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Addendum StartPage: 0
SOAH DOCKET NO. 473-18-2800 ..s, PUC DOCKET NO. 48095 23!C 1
APPLICATION OF ONCOR ELECTRIC -BEFORE THE,, DELIVERY COMPANY LLC TO AMEND A CERTIFICATE OF CONVENIENCE AND NECESSITY FOR STATE OFFICE OF A 345-KV TRANSMISSION LINE IN CRANE, ECTOR, LOVING, REEVES, WARD, AND WINKLER COUNTIES ADMINISTRATIVE HEARINGS (ODESSA EHV — RIVERTON AND MOSS — RIVERTON CCN)
DIRECT TESTIMONY OF ANDREW G. HEVLE ON BEHALF OF KINDER MORGAN
TABLE OF CONTENTS
I. POSITION AND QUALIFICATIONS 2
II. PURPOSE OF TESTIMONY .4
III. POTENTIAL IMPACT OF CROSSING OR PARALLELING ELECTRIC TRANSMISSION LINES AND NATURAL GAS, OIL, OR CO2 STEEL PIPELINES .8
IV. THE RISKS ASSOCIATED WITH ROUTING ELECTRICAL TRANSMISSION LINES NEAR STEEL PIPELINES ARE WELL-ESTABLISHED .14
V. MITIGATING RISKS TO PIPELINE INTEGRITY IS REQUIRED BY STATE AND FEDERAL LAW 18
VI. REQUESTED RELIEF 19
VII. CONCLUSION .25
LIST OF EXHIBITS
EXHIBIT A L- O&M 903 EXHIBIT B INGAA "Criteria for Pipelines Co-Existing with Electric Power Lines" EXHIBIT C NACE SP0177-2014 EXHIBIT D NACE International Publication 35110 EXHIBIT E NACE International Standard SP0169-2013 EXHIBIT F Roger Floyd, "Testing and Mitigation of AC Corrosion on 8" Line: A Field Study" at 6-7 (NACE Corrosion 2004, Paper No. 04210, 2004)
Page 1
000001 EXHIBIT G M. Yunovich, N.G. Thompson, "AC Corrosion: Corrosion Rate and Mitigation Requirements" at 5 (NACE Corrosion 2004, Paper No. 04206, 2004) EXHIBIT H R.A. Gummow, G.R. Wakelin and S.M. Segall, "AC Corrosion — A New Challenge to Pipeline Integrity" at 4-6 (NACE Corrosion 98, Paper NO. 566, 1998) EXHIBIT I Shane Finneran & Barry Krebs, "Advances in HVAC Transmission Industry and Its Effects on Pipeline Induced AC Corrosion" at 4-6 (NACE Corrosion 2014, Paper No. 4421, 2014) EXHIBIT J CorrPD-011 Requirements for Overhead Power Lines in the Vicinity of Kinder Morgan Pipelines, attached hereto as Exhibit J
TO THE EXTENT ANY EXHIBITS INCLUDED IN THIS TESTIMONY ARE SUBJECT TO COPYRIGHT THOSE EXHIBITS SHOULD ONLY BE USED IN REVIEW OF THIS TESTIMONY AND MAY NOT BE USED FOR COMMERCIAL PURPOSES
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1 DIRECT TESTIMONY OF ANDREW G. HEVLE
2 I. POSITION AND QUALIFICATIONS
3 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS
4 A. Andrew G. Hevle. My business address is 1001 Louisiana St # 1000, Houston,
5 TX 77002.
6 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
7 A. I am testifying on behalf of Kinder Morgan Wink Pipeline LLC, Kinder Morgan
8 CO2 Company, L.P., Natural Gas Pipeline Company of America, LLC, and El Paso
9 Natural Gas Company, LLC (collectively "Kinder Morgan" or the "Company").
10 Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC UTILITY
1 1 COMMISSION OF TEXAS ("COMMISSION")?
12 A. No.
13 Q. PLEASE OUTLINE YOUR EDUCATIONAL AND PROFESSIONAL
1 4 QUALIFICATIONS.
