (a mix of oil, water
and gas) pipelines. These small-diameter, lower-volume pipelines are
common in Alberta’s oil and gas industry because of their use
in gathering systems.
overall frequency for sour gas pipeline failures remains very low and
has declined over the last decade. This may be due to the extra care
that operators are taking in corrosion inspection, monitoring, and mitigation
for sour lines.
decline in external corrosion failures also indicates advancements in
and use of superior pipeline protective coatings in Alberta.
pipeline age can be a factor, proper corrosion prevention and failure
mitigation programs allow older pipelines to be operated safely and
(Source: EUB Website)