The Gas Mega Rule

The Gas “Mega Rule”Western Regional Gas Conference

Tempe AZ August 23, 2016

JOHN A. JACOBI, P.E., J.D.

Outline2

A. The Rulemaking Process

B. History of the Gas “Mega Rule”

C. The Gas Mega Rule • Things that are not to be changed (Valve

spacing, underground storage, risk models, NPMS reporting, etc.)

Outline3

C. The Gas Mega Rule (continued)

• Gathering Lines (newly regulated gathering and new reporting requirements)

• The “Grandfather” clause• Moderate Consequence Areas• Other Definitions (some proposed and some

that should have been proposed)

Outline4


• §192.624 – MAOP Verification• Subpart O Gas Transmission Pipeline Integrity

Management• §192.607 Verification of Pipeline Material• §192.619 MAOP• §192.710 Pipeline Assessments

Outline5


• Miscellaneous Provisions− §192.478 Internal Corrosion− §192.493 ILI Standards− §192.506 Spike Tests− §192.613(c) Weather Events

• Overview

The Rulemaking Process6

• Source of Authority• Advanced Notice of Proposed Rulemaking• Notice of Proposed Rulemaking• Economic Impact• Public Comments• Timing

History7

• 76 FR 53086 et. seq.; August 15, 2011; Docket No. PHMSA-2011-0023

• Response to CY2010 incidents, then upcoming reauthorization, and follow up to liquid ANPRM

• Comment period closed January 20, 2012• NOPR 81 FR 20722 et. seq., April 8, 2016• Public Comment Period closed July 8, 2016

Docket PHMSA-2011-00238

Go to

www.regulations.gov

enter the docket number

All of the public records will be there!!

Abstract9

In this rulemaking, PHMSA will be revisiting the requirements in the Pipeline Safety Regulations

addressing integrity management principles for Gas Transmission pipelines. In particular, PHMSA will

address: repair criteria for both HCA and non-HCA areas, assessment methods, validating &

integrating pipeline data, risk assessments, knowledge gained through the IM program, corrosion control, management of change,

gathering lines, and safety features on launchers and receivers.

Cost Benefit 10

Summary of Average Annual Present Value Benefits and Costs1 (Millions; 2015$)

Topic Area 7% Discount Rate 3% Discount Rate

Benefits Costs Benefits CostsRe-establish MAOP, verify material properties, and

integrity assessments outside HCAs $196.9 -$230.5 $17.8 $247.8 -$288.6 $22.0Integrity management process clarifications n.e. $2.2 n.e. $1.3Management of change process improvement $1.1 $0.7 $1.2 $0.8Corrosion control $5.5 $6.3 $5.9 $7.9Pipeline inspection following extreme events $0.3 $0.1 $0.3 $0.1MAOP exceedance reports and records verification n.e. $0.2 n.e. $0.2Launcher/receiver pressure relief $0.4 $0.0 $0.6 $0.0Gas gathering regulations $11.3 $12.6 $14.2 $15.1Total $215.6 -$249.2 $39.8 $270 -$310.8 $47.4

HCA = high consequence area

MAOP = maximum allowable operating pressure

n.e. = not estimated

1. Total over 15-year study period divided by 15. Additional costs to states estimated not to exceed $1.5 million per year. Range of benefits reflects range in estimated defect failure rates.

2. Break even value of benefits, based on the average consequences for incidents in high consequence areas, would equate to less than one incident averted over the 15-year study period.

Estimated Per-Mile Costs11

PHMSA has data on gas transmission pipeline operators affected by the proposed rule. However,

PHMSA does not have data on currently unregulated gas gathering pipeline operators. Therefore, this [Initial Regulatory Flexibility Analysis] document

provides the elements of an IFRA, including PHMSA’s analysis of the potential impact of the

proposed Safety of Gas Transmission and Gathering Pipelines rule on small entities.

Estimated Per-Mile Costs12

Table 3. Estimated Per-Mile Costs for Topic Area 1 by Subtopic

Sub-Topic

Approximate Equivalent

Mileage

Mileage1

Total Ongoing

Costs2

Cost Per

Mile3

Approximate Cost per Mile

per Year4

Re-establish MAOP: HCA > 30% SMYS

HCA Miles 19,872 $33,225,784 $1,672 $111

Re-establish MAOP: Inadequate Records

Mileage reported with incomplete MAOP records

4,363

$213,837,287

$49,012

$3,267Integrity Assessment: Non- HCA

Non-HCA 281,901 $142,673,072 $506 $34

Re-establish MAOP: HCA 20-30% SMYS; Non-HCAClass 3 and 4; Non-HCAClass 1 and 2 piggable

All GT Miles

301,774

$67,931,862

$225

$15GT = gas transmissionHCA = high consequence areaMAOP = maximum allowable operating pressure SMYS = specified minimum yield strength

1. Source: 2014 Gas Transmission Annual Reports2. See the Regulatory Impact Analysis in the docket for the rulemaking.3. Calculated as total cost divided by applicable mileage.4. Calculated as per mile cost divided by 15 years.

Things that will not change13

A. Class Locations will not go away – yet

B. Data – Reliable, Traceable, Verifiable & Complete mentioned 30 times!!

C. Risk Models – the thrust is risk-based but no new models are proposed

D. Valve Spacing – not changed

Things that will not change14

E. Underground storage – will be a separate rulemaking

F. NPMS Reporting – not changed in terms of what has to be reported

G. Management of Change – no significant changes

H. Quality Management Systems – will morph into a separate rulemaking for Pipeline Safety Management (PSM – API RP 1173)

Documentation15

• The phrase “reliable, traceable, verifiable, and complete” appears 30 times in the NOPR.

• Nowhere in the NOPR (or in the current Part 192) are any of these words defined.

• PHMSA should provide a reasonable definition of these words.

Documentation16

• The phrase “for the life of the pipeline” appears 19 times in the body of the NOPR.

• A new Appendix A to Part 192 is titled “Records Retention Schedule for Transmission Pipelines.”

• Over 80 code sections or subsections are listed in the proposed Appendix A.

• The overwhelming majority are “for the life of the pipeline.”

§192.13 General Requirements17

New §192.13(e):• Keep records for the retention period specified

in (new) Appendix A• Records must be reliable, traceable, verifiable,

and complete• No or inadequate records – must develop using

(new) §192.607

§192.67 Records: Materials18

NewOperators of transmission pipelines must acquire and retain for the life of the pipeline the original steel pipe manufacturing records that document tests, inspections, and attributes required by the manufacturing specification in effect at the time the pipe was manufactured, including, but not

limited to, yield strength, ultimate tensile strength, and chemical composition of materials

for pipe in accordance with §192.55.

§192.205 Records: Components19

New (transmission lines)Must acquire and retain records documenting the mfg. std. and pressure rating to which each valve

was mfg. and tested. Flanges, fittings, branch connections, extruded outlets, anchor forgings,

and other components with material yield strength grades of X42 or greater must have

records documenting the mfg. spec. in effect at the time of mfg, including, but not limited to, yield strength, ultimate tensile strength, and chemical

composition of materials.

Reporting (Part 191)20

• Reporting of incidents, safety-related conditions, exceedances of MAOP, annual pipeline summary data, and National Operator Registry information

• Would apply to offshore gathering lines and to onshore gathering lines, whether designated as “regulated onshore gathering lines” or not (as determined in § 192.8).

Reporting (Part 191)21

• Distribution & gathering lines expressly required to report safety related conditions related to exceeding MAOP (§191.23)

• §191.25(b) Each report of a MAOP exceedance meeting the requirements of criteria in § 191.23(a)(9) for a gas transmission pipeline must be reported within five calendar days of the exceedance using the reporting methods and report requirements described in §191.25(c).

Documentation22

PHMSA is serious about requiring

good solid records

regarding compliance!

§192.8 Gas Gathering23

• Type A gathering lines 8 inches or greater in diameter in Class 1 locations may be regulated.

• Requirements would include damage prevention, corrosion control (for metallic pipe), public education program, maximum allowable operating pressure limits, line markers, and emergency planning (same as for Type B gathering in Class 3 and 4 locations).

HINT: It is likely that the diameter will be increased.

§192.9 Gas Gathering24

New §192.9(f):

If a change in class location or increase in dwelling density causes an onshore gathering

line to be a regulated onshore gathering line, the operator has one year for Type A, Area 2 and Type B lines and two years for Type A, Area 1 lines after

the line becomes a regulated onshore gathering line to comply with this section.

New §192.3 Gathering Definition25

• Gathering Lines (Onshore) will be pipelines, and equipment used to collect gas from the endpoint of a production facility/operation and transport it to the furthermost point downstream of a number of endpoints. Incidental gathering would still be recognized but limited.

Other Gathering Definitions26

• API RP 80 “Guidelines for the Definition of Onshore Gas Gathering Lines” would no longer be incorporated by reference.

• New §192.3 gathering related definitions (consistent with RP 80 definitions):

• Gas Processing Plant• Gas treatment facility• Onshore Production facility/operation

The “Grandfather Clause”27

• Any segment for which MAOP was established in accordance with §192.619(c) prior to the effective date of the new rule will have to have its pressure verified under §192.624.

ApplicabilityOnshore transmission lines in §192.903 HCAs, or in Class 3 or Class 4 Locations or in a Moderate Consequence Areas (if the line is piggable in the

MCA)

Moderate Consequence Area28

Moderate Consequence Area (MCA, §192.3)• 5 or more buildings intended for human

occupancy within PIR; or• An occupied site within PIR; or • a right-of-way for a designated interstate,

freeway, expressway, and other principal 4-lane arterial roadway within PIR; and

• does not meet the definition of a §192.903 high consequence area.

Occupied Site29

• An outside area or open structure that is occupied by 5 or more persons on at least 50 days in any 12-month period

• A building that is occupied by 5 or more persons on at least 5 days a week for 10 weeks in any 12-month period

Other Definitions (§192.3)30

• Transmission line definition essentially unchanged

• Distribution line (Onshore) definition unchanged

• MISSING: Definition of “in-plant piping” and meaningful definitions of distribution line and distribution system.

Other Definitions (§192.3)31

• Distribution Center• Dry gas or dry natural gas• In-line inspection (ILI)• In-line inspection tool or instrumented internal

inspection device• Legacy construction techniques• Legacy pipe • Modern pipe• Significant Seam Cracking• Significant Stress Corrosion Cracking• Wrinkle bend

§ 192.5 Class locations32

Definitions unchanged but:

Records for transmission pipelines documenting class locations and demonstrating how an

operator determined class locations in accordance with this section must be retained for

the life of the pipeline.

§ 192.7 - New Standards33

• API STD 1163-2005, “In-Line Inspection Systems Qualification Standard” (§192.493)

• NACE Standard Practice 0102-2010, "Inline Inspection of Pipelines“ (§§192.150(a) and 192.493)

• NACE Standard Practice 0204-2008, "Stress Corrosion Cracking Direct Assessment” (§§ 192.923(b)(3) and 192.929)


• NACE Standard Practice 0206-2006, "Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas" (§§ 192.923(b)(2); 192.927(b); and192.927(c))

• ANSI/ANST ILI-PQ-2010, "In-line Inspection Personnel Qualification and Certification” (§192.493)


• Battelle's Experience with ERW and Flash Welding Seam Failures: Causes and Implications (Task 1.4)” (§192.624(c) and (d))

• Battelle Memorial Institute, "Models for Predicting Failure Stress Levels for Defects Affecting ERW and Flash-Welded Seams" (Subtask 2.4)” (§192.624(c) and (d))


• Battelle Final Report No. 13-021, "Predicting Times to Failures for ERW Seam Defects that Grow by Pressure Cycle Induced Fatigue (Subtask 2.5)” (§192.624(c) and (d))

• Battelle Memorial Institute, "Final Summary Report and recommendations for the Comprehensive Study to Understand Longitudinal ERW Seam Failures -- Phase 1 (Task 4.5)” (§192.624(c) and (d))

§192.13 General Requirements37

New §192.13(d):• Operators must evaluate and mitigate, as

necessary, risks to the public and environment as an integral part of managing pipeline design, construction, operation, maintenance, and integrity, including management of change (MOC).

• MOC = ASME/ANSI B31.8S, section 11• 8 required elements for MOC

§192.624 Establishing MAOP38

This section is potentially the most costly.It is certainly the longest and most complex!!

General Applicability

Onshore transmission lines in §192.903 HCAs, or in Class 3 or Class 4 Locations or in a Moderate Consequence Areas (if the line is piggable in the

MCA)

§192.624 Applicability39

Other Criteria• Any segment that has experienced a reportable

in-service incident, as defined in §191.3, since its most recent successful Subpart J pressure test, due to an original manufacturing-related defect, a construction-, installation-, or fabrication-related defect, or a cracking-related defect, including, but not limited to, seam cracking, girth weld cracking, selective seam weld corrosion, hard spot, or stress corrosion cracking.


Other Criteria• Any segment for which pressure test records

necessary to establish maximum allowable operating pressure per Subpart J for the pipeline segment, including, but not limited to, records required by § 192.517(a), are not reliable, traceable, verifiable, and complete.

Note: This particular requirement does NOT apply in Moderate Consequence Areas.


Other Criteria• Any segment for which MAOP was established

in accordance with §192.619(c) prior to the effective date of the new rule.

Note:§192.619(c) is the “Grandfather Clause.” This requirement

eliminates the “Grandfather Clause.” Any operator with grandfathered pipe will have work to do!!

§192.624 Deadlines42

• Plans must be developed and documented within 1 year of the effective date.

• Plan must be implemented for at least 50% of the mileage within 8 years of effective date.

• Plan must be implemented for 100% of the mileage within 15 years of effective date.

• May petition for one year extension of deadlines (lots of strings attached)

§192.624 Acceptable Methods43

• Method 1 – Pressure Test• Method 2 – Pressure Reduction (HAOP)• Method 3 – Engineering Critical Assessment• Method 4 – Pipe Replacement• Method 5 – Pressure Reduction (Small Dia & PIR)

• Method 6 – Alternative Technology

Subpart O – Integrity Mgm’t44

• Incredibly complex • Allegedly would apply only to transmission

lines in HCAs (PIR containing ≥ 20 buildings intended for human occupancy or an identified site)

• Data gathering and integration would apply to both covered segments and non-covered segments and extremely prescriptive.

Subject Matter Experts (SMEs)45

• If input is obtained from subject matter experts, the operator must employ measures to adequately correct any bias in SME input. Bias control measures may include training of SMEs and use of outside technical experts (independent expert reviews) to assess quality of processes and the judgment of SMEs. Operator must document the names of all SMEs and information submitted by the SMEs for the life of the pipeline.

Apparently whoever wrote this is a cynic.

Spatial Relationships46

• Must identify and analyze spatial relationships among anomalous information (e.g., corrosion coincident with foreign line crossings; evidence of pipeline damage where overhead imaging shows evidence of encroachment). Storing or recording the information in a common location, including a geographic information system (GIS), alone, is not sufficient.

Plastic Transmission Pipeline47

Must assess the threats using the information in sections 4 and 5 of ASME B31.8S, and consider

any threats unique to the integrity of plastic pipe such as poor joint fusion practices, pipe with poor slow crack growth (SCG) resistance, brittle pipe,

circumferential cracking, hydrocarbon softening of the pipe, internal and external loads, longitudinal

or lateral loads, proximity to elevated heat sources, and point loading.

Cyclic Fatigue48

• Fracture mechanics modeling for failure stress pressures and cyclic fatigue crack growth analysis must be conducted in accordance with (new) §192.624(d) for cracks.

• Cyclic fatigue analysis must be annual, not to exceed 15 months.

Miscellaneous Provisions49

• §192.478 Internal Corrosion• §192.493 ILI Standards• §192.506 Spike Tests• §192.613(c) Weather Events

§192.478 Internal Corrosion50

Entire section added to require gas analysis for potentially corrosive constituents (such as carbon dioxide, hydrogen sulfide, sulfur, microbes, and free water, either by itself or in combination).

Coupons and monitoring would be required if potentially corrosive constituents present.

§192.493 ILI51

Part 192 ILI must comply with API STD 1163, In-line Inspection Systems Qualification Standard;

ANSI/ASNT ILI-PQ-2005, In-line Inspection Personnel Qualification and Certification; and

NACE SP0102-2010, In-line Inspection of Pipelines. Assessments may also be conducted using tethered or remotely controlled tools, not

explicitly discussed in NACE SP0102-2010, provided they comply with those sections of

NACE SP0102-2010 that are applicable.

§192.506 Spike Tests52

• 30% SMYS or greater with integrity threats “that cannot be addressed by other means such as in-line inspection or direct assessment.”

• Must use water as test medium.• Baseline test pressure (8 hours) must be

§192.619, §192.620 or (new) §192.624 as applicable (w/o spike).

• Spike = lesser of 1.50 times MAOP or 105% SMYS for at least 30 minutes.

§192.506 Spike Tests53

• Spike test must be successfully completed w/in first 2 hours as part of 8 hour baseline test (i.e., spike counts as part of 8 hour test).

• If time dependent threat is present (e.g., cracking), a retest interval under new §192.624 must be established.

• Alternative Technology is possible with LOTS of technical support. (Good luck!)

§192.613(c)54

After extreme weather events such as a hurricanes floods, earthquakes, landslides, natural disasters potentially affected onshore systems must be inspected.• Must be based upon specific system & nature of

potential damage• Must commence within 72 hours of when need is

identified OR when system can be safely accessed and equipment & personnel are available (whichever is sooner)(are they kidding??)

§192.613(c)55

• Remedial action to be determined by operator:(i) Reducing the operating pressure or shutting down the pipeline;

(ii) Modifying, repairing, or replacing any damaged pipeline facilities;

(iii) Preventing, mitigating, or eliminating any unsafe conditions in the pipeline right of way;

(iv) Performing additional patrols, surveys, tests, or inspections;

(v) Implementing emergency response activities with Federal, State, or local personnel; or

(vi) Notifying affected communities of the steps that can be taken to ensure public safety.

Overview56

• Documentation, Documentation, Documentation!! (materials, anomalies, compliance, etc., etc., etc.)

• Significantly more prescriptive than existing provisions

• Fracture Mechanics & Metallurgy• More pipe covered (gathering & MCA)• Schedule

Questions57

John [email protected](713) 260-4039 (Office)(832) 712-3098 (Mobile)

Thank YOU!!

Documents

The Gas Mega Rule