16 Tex. Admin. Code § 8.101 - Pipeline Integrity Assessment and Management Plans for Natural Gas and Hazardous Liquids Pipelines
(a) This section
does not apply to plastic pipelines.
(b) By February 1, 2002, operators of
intrastate transmission lines subject to the requirements of 49 CFR Part 192 or
pipeline facilities used in the transportation of hazardous liquids or carbon
dioxide subject to 49 CFR Part 195 shall have designated on a system-by-system
or segment within each system basis whether the pipeline operator has chosen to
use the risk-based analysis pursuant to paragraph (1) of this subsection or the
prescriptive plan authorized by paragraph (2) of this subsection. Hazardous
liquid pipeline operators using the risk-based plan shall complete at least 50%
of the initial assessments by January 1, 2006, and the remainder by January 1,
2011; operators using the prescriptive plan shall complete the initial
integrity testing by January 1, 2006, or January 1, 2011, pursuant to the
requirements of paragraph (2) of this subsection. Natural gas pipeline
operators using the risk-based plan shall complete at least 50% of the initial
assessments by December 17, 2007, and the remainder by December 17, 2012;
operators using the prescriptive plan shall complete the initial integrity
testing by December 17, 2007, or December 17, 2012, pursuant to the
requirements of paragraph (2) of this subsection.
(1) The risk-based plan shall contain at a
minimum:
(A) identification of the pipelines
and pipeline segments or sections in each system covered by the plan;
(B) a priority ranking for performing the
integrity assessment of pipeline segments of each system based on an analysis
of risks that takes into account:
(i)
population density;
(ii) immediate
response area designation, which, at a minimum, means the identification of
significant threats to the environment (including but not limited to air, land,
and water) or to the public health or safety of the immediate response
area;
(iii) pipeline
configuration;
(iv) prior in-line
inspection data or reports;
(v)
prior pressure test data or reports;
(vi) leak and incident data or
reports;
(vii) operating
characteristics such as established maximum allowable operating pressures
(MAOP) for gas pipelines or maximum operating pressures (MOP) for liquids
pipelines, leak survey results, cathodic protection surveys, and product
carried;
(viii) construction
records, including at a minimum but not limited to the age of the pipe and the
operating history;
(ix) pipeline
specifications; and
(x) any other
data that may assist in the assessment of the integrity of pipeline
segments;
(C) assessment
of pipeline integrity using at least one of the following methods appropriate
for each segment:
(i) in-line
inspection;
(ii) pressure
test;
(iii) direct
assessment;
(iv) for gas pipelines
only, guided wave ultrasonic testing (GWUT);
(v) for gas pipelines only, excavation with
direct in situ examination; or
(vi)
other technology or assessment methodology not specifically listed in this
paragraph after approval by the director.
(D) management methods for the pipeline
segments which may include remedial action or increased inspections as
necessary;
(E) periodic review of
the pipeline integrity assessment and management plan every 36 months, or more
frequently if necessary; and
(F)
re-assessment intervals not to exceed the following:
(i) for pipelines subject to 49 CFR Part 195,
a maximum interval of 10 years for onshore line pipe that can accommodate
inspection by means of in-line inspection tools; or
(ii) for pipelines subject to 49 CFR Part
§192.710, a maximum interval of 10 years.
(2) Operators electing not to use the
risk-based plan in paragraph (1) of this subsection shall conduct a pressure
test or an in-line inspection and take remedial action in accordance with the
following schedule:
(c) Within 185
days after receipt of notice that an operator's plan is complete, the
Commission shall either notify the operator of the acceptance of the plan or
shall complete an evaluation of the plan to determine compliance with this
section.
(d) After the completion
of the assessment required under either plan, the operator shall promptly
remove defects that are immediate hazards and, no later than the next test
interval, shall mitigate any anomalies identified by the test that could
reasonably be predicted to become hazardous defects. For pipelines subject to
49 CFR §
192.710, an operator shall follow the
remediation requirements required by
49 CFR §
192.710(f).
(e) If a pipeline that is not subject to this
section undergoes any change in circumstances that results in the pipeline
becoming subject to this section, then the operator of such pipeline shall
establish integrity of the pipeline pursuant to the requirements of this
section prior to any further operation. Such changes include but are not
limited to an addition to the pipeline, change in the operating pressure of the
pipeline, change from inactive to active status, change in population in the
area of the pipeline, or change of operator of the pipeline segment. If a
pipeline segment is acquired by a new operator, the pipeline segment can
continue to be operated without establishing pipeline integrity as long as the
new operator utilizes the prior operator's operation and maintenance procedures
for this pipeline segment. If the population in the area of a pipeline segment
changes, the pipeline segment can continue to operate without establishing
pipeline integrity until such time as the operator determines whether or not
the change in population affects the criteria applicable to the integrity
management program, but for no longer than the time frames established under 49
CFR Part 192 or 195.
Notes
State regulations are updated quarterly; we currently have two versions available. Below is a comparison between our most recent version and the prior quarterly release. More comparison features will be added as we have more versions to compare.
No prior version found.