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#

(iv)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:#

Figure 1: 16 TAC §8.110(b)(2)#

Figure 2: 16 TAC §8.110(b)(2) [See Figures at end of this document.]#

(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.#

Figure 1: 16 TAC §8.101(b)(2) GAS TRANSMISSION LINES Size Pressure Class 2, 3, 4 Class 1 Offshore Less than 100 psig n/a n/a Intervals prescribed by operator Less than or equal to 8 inches Greater than 100 psig and less than 20% SMYS 10 year intervals n/a Intervals prescribed by operator Greater than 20% SMYS 5 year intervals n/a Intervals prescribed by operator Less than 100 psig n/a n/a Intervals prescribed by operator Greater than 8 inches Greater than 100 psig and less than 20% SMYS 5 year intervals n/a Intervals prescribed by operator Greater than 20% SMYS 5 year intervals 10 year intervals Intervals prescribed by operator#

Figure 2: 16 TAC §8.101(b)(2) LIQUIDS PIPELINES Hazardous Liquids Non Rural Rural Crossing of Navigable Waterways Offshore Crude Transmission 5 year intervals 10 year intervals 5 year intervals Intervals prescribed by operator Crude Gathering 5 year intervals *10 year intervals 5 year intervals Intervals prescribed by operator HVL 5 year intervals 5 year intervals 5 year intervals Intervals prescribed by operator Products 5 year intervals 10 year intervals 5 year intervals Intervals prescribed by operator Carbon Dioxide 5 year intervals 10 year intervals 5 year intervals Intervals prescribed by operator *only for onshore line pipe that can accommodate inspection by means of in-line inspection tools#

Source Note: The provisions of this §8.101 adopted to be effective April 30, 2001, 26 TexReg 3214; amended to be effective August 25, 2003, 28 TexReg 6829; amended to be effective November 24, 2004, 29 TexReg 10733; amended to be effective August 28, 2006, 31 TexReg 6715; amended to be effective March 2, 2009, 34 TexReg 1414; amended to be effective August 30, 2010, 35 TexReg 7743; amended to be effective January 6, 2020, 45 TexReg 121; amended to be effective December 9, 2024, 49 TexReg 9960#