NPRM: Safety of Gas Transmission& Gathering PipelinesDocket: PMHSA-2011-0023

Chris FoleyVice President, RCP Inc.cfoley@rcp.comwww.rcp.com

New / Revised Definitions• Close interval survey• Distribution center• Dry gas or dry natural gas• Electrical Survey*• Gas processing plant• Gas treatment facility• Gathering line (onshore)• Hard spot• In-line inspection (ILI)• In-line inspection tool• Legacy construction

• Legacy pipe• Moderate consequence area• Modern pipe• Occupied site• Onshore production facility• Significant Seam Cracking• Significant Stress Corrosion Cracking• Transmission line*• Wrinkle bend

*Revised definitions

New IBR ConsensusStandards (9)• API STD 1163-2005, “In-Line Inspection Systems Qualification Standard” 1st edition, August 2001• NACE Standard Practice 0102-2010, "Inline Inspection of Pipelines" Revised 2010• NACE Standard Practice 0204-2008, "Stress Corrosion Cracking Direct Assessment" Revised 2008• NACE Standard Practice 0206-2006, "International Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas“• ANSI/ANST ILI-PQ-2010, "In-line Inspection Personnel Qualification and Certification" 2010• Battelle's Experience with ERW and Flash Welding Seam Failures: Causes and Implications• Battelle Memorial Institute, "Models for Predicting Failure Stress Levels for Defects Affecting ERW and Flash-Welded Seams“• Battelle Final Report No. 13-021, "Predicting Times to Failures for ERW Seam Defects that Grow by Pressure Cycle Induced Fatigue “• Battelle Memorial Institute, "Final Summary Report and recommendations for the Comprehensive Study to Understand Longitudinal ERW Seam Failures -- Phase 1"

New Gathering Line Definition& Regulated Type• API RP80 no longer IBR• New definitions

– Gathering Line (onshore), Gas Processing Plant, Gas Treatment Facility, and Onshore Production Facility / Operation– Production will end at farthest of the last meter used for production allocation, or comingling from 2+ wells

• Gathering lines >= 8” and >=20% SMYS in Class 1 areas– Regulated as Type A, Area 2 (new classification)– Type A, Area 2 must (mostly) meet the requirements for Type B lines, with 2 years to comply– Operators will be required to document the beginning and endpoints of each non-regulated and regulated gathering line in 6 months

Texas Gas Gathering & Production• §8.1 General Applicability and Standards

– (1) The rules in this chapter establish minimum standards of accepted good practice and apply to: • (B) onshore pipeline and gathering and production facilities, beginning after the first point of measurement and ending as defined by 49 CFR Part 192 as the beginning of an onshore gathering line. The gathering and production beyond this first point of measurement shall be subject to 49 CFR Part 192.8 and shall be subject to the rules as defined as Type A or Type B gathering lines as those Class 2, 3, or 4 areas as defined by 49 CFR Part 192.5;

• §8.5 Definitions (28) Transportation of gas :– “The gathering, transmission, or distribution of gas by pipeline or its storage within the State of Texas. For purposes of safety regulation, the term shall include onshore pipeline and production facilities, beginning after the first point of measurement and ending as defined by 49 CFR Part 192 as the beginning of an onshore gathering line. “

Moderate Consequence AreaMCA• Moderate consequence area means an onshore area that is within a potential impact circle, as defined in § 192.903, containing five (5) or more buildings intended for human occupancy, an occupied site, or a right-of-way for a designated interstate, freeway, expressway, and other principal 4-lane arterial roadway as defined in the Federal Highway Administration…• Occupied site definition only requires 5 or more persons at a location 50 days in 12-month period OR in a building, 5 days/week, 10 weeks in any 12-month period.

– Beaches, playgrounds, recreational areas, 4-H & religious facilities, etc.

MCA

Occupied SitePIR

MCA

PIRPIRPIR PIR

MCA

PIR

Management of ChangeMOC 192.13(d)Applicability (Onshore Gas Transmission)• Design• Operation• Environmental• Maintenance• Technical• Physical• Procedural• Organizational decisions made on pipeline

MOC Process• Reason for change• Authority for approving changes• Analysis of implications• Acquisition of required work permits• Documentation• Communication of change to affected parties• Time limitations• Qualification of staff

Codify Management of Change process from ASME/ANSI B31.8S, Section 11

Additional Corrosion Control Requirements• Conduct coating inspection, post backfill

– New construction, repair or replacement– W/in 3 months from placing in-service, DCVG or ACVG– Repair moderate/severe damage w/in 6 months– Records retained for the life of pipe

• Cathodic protection (ex. rectifiers, p/s potentials) deficiencies must be remediated prior to next scheduled inspection & confirmed w/CIS– Changes made to App. D Criteria for CP & Determination Measurements

• Interference current “program” including surveys detecting presence & level of stray currents– Remediate detrimental conditions w/in 6 months of survey completion

• Internal corrosion “program” including monitoring, sampling & mitigation program requirements– Injection points w/potentially corrosive constituents, use gas quality monitoring equipment– Mitigate corrosive constituents (ex. inhibitors, cleaning pigs, etc.)– Monitor gas stream quality twice per year, make adjustments as necessary

Records• New Appendix A

– Records Retention Schedule for Transmission Pipelines• “Reliable” + Traceable, Verifiable, and Complete (RTVC)

– RTVC standard applies to “records that demonstrate compliance with this Part” (i.e. ALL of Part 192 !?!)• Material records for original steel pipe manufacturing, valves & other components >= 42,000 psi

– Transmission pipelines only– Manufacturing specification, tests, inspections, pressure rating, yield strength, ultimate tensile strength, chemical composition

• If material records are NOT available for onshore, steel, transmission pipelines, located in HCA’s or Class 3 or 4 areas … re-establish per– 192.607 Verification of Pipeline Material: Onshore steel transmission pipelines

Verification of Pipeline Materials 192.607If RTVC material records not available• Material documentation plan w/in 6 months

– No timeline given to complete verification• NDE, destructive, examinations & assessments

– Very prescriptive criteria• Defines population types of non-RTVC materials• Minimum number/spacing of excavations per population type• Detailed list of pipeline attributes not necessarily required for MAOP (toughness, coating type, etc.)• Prescriptive tests for SCC, seam cracking, selective seam weld corrosion

– If inconsistencies found w/in test population, more tests required– Other or alternate technology

• submitted to PHMSA >180 days prior to use• must receive “no objection” letter from PHMSA

MAOP Verification, Onshore Steel Pipelines, 192.624• Applicability

– Located in HCA, class 3 or 4, or ILI capable MCA– Experiences a reportable incident due to manufacturing, construction, fabrication, cracking defect since last Subpart J test– Pressure test records used to establish MAOP are not RTVC– “Grandfathered” pipeline (MAOP est. using 192.619(c))

• Completion dates for MAOP verification– Develop plan within 1 year– 50% within 8 years– 100% within 15 years

• MAOP determination methods– Pressure test

• spike test legacy pipe or reportable incident due to manufacturing, construction, fabrication, or crack-like defects– Pressure reduction

• Considerable amount of prescriptive if/then requirements– Engineering Critical Assessment

• Considerable amount of data analysis & predicted failure pressure analysis– Pipe replacement– Pressure reduction for <=8”, <=150’PIR, <30% SMYS & not ILI or pressure test capable

• Numerous prescriptive actions (DA, odorization, increased patrols, etc)– Alternative technology approved by PHMSA

• Written request >180 days, must receive “no objection letter”

MAOP Verification, Onshore Steel Pipelines, 192.624

• Fracture mechanic modeling for failure stress & crack growth analysis – Applies to any pipeline regardless of HCA, class location…– If segment susceptible to cracks based upon any available information– Determine remaining life of pipeline

• If calculated remaining life <5 years, pressure test or reduce pressure within 1 year• Otherwise, re-evaluate at the lesser of 50% estimated remaining life or 15 years• Reviewed & confirmed by metallurgy & fracture mechanics SME

• Records to accomplish 192.624 must be RTVC

MAOP Verification, Onshore Steel Pipelines, 192.624

Non-HCA IntegrityAssessments 192.710• Requires integrity assessments for non-HCA segments:

– All Class 3 and 4 Locations– Moderate Consequence Area’s that are piggable.

• Initial assessment within 15 years• Periodic reassessment every 20 years thereafter• Operators can take credit for prior assessments of MCA segments that were conducted in conjunction with and HCA assessment without performing another initial assessment

Repair Criteria forNon-HCA’s• Immediate repair conditions (Non-HCA)

– Similar to HCA repair criteria– Pressure reduction until repairs are complete, lesser of the following

• Remaining strength calculation commensurate w/class location design factor– corrosion defects

• Predicted failure pressure calculation– gauges, dents, cracks, selective seam weld defects

• 80% pressure at time of discovery• 2-Year repair conditions (Non-HCA)

– Similar to HCA 1-year repair criteria• Monitored conditions (Non-HCA)

– Similar to HCA monitor criteria• In situ direct examination of crack defects

– Prescriptive requirements and procedures for • Technology performance criteria• Qualification of SME (type of DA, metallurgy, fracture mechanics)

Additional Integrity MgmtRequirements• Prescriptive data attributes to be collected (48+)

– Ex. installation year, construction inspection reports, O&M inspection reports, performance of safety equipment, vandalism, industry experience for failure history, aerial photography• Address SME input bias

– Document names of SME’s who submit information– Use outside/independent technical reviews to assess quality of processes and SME judgement

• Employ spatial analysis and interrelationships of anomalous conditions and threats– Corrosion coincidence w/foreign line crossing– Pipeline damage where overhead imagery shows encroachment– Storage of data on GIS alone is insufficient (must be analyzed)

Additional Integrity MgmtRequirements• Prescriptive risk assessment factors

– Evaluate interactive threats– Validation of risk anlysis results

• Consistent w/operator & industry experience• Sensitivity analysis of probability of failure & associated consequences

– Leverage risk analysis to develop P&M measures– Consequence analysis should include worst case scenario from initial failure to termination point– Analyze the likelihood of failures– Evaluate effectiveness of currently deployed P&M measures– Compensate for uncertainties in the model & data– Evaluate risk reduction from reduced anomaly remediation & assessment intervals

Assessment Methodologies• Prescriptive ILI requirements

– Additional defects to be detected• Ex. crack-like defects, hard spots, deformation

– New IBR standards– Qualifications for people analyzing ILI data– Must consider ILI uncertainties

• Ex. tool tolerance, detection threshold, sizing accuracy, location accuracy, etc.• Pressure testing & spike testing– Lists the applicable defects/threats for pressure test and spike test assessments

• Ex. crack-like defects, susceptible seams, corrosion, etc.• Excavation / In situ direct examinations– Ex. visual exams, radiography, UT, mag particle inspection

• Guided Wave Ultrasonic Testing• Limits Direct Assessments

– Only allowed in conjunction with or when above methods not capable or practical (192.921(a)(6))– Prescribes new IBR standards for ICDA & SCCDA

• Prescribes PHMSA notification if determination of anomalous conditions can’t be made within 180 days

Spike Testing192.506• Applicability

– Steel transmission operating >= 30% SMYS– Existing integrity threats that cannot be addressed via ILI or direct assessment

• Spike test substantiates proposed MAOP• Requirements

– Hydrostatic test– conducted within 1st two hours of 192.505 test– w/elevated pressure equivalent to the lesser of 150% MAOP or 105% SMYS– held for a minimum of 30 minutes

• Re-testing– If integrity threat is time dependent (ex. crack-like defects), – Retest interval & periodic testing determined via 192.624(d)

• Fracture mechanic modeling• Alternative Technology or Alternative Technical Evaluation Process

• Request to PHMSA 180 days prior, must receive “no objection letter”

Revised Repair Criteria forHCA’s• Additional immediate repair conditions (HCA)

– Predicted failure pressure <= 1.1 MAOP for any class location using RTVC records– Metal loss >=80%– Corrosion affecting longitudinal seam– Significant Selective Seam Weld Corrosion (SSWC)– Significant Stress Corrosion Cracking (SSC)

• Additional 1-Year repair conditions (HCA)– Predicted failure pressure ratio at the location of the anomaly

• <=1.25 for Class 1 locations• <=1.39 for Class 2 locations • <=1.67 for Class 3 locations • <=2.00 for Class 4 locations

– An area of corrosion with a predicted metal loss greater than 50% of nominal wall.– Predicted metal loss >50% of nominal wall

• At P/L crossing• an area with widespread circumferential corrosion• in an area that could affect a girth weld.

– A gouge or groove greater than 12.5% of nominal wall. – Any indication of crack or crack-like defect other than an immediate condition.

Additional P&M Requirementsfor HCA Segments• Enhanced internal corrosion mgmt. program

– Monitor/mitigate deleterious gas stream components– Install filters & continuous gas quality equipment where contaminants are being injected– Quarterly gas monitoring & analysis– Cleaning pigs, testing for MIC– Use of corrosion inhibitors– Prescriptive corrosive gas stream constituent volume thresholds– Semi-annual program review & adjust program as necessary

Additional P&M Requirementsfor HCA Segments• Enhanced external corrosion management program

– HVAC Interference• Perform electrical current surveys <7 years where presence of HV electrical line in proximity• Conduct interference surveys at suspect locations• Identify locations w/interference currents >=20 amp/m2• Remedial action w/in 6 months to protect from deleterious current

– >=50 amp/m2 mandatory– >20 amp/m2 & <50 amp/m2 requires written engineering justification– Adequacy of external corrosion control via indirect assessment

• Perform CIS, DCVG, or ACVG at least every 7 years• Remediate damage and integrate results w/risk assessments• Prescribe distance between P/S test stations < ½ mile in HCA

– Cathodic protection assessment• Identify, remediate low potential readings w/in 6 months, report to PHMSA/State if cannot remediate w/in 6 months

Miscellaneous• MAOP exceedance reporting (SRC)

– Require operators to report each exceedance of the MAOP that exceeds the build-up allowed for operation of pressure-limiting or control devices• Welder qualification records retained for life of pipe• Class 1 pressure test factor increased from 1.1 to 1.25• Install pressure relief for all pig traps in use after 6 months of rule date• Evaluate pipeline w/in 72 hours of severe weather or other event that could affect the integrity of the pipeline & remediate if necessary• Seismicity

– Include seismicity in evaluating P&M measures for the threat of outside force damage.– Include seismicity of the area in the relevant pipeline attributes

• New Appendix F – Criteria for Conducting Integrity Assessments Using Guided Wave Ultrasonic Testing (GWUT)

Comments can be viewed at:www.regulations.govDocket: PMHSA-2011-0023Chris Foley

Vice President, RCP Inc.cfoley@rcp.com(713) 655-8080www.rcp.com