15 A. I received a Bachelor of Science in Mechanical Engineering from Louisiana Tech
16 University, and am certified by NACE International as a Corrosion Specialist, Certified
17 Coating Inspector, Cathodic Protection Specialist (CP4), Pipeline Integrity Management
18 Specialist and Senior Internal Corrosion Technologist.
19 Q. ARE YOU A MEMBER OF ANY PROFESSIONAL ORGANIZATIONS?
20 A. I am a member of NACE International, American Society of Mechanical
21 Engineers (ASME), the Society for Protective Coatings (SPCC), American Petroleum
22 Institute (API), Southern Gas Association (SGA) and Kinder Morgan's voting
23 representative on the Corrosion Committee of Pipeline Research Council International
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1 (PRCI). I have successfully completed the Fundamentals of Engineering (FE)
2 Examination by the National Council of Examiners for Engineering and Surveying
3 (NCEES) and am certified as an EIT.
4 Q. PLEASE DESCRIBE YOUR QUALIFICATIONS RELATED TO
5 ASSESSING THE IMPACT OF ALTERNATING-CURRENT ("AC")
6 INTERFERENCE ON NATURAL GAS, OIL, AND CO2 STEEL PIPELINES.
7 A. I am Manager of Corrosion Control for Kinder Morgan's Natural gas pipeline
8 group, responsible for the business unit's corrosion control program. I presently serve as
9 most recent past Chairman of the NACE Technical Coordination Committee (TCC),
10 which oversees all NACE International technical activities. I am a member of the task
11 group (TG 025) that developed the NACE International standard SP0177 "Alternating
12 Current (AC) Power Systems, Adjacent: Corrosion Control and Related Safety
13 Procedures," and a member of the committee that developed INGAA Foundation's report
14 "Criteria for Pipelines Co-Existing with Electric Power Lines" and a member of the
15 voting body for the task group (TG 430) draft standard "AC Corrosion on Cathodically
16 Protected Pipelines: Risk Assessment, Mitigation, and Monitorine. I have published
17 articles and made numerous presentations on the topic of corrosion control.
18 Q. WERE YOUR TESTIMONY AND EXHIBITS PREPARED BY YOU OR
19 BY SOMEONE UNDER YOUR DIRECT SUPERVISION?
20 A. Yes.
21
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1 II. PURPOSE OF TESTIMONY
2 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
3 A. Kinder Morgan owns an extensive network of natural gas, oil, and CO2 steel
4 pipelines in the study area that could be impacted by one or more of the routes proposed
5 by Oncor Electric Delivery Company LLC ("Oncor") in this proceeding. My testimony
6 explains that routing Oncor's proposed 345-kV electric transmission line in a manner that
7 crosses or parallels within 1,000 feet of Kinder Morgan's existing pipeline facilities could
8 cause AC interference on those facilities, which increases the risk of shock potential and
9 accelerated corrosion that can threaten pipeline integrity and create a public safety
10 hazard. I also explain The Company's obligations under state and federal law to protect
11 public safety and pipeline integrity, and I describe the measures that may need to be taken
12 to meet that obligation by mitigating any risks to the Company's steel pipelines caused by
13 Oncoes proposed facilities. I also address the potential mitigation costs associated with
14 each proposed route. Finally, I recommend that the Commission include in a Final Order
15 similar language to that which Commission has approved in prior CCN proceedings.
16 Specifically I recommend that the Commission include the following ordering
17 paragraph:1
18 Oncor must conduct surveys to identify pipelines that could be affected by
19 the proposed transmission line, and coordinate with pipeline owners in
20 modeling, and analyzing potential hazards prior to energizing the power
21 lines because of AC interference affecting pipelines being paralleled or
22 crossed.
1 Docket No. 43878, Final Order at Ordering Paragraph No. 13 ( Mar. 30, 2016); Docket No. 42583, Final Order at FoF 110 & Ordering Paragraph No. 10 (May 27, 2015); Docket No. 42087, Final Order at Ordering Paragraph No. 10 (Dec. 19, 2014).
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1 Kinder Morgan requests the addition of "prior to energizing the power line" as a small
2 deviation from language the Commission has previously approved in order to ensure that,
3 once energized, the electric transmission facilities do not pose the risks discussed in more
4 depth below. 1 also recommend that the Commission include the following ordering
5 paragraph:
6 Once any such hazards caused by AC interference are identified, Oncor
7 shall work with the impacted pipeline(s) to ensure that at any points at
8 which the transmission facilities parallel or cross the pipeline(s) the
9 transmission facilities will be sited and constructed so as to minimize the
10 amount of AC interference mitigation measures required to be
11 implemented by the pipeline(s) to ensure the safest conditions and to
12 minimize the cost of mitigation rneasures.
13 Because it has yet to be determined how the line will ultimately be constructed, it is not
14 certain what effects the line with have on Kinder Morgan's pipelines or the costs of
15 mitigating those effects. This language would provide Oncor and Kinder Morgan
16 flexibility in how to address the safety concerns created by AC Interference going
17 forward. This language would also provide Kinder Morgan, Oncor, affected landowners,
18 and Oncor's customers more clarity regarding how safety concerns created by AC
19 Interference will be addressed in the future.
20 Q. IS KINDER MORGAN REQUESTING THAT THE COMMISSION
21 ORDER ONCOR TO CONDUCT MITIGATION ACTIVITIES OR TO
22 REIMBURSE THE COMPANY FOR ITS MITIGATION COSTS RELATED TO
23 THE ELECTRIC TRANSMISSION LINE APPROVED IN THIS PROCEEDING?
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1 A. No. Kinder Morgan only requests that the Commission recognize, as it has in
2 previous cases, that there are AC interference risks associated with routing electric
3 transmission lines near existing steel pipelines resulting from Oncor's proposal to locate
4 the facilities near pipelines, and that these risks will have to be mitigated through some
5 coordination between Kinder Morgan and Oncor.2 Kinder Morgan has intervened in this
6 proceeding in order to present evidence on the potential mitigation needs that would
7 result from Oncor's proposed routes and so that it can present evidence with respect to
8 the safest manner by which Oncor's proposed routes should cross or parallel Kinder
9 Morgan's pipelines, and, finally, so that the Commission may consider these issues when
10 it determines which of the proposed routes best meets the Commission's routing criteria.
11 Q. PLEASE DESCRIBE KINDER MORGAN'S PIPELINE OPERATIONS
12 WITHIN THE STUDY AREA.
13 Kinder Morgan is one of the largest energy infrastructure companies in North America.
14 The pipelines that have intervened in this proceeding include Kinder Morgan Wink
15 Pipeline LLC, Kinder Morgan CO2 Company, L.P., El Paso Natural Gas Company, LLC
16 and Natural Gas Pipeline Company of America, LLC. The Kinder Morgan Wink Pipeline
17 system is a 450-mile Texas intrastate pipeline that transports crude oil from Scurry
18 County, Texas to a refinery in El Paso, Texas. The Kinder Morgan CO2 system is an
19 interstate pipeline system that transports carbon dioxide to eastern New Mexico, western
20 Texas and southwestern Utah. The El Paso Natural Gas Pipeline system is an interstate
21 pipeline system that transports natural gas from the San Juan, Permian, and Anadarko
2 Docket No. 42583„-lpplication of Oncor Electric Delivery company LLC to Amend its Certificate of convenience and Necessity for a Proposed 138KV Transmission Line in Culberson, Loving, Reeves, Ward and Winkler Counties, Open Meeting Tr. at 32-33 (May 21, 2015) (addressing the need for mitigation and the applicability of the Texas Health and Safety Code to electric transmission line projects).
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1 Basins to California, Arizona, Nevada, New Mexico, Oklahoma, Texas and northern
2 Mexico. The Natural Gas Pipeline Company of America system is one of the largest
3 interstate pipeline systems in the country, with 9,100 miles of pipeline, transporting
4 natural gas from Texas and the Southwest into the Chicago area.
5 Q. DOES KINDER MORGAN SUPPORT OR OPPOSE ANY PARTICULAR
6 ROUTE IN THIS PROCEEDING?
7 A. No.
8 Q. PLEASE DESCRIBE THE SEGMENTS OF ONCOR'S PROPOSED
9 ROUTES THAT CROSS OR PARALLEL WITHIN 1,000 FEET OF KINDER
10 MORGAN'S PIPELINE FACILITIES.
11 A. Numerous proposed segments will cross or parallel within 1,000 feet of the
12 Company's existing natural gas, oil, or CO2 steel pipelines and will potentially require
13 some level of pipeline mitigation to be performed to mitigate the risks of AC
14 interference. Because it appears that there is consensus on Route 1180, my testimony
15 will specifically address those segments of Route 1180 that potentially affect Kinder
16 Morgan's pipelines. Kinder Morgan has identified seven (8) segments of Route 1180
17 that cross its pipelines—segments A2, B2, G5, G6, J I, L2, N2 and U. There are also four
18 (5) segments that potentially parallel the pipelines as well—segments G6, R2, T21, and
19 T22 and U.
20 Q. WHY DOES THE COMPANY ONLY IDENTIFY RISKS ASSOCIATED
21 WITH ROUTES THAT PARALLEL WITHIN 1,000 FEET OF ITS FACILITIES?
22 A. While power lines that parallel pipelines greater than 1,000 feet may have effects
23 on the pipeline, it is unlikely that the effects will be significantly detrimental to require
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1 mitigation. 1,000 feet distance is a low-risk limit rule-of-thumb used in the pipeline
2 industry for stray current for high voltage alternating current (HVAC") loads less than
3 1,000 Amps, and is incorporated in Kinder Morgan's monitoring procedures in O&M
4 9033 and referenced in the INGAA Foundation's report "Criteria for Pipelines Co-
5 Existing with Electric Power Lines".4
6 Q. DOES ONCOR IDENTIFY IN ITS APPLICATION THE LENGTHS OF
7 SEGMENTS OR ROUTES THAT PARALLEL WITHIN 1,000 FEET OF KINDER
8 MORGAN'S FACILITIES?
9 A. No. Oncor is not required under Commission rules to calculate the length of its
10 proposed segments or routes that are within the 1,000-feet threshold utilized by the
11 pipeline safety industry to assess AC interference risks. Oncor's application recognizes
12 that between the cities of Kermit, Wink, and Monahans, routing had to consider
13 expansive oil and gas fields and the associated network of pipelines,5 but this assessment
14 is unrelated to the safety concerns I address in my testimony. My testimony does not
15 challenge the criteria Oncor or the Commission use in analyzing potential routes for
16 electric transmission lines. My testimony provides additional information to assist the
17 Commission in evaluating these safety concerns while determining the specific location
18 for the final route and what conditions the Commission will implement for that route.
19 III. POTENTIAL IMPACT OF CROSSING OR PARALLELING ELECTRIC 20 TRANSMISSION LINES AND NATURAL GAS, OIL, OR CO2 STEEL 21 PIPELINES. 22 23 Q. WHAT SPECIFIC ISSUES OR CONCERNS HAVE YOU IDENTIFIED
24 WITH REGARD TO ROUTING ONCOR'S PROPOSED 345-KV ELECTRIC
3 Attached hereto as Exhibit A. 4 Attached hereto as Exhibit B . 5 Environmental Assessment attached to Oncor's Application at p. 4-2.
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1 TRANSMISSION LINE ACROSS OR PARALLEL TO KINDER MORGAN'S
2 EXISTING NATURAL GAS, OIL, OR CO2 STEEL PIPELINES?
3 A. I have three primary concerns. AC interference caused by routing HVAC electric
4 transmission lines across or parallel to Kinder Morgan's natural gas, oil, or CO? steel
5 pipelines can create an increased risk of shock potential for anyone who comes into
6 contact with or within close proximity of an affected pipeline facility. Secondly, AC
7 interference can cause accelerated corrosion on and affected pipeline, which can result in
8 premature failure of the pipeline, leakage, and injury to the public or other property.
9 Finally, the proximity of tower footings, grounding, counterpoise and other structures
10 increases the risk of ground fault currents and lightning damaging the pipeline and the
11 pipeline coating.
12 Q. PLEASE EXPLAIN YOUR CONCERNS ABOUT THE RISK OF SHOCK
13 POTENTIAL ASSOCIATED WITH ROUTING ELECTRIC TRANSMISSION
1 4 LINES ACROSS OR PARALLEL TO STEEL PIPELINES.
15 A. Installing high-voltage electric transmission lines across or parallel to existing
16 steel pipelines can cause AC voltage and current from the transmission line to be induced
17 onto the pipelines as well as increased risk due to ground fault and lightning.6 When AC
18 voltage and current are induced onto steel pipelines, it can create a shock hazard for
19 anyone who comes into contact with an exposed pipeline.7 In addition, when fault
20 conditions on an electric transmission line cause high magnitudes of current flow in the
21 ground near a steel pipeline, it can cause a "step" shock hazard that causes a person
6 See NACE SP0177-2014 attached hereto as Exhibit C. kl.
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1 standing near a pipeline to experience a shock even if he or she never comes into direct
2 contact with the pipeline or its appurtenances.8
3 Q. DO THESE SHOCK HAZARD CONCERNS APPLY TO UNDERGROUND
4 PIPELINES AS WELL AS ABOVE-GROUND FACILITIES?
5 A. Yes. Underground pipelines must be excavated periodically for maintenance and
6 repair. Facilities that have been exposed to sufficient AC interference to create a shock
7 potential on the pipeline pose a risk of shock to Company personnel as well as members
8 of the general public that come near the excavated pipelines.9
9 Q. ARE THERE INDUSTRY STANDARDS RELATED TO THESE SHOCK
1 0 HAZARDS?
11 A. Yes. NACE International Standard SP0177-2014 specifically recommends that
12 pipeline operators mitigate induced voltage to below 15 volts to eliminate shock hazards
13 on exposed pipeline and appurtenances,1° though that standard notes that touch voltages
14 below 15 volts could also be dangerous to humans11 and especially to children.12 NACE
15 International Standard SP0177-2014 also recognizes that the risks of induced voltage
16 apply to underground pipelines as well as above-ground pipeline facilities,13 and it
17 specifically directs pipeline operators to address hazards to pipeline personnel who may
18 come into contact with exposed pipelines.14 In addition to the hazard during normal
19 operations, SP0177-2014 identifies more severe shock hazards that may be present during
20 short-circuit conditions.
8 Id. 9 Id. 1° Id. at 3 & 6. II Id. at 16; See IEEE Standard 80-2000 at 11 (identifying a 9-25 mA range for painful shock resulting in difficulty releasing an energized object (9-25 mA multiplied by 1,000 ohms results in a range of 9 to 20 V)). 12 NACE International Standard SP0177-2014 at 16. 13 Id. at i. 14 Id. at 15.
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1 Q. BASED ON THIS STANDARD, DO ANY OF ONCOR'S PROPOSED
2 TRANSMISSION LINE ROUTES CREATE A POTENTIAL SHOCK HAZARD?
3 A. Yes. As noted above, numerous segments on Oncor's proposed routes cross or
4 parallel within 1,000 feet of Kinder Morgan's existing pipelines. According to the
5 Company's prior modeling, AC voltage above 15 volts can be induced onto a steel
6 pipeline where a 345-kV electric transmission line and pipeline intersect or parallel
7 within 1,000 feet of each other.
8 Q. PLEASE EXPLAIN YOUR CONCERNS REGARDING THE RISK OF
9 ACCELERATED CORROSION ASSOCIATED WITH CROSSING OR
10 PARALLELING A STEEL PIPELINE.
1 1 A. When electric transmission lines cross or parallel (within a certain proximity) a
12 steel pipeline, the magnetic field created by the current in the electric transmission line
13 will induce AC voltage and current from the electric transmission line onto the steel
14 pipeline. Through holidays (unavoidable defects caused by both the application process
15 and human error) in the pipe's coating, this AC current can discharge from the pipeline
16 back into any surrounding soil that is in direct contact with the steel pipe. The current
17 flowing from the pipeline to the surrounding soil can cause metal-loss corrosion on the
18 outside of the pipe where the current leaves the pipeline. This corrosion can lead to
19 weakening of the pipeline and, ultimately, leakage or rupture, which could result in injury
20 to the public and damage to property.
21 Q. CAN YOU PREDICT THE ACTUAL AMOUNT OF PIPELINE
22 CORROSION DAMAGE THAT WILL OCCUR AS A RESULT OF AC
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1 INTERFERENCE FROM ONCOR'S PROPOSED ELECTRIC TRANSMISSION
2 LINE?
3 A. No. We know that Oncor's proposed routes pose a significant risk of AC
4 interference on Kinder Morgan's pipelines, and we know AC Interference creates a
5 significant risk of accelerated corrosion on steel pipelines and that significant corrosion
6 damage can occur within a short period of time..15 The level of AC interference can be
7 modeled in advance of energization to asses these risks, however, the actual rate of
8 corrosion damage that will occur without sufficient mitigation measures will depend on a
9 variety of factors including how the electric utility ultimately operates the line and the
10 resulting amount of current induced onto the pipeline at any given time, the density of
11 AC current flowing from the pipeline into the soil surrounding the pipeline, the resistivity
12 of the soil surrounding the pipeline, and numerous other factors that can fluctuate or
13 change over time.
14 Q. CAN CORROSION DAMAGE BE REVERSED AFTER IT IS
15 DETECTED?
16 A. No. Corrosion damage is permanent, and can occur in a very short period of time.
17 Furthermore, it can be difficult to immediately detect corrosion damage on buried
18 pipelines. Therefore, it is critical to prevent corrosion from ever starting by addressing
19 AC interference risks as soon as they are identified, as is required by both state and
20 federal law. Accordingly, in order to ensure that permanent corrosion damage does not
21 occur, the Company routinely analyzes the potential impacts of any new electric
I 5 See, NACE International Publication 35110 "Corrosion State-of-the-art: Corrosion Rate, Mechanism, and Mitigation Requirements" attached hereto as Exhibit D; U.S. Department of Transportation, ADB 03-06, 68 Fed. Reg. 64189-64190 (Nov. 12, 2003) (describing a newly constructed pipeline that experienced more than 50% wall loss over a two-year period of time due to corrosion related to stray electrical currents).
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1 transmission line installed near its steel pipelines as soon as location for that facility is
2 approved by the Commission. Depending on the level of AC interference predicted by
3 the modeling, the Company will work with the electric utility to install AC monitoring
4 equipment or mitigation measures prior to energization of the electric transmission line.
5 This practice is necessary to protect the public, the electric utility's facilities, reduce the
6 risk of significant pipeline repair and replacement costs, as well as to comply with state
7 and federal law..
8 Q. DO YOU HAVE ANY ADDITIONAL CONCERNS ABOUT ONCOR'S
9 PROPOSED TRANSMISSION LINE?
10 A. Yes. Natural gas is sometimes vented at certain above-ground facilities located in
11 the study area. Any approved transmission line must be routed at least 200 feet away
12 from those facilities in order to avoid the risk of an electric arc or spark igniting the
13 vented gas. Also, the weight of heavy construction equipment that crosses over a buried
14 pipeline during construction could cause the pipeline to be over-stressed and to fail.
15 Oncor should be directed to seek prior approval from the Company before it operates any
16 construction equipment on existing Kinder Morgan pipeline right-of-way. Also, based on
17 Company experience and policy, blasting should not be permitted within 1,000 feet of
18 Kinder Morgan's pipelines without notification to the Company, including complete
19 Blasting Plan Data due to the strain it could place on buried pipelines. Oncor should
20 therefore be directed to seek prior approval from the Company before it conducts any
21 blasting within 1,000 feet of Kinder Morgan's pipeline. If excavation is performed near
22 Kinder Morgan's pipelines, Oncor must contact One-Call and should follow the
23 excavation requirements of State One-Call Law and Common Ground Alliance Best
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1 Practices. Grounding, counterpoise, tower footings or other structures should not be
2 located in Kinder Morgan's rights-of-way or in proximity to Kinder Morgan's pipelines
3 to prevent damage from ground fault shorting conditions or lightning. Finally, if the
4 approved route were to cross Kinder Morgan's above-ground facilities, electric
5 transmission poles should be located far enough away from these facilities that if a pole
6 were toppled, it would not damage those facilities.
7 IV. THE RISKS ASSOCIATED WITH ROUTING ELECTRIC TRANSMISSION 8 LINES NEAR STEEL PIPELINES ARE WELL-ESTABLISHED. 9 V. 10 Q. DOES THE PIPELINE INDUSTRY RECOGNIZE THE THREAT OF
1 I SHOCK POTENTIAL FROM AC INTERFERENCE ON A STEEL PIPELINE AS
12 A RISK TO PUBLIC SAFETY AND PIPELINE INTEGRITY ?
13 A. Yes. The risk is clearly identified in NACE International Standard SP0177-2014
14 and IEEE Standard 80-2000. NACE specifically requires pipeline operators to mitigate
15 induced voltage to below 15 volts in order to avoid potential shock.16 16 Q. DOES THE PIPELINE INDUSTRY RECOGNIZE THE THREAT OF AC
17 CORROSION ON A STEEL PIPELINE AS A RISK TO PUBLIC SAFETY AD
18 PIPELINE INTEGRITY ?
19 A. Yes. The threat of AC corrosion is specifically recognized in NACE International
20 Standards SP0177-201417 and SP0169-2013,18 and it is addressed thoroughly in NACE
21 International Publication 35110,19 as well as in numerous studies that have been
16 NACE International Standard SP0177-2014 at 3 & 16. 17 Id. 18 See generally NACE International Standard SP0169-2013 attached hereto as Exhibit E. 19 NACE International Publication 35110 at 2 ("AC Corrosion or AC-enhanced corrosion (ACEC) is a bona fide effecr).
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conducted on the impacts of AC interference on pipelines.2° In addition, the federal
2 Pipeline and Hazardous Materials Safety Administration ("PHMSA") has identified
3 incidents where extensive corrosion damage related to induced current has occurred on
4 steel pipelines in services for only two years,21 and it specifically directs pipeline
5 operators to mitigate these risks pursuant to recommended practices and guidance
6 provided by NACE, ASME, and the Gas Piping Technology Committee ("GPTC").22
7 Further, federal minimum pipeline safety regulations, which have been adopted and
8 expanded on by the Railroad Commission of Texas,23 specifically require pipeline
9 operators to address corrosion from electrical interference,24 and a recently published
1 0 pipeline integrity rule specifically addresses the threat of AC interference.25
1 1 Q. ARE THERE INDUSTRY STANDARDS OR STUDIES THAT PROVIDE
12 GUIDANCE AS TO HOW TO MITIGATE THE RISKS OF ACCELERATED
1 3 CORROSION ASSOCIATED WITH INDUCED CURRENT ON A PIPELINE?
14 A. Yes. While Kinder Morgan's procedures use a limit of 30 A/m2 for its natural gas
1 5 lines, and 50 A/m2 for its oil and CO2 lines, NACE International Publication 35110
16 specifically recognizes a risk of accelerated corrosion on a steel pipeline associated with
17 exposure to current density above 20 amps per square meter ("A/m2").26 The 20 A/m2
1 8 standard has also been identified in numerous case studies addressing the risks of AC
20 See, e.g., Roger Floyd, "Testing and Mitigation of AC Corrosion on 8" Line: A Field Study" at 6-7 (NACE Corrosion 2004, Paper No. 04210, 2004) attached hereto as Exhibit F; M. Yunovich, N.G. Thompson, "AC Corrosion: Corrosion Rate and Mitigation Requirements" at 5 (NACE Corrosion 2004, Paper No. 04206, 2004) attached hereto as Exhibit G; R.A. Gummow, G.R. Wakelin and S.M. Segall, "AC Corrosion — A New Challenge to Pipeline Integrity" at 4-6 (NACE Corrosion 98, Paper NO. 566, 1998) attached hereto as Exhibit H. 21 U.S. Department of Transportation, ADB 03-06, 16 Fed. Reg. 64189-64190 (Nov. 12, 2003). 22 Id. 23 16 TAC § 8.1(b)(1) (2015) (adopting 49 C.F.R. part 192 in its entirety as a minimum safety standard for operation of natural gas pipelines). 24 49 C.F.R. §§192.473 & .917(5) (2015). 25 81 Fed. Reg. 20,722 (April 8, 2016) (proposing changes to 49 C.F.R. Parts 191 and 192 and specifically proposed rule 49 C.F.R. 192.935). 26 NACE International Publication 35110 at 5-6. Page 16
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1 corrosion on buried pipelines.27 In fact, numerous industry studies have found that
2 exposure at any level of current density can increase corrosion and that using a 20 A/m2
3 current density standard could still result in a 90% increase in corrosion compared to
4 conditions where no current is present.28
5 Q. IS THERE POTENTIAL FOR CURRENT DENSITY ABOVE 20 A/M2 ON
6 KINDER MORGAN'S STEEL PIPELINES FROM ANY OF THE PROPOSED
7 ROUTES IN THIS PROCEEDING?
8 A. Yes. A 345-kV electric transmission line that intersects or parallels within 1,000
9 feet of a steel pipeline can result in current density exposures above 20 A/m2. After a
1 0 route is approved, a route-specific modeling study will be conducted to determine
11 whether there is a risk of AC interference at any distance from a Kinder Morgan facility
1 2 and what mitigation is required, if any.
1 3 Q. HAS THE NEED FOR PIPELINE MITIGATION ACTIVITIES
1 4 ASSOCIATED WITH ELECTRIC TRANSMISSION LