2019 RRC Regulatory Conference

Oil and Gas and Pipeline SafetyAugust 21 , 2019, Austin, Texas

Benny Mumme - Flint Hills Resources

Biography

▪ Benny Mumme

▪ Flint Hills Resources

▪ Senior Integrity Engineer

▪ 37 years in Pipeline Integrity Management. Pipeline Integrity SME responsible for Station Integrity and Water Crossing Management. A graduate from Texas A&M University with a BS in Engineering Technology. NACE Corrosion Specialist. Held several roles in Pipeline Integrity Management and Corrosion Control. Currently active in API Pipeline Integrity Work Group and Chairman of API 1160 sub work group. Presently PRCI Corrosion Technical Committee Vice Chair and active technical committee

member with NACE and ASME B31.4.

Company Logo

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API RP 1160 - Managing System Integrity for

Hazardous Liquid Pipelines

Agenda

1. What is 1160? It is the umbrella document of Liquid Pipeline Integrity Documents. “A Road Mapping Document”. This RP is specifically designed to provide the operator with a description of industry-proven practices in pipeline integrity management.

2. Revision team - 50 SME Participants: Twenty Two Companies

3. Revision Objectives - this revision published February 2019.

4. Document format adjusted to tie to API 1173 continuous PDCA Loop

5. New and Revised Repair Response Criteria - New Changes and additions

6. Implementation

1. It is the umbrella document of liquid pipeline integrity documents.

2. Is a technical document and a guide to more than seventy plus good pipeline integrity

resource documents like:

▪ Pipeline Repairs – ASME B31.4, the PRCI Repair Manual R2260-01R (Catalog L52047) ,

API RP 1176, and CSA Z662.

▪ Reassessment intervals - API RP 1176, API RP 2611, API 580, API 581, and API 570.

▪ API various documents 1110, 1133, 1161, 1162,1163, 1168, 1173, 1174, 1175, 1176, 1178,

▪ ASME B31.4, Liquid and Slurry Piping Transportation Systems

▪ ASME B31.8S, Managing System Integrity of Gas Pipelines

▪ ASTM E1049-85, Standard Practices for Cycle Counting in Fatigue Analysis

▪ NACE SP0169, Control of External Corrosion on Underground or Submerged Metallic

Piping Systems

▪ NACE SP0502, Pipeline External Corrosion Direct Assessment Methodology

▪ PRCI PR-218-063505, Safe Inspection Procedures for Dent and Gouge Damage (2010).

▪ Annex I various PHMSA Advisory Bulletins

AND MANY MORE!

API RP 1160 - Managing System Integrity for Hazardous Liquid

Pipelines - What is an integrity road mapping document?

Revision of API RP 1160 - Managing System

Integrity for Hazardous Liquid Pipelines

“Twenty Two Companies contributed 50 SME Participants”

Flint Hills Resources Trans Canada Exxon Mobil

Enterprise Williams Phillips 66

Energy Transfer Sinclair Oil Marathon Petroleum

Shell Plains Buckeye

Colonial Enbridge Oxy

Tall Grass Energy API AOPL

PHMSA DVNGL Kiefner Associates

TDW Explorer

1. Update - Last five years of Pipeline Integrity Technical Advancements or

changes.

2. Incorporate API STD 1173 Safety Management Systems (Plan Do Check

Act) version 1 July 2015. Restructure the document to flow PDCA.

3. Remove - most of the Crack Management guidance that was moved into

the new API RP 1176 – Assessment and Management of Cracking in

Pipelines- version 1 June 2016. Add crack response criteria from 1176.

4. Add road mapping guidance on Integrity Data Management and

Integration new API Bulletin 1178 – version 1 in 2017.

5. Remove most of the Hydrotest guidance that was moved to the new API

TR 1179 document – Scheduled to be published in version 1 April/May

2019.

6. Remove most of the Waterway Crossing guidance that moved to updated

API RP 1133 – version 2 December 2017

7. Give consideration to the PHMSA hazardous liquid rulemaking Section 9

and through out the document. Revised repair response criteria.

Main Revision Objectives

Other Revision Objectives

▪ Added new list of PHMSA advisories See Annex I list of 21 Advisory Bulletins

▪ Consider strain-related problems (begin discussion in document in the construction section; team to decide spectrum of strain-related topics to be included). – See Annex A section A.6 Construction Related Defects

▪ Include interactive threats (e.g., depth of crack and corrosion). Added to section 5.2 Threat Interaction also Annex B.8 Considerations for Interacting Threats.

▪ Consider expanding discussion of vortex induced vibration threat in waterway outside force section. Added to section 5.2.5 Time dependent interaction including VIV.

▪ Update the repair table or provide a comparison of various recommended repairs - Removed repair table from section 9.5 now go see ASME B31.4 or other repair guidance like PRCI repair manual. Also see Annex C Repair Strategies.

Other Revision Objectives▪ Consider adding a discussion regarding synergies of using different

technologies. Consider tool limitations. Added to section 9.2 In-Line inspection. Discusses different technologies for different threats. Also see Annex B.7 Using Multiple Tool Technologies

▪ Consider including discussion on aggressive growth rates (e.g., parameters or pipe conditions that could lead to aggressive growth rates). Added Section 9 threat categories 9.1 also in Table 2 on Assessment Types ILI . Table 3 SSWC. Also section 9.9.2.2.2 discovery of condition. Near term response condition Sec 10.2.2 reassessment intervals. Appendix A - SSWC.

▪ Consider including discussion of HVAC and HVDC interference. Appendix A.1.2 Stray Current Corrosion

▪ Consider updating/expanding Integrity Management of Pipeline Pump Stations and Terminals section. What is the best approach? Added significant material to this section. Also pointes to API 570, API 580, API 2611. PPTS -2009.

Incorporate API 1173 - PDCA Loop

Safety Management System Process

Plan (Sec. 5) Identify threats to Pipeline

Integrity(Sec. 6) Identify Potential impact to Critical Locations (HCA analysis)(Sec. 8) Assess Risk and Rank Segment (Sec. 8) Develop or Revise Assessment Plan

Do(Sec. 9) Conduct Pipeline Inspections, Testing and Examinations (Sec. 7) Collect Pipeline Integrity Data(Sec. 13) Collect Program Performance Data (Sec. 14) Review Management of Change (MOC) - Measures

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Incorporates API 1173 - PDCA Loop

Safety Management System Process

Check(Sec 7) Integrate pipeline, Tools and Program, Performance Data together with MOC Measures(Sec 13) Review Operator, Industry and Regulator Learnings and like PHMSA recommended advisories(Sec 13) Evaluate Integrity Program

Performance – “effectiveness”

Act(Sec 9 and Annex C) Perform Pipeline Remediation Activities like “pig and dig”(Sec 11) Perform Preventative and Mitigative Activities like adjust or add corrosion control(Sec 10 Annex D) Calculate Pipeline Reassessment Intervals(Sec 13,14) Undertake Integrity Program Improvement actions

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New Changes to Response Levels▪ Immediate

– Discovery: < 30 days from “completion of the inspection”

– Mitigation: < 5 days from discovery

▪ Near Term

– Discovery: typically 180 days – not expressly prescribed

– Mitigation: < 270 days (9 months) from discovery, for HCAs (including could affect)

< 540 days (18 months) from discovery, For non HCA’s

▪ Scheduled (growth)

– Discovery: not prescribed, driven by growth analysis and constraints in resolving tool tolerance

– Mitigation: prior to the year the condition is met

▪ Monitored

– Discovery: not defined

– Mitigation: none prescribed

Immediate

a) Metal loss depth > 80 % WT

b) Likely crack anomaly depth > 70 % WT (or saturated).

c) Metal loss or likely crack anomaly FPR < 1.1

d) Dent with gouge, likely or possible crack, or stress riser, unless …an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity

e) Dent located on TOP depth > 6 % of NPS, unless …

– an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity

f) An anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action.

Near Term

a) Dent > 2 %* NPS that affects pipe curvature at a girth weld or a longitudinal seam weld, unless …

b) Dent located on TOP depth > 2 %* of NPS, unless …

c) Dent > 6 % NPS, unless …

– an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity.

d) Metal loss, likely crack (that is time dependent or possibly time dependent) or possible crack (that is time dependent) anomaly FPR < 1.25 at the location

e) An area of general corrosion with a predicted metal loss > 50 % WT of nominal wall

f) SSWC with a predicted metal loss greater than 50% of nominal wall

* > 1/4” where NPS < 12

Near Term (continued)

g) Metal loss depth > 50 % WT at:

– crossing of another pipeline or

– is in an area with widespread circumferential corrosion, or

– is in an area that could affect a girth weld

h) Likely crack (that is time dependent or possibly time dependent) or a possible crack (that is time dependent) with depth > 50 % WT. nominal wall

I) Dent with corrosion

– unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity

j) Gouge or groove depth from mechanical damage from > 12.5 % WT from mechanical damage

Scheduled (growth)

a) A calculation of the remaining strength of the pipe (including allowances for growth and tool measurement error) shows less than FPR < 1.1 at the location of the anomaly.

b) A calculation of the maximum depth of a metal loss feature (including allowances for growth and tool measurement error)> predicted to be >80 % of nominal wall regardless od dimensions.

If an anomaly fails a scheduled response criteria including tool tolerance but within the application of growth, the anomaly should be addressed as a Near term response. Additional guidance on scheduled response conditions for cracks can be found in API RP 1176.

Monitored

An operator does not have to schedule the following conditions for remediation but should record and monitor the conditions during subsequent integrity assessments for any change that may require attention.

a) Any manufacturing or construction condition that an industry recognized engineering evaluation or technical analysis shows to be stable and for which operating conditions have not significantly changed since the last successful pressure test; or

b) Any condition identified by an integrity assessment or information analysis that is not currently deemed to impair the integrity of the pipeline.

Additional guidance on monitor conditions for cracks can be found in API RP 1176.

The Main Take Away!

New and revised documents that

need to be Implemented.

1. Operating Companies need to take

the suite of new and revised Integrity

documents like API 1160, 1163, 1133,

1176, 1178, 1179 etc.. and perform a

gap analysis and revise and implement

changes to your Integrity Management

Programs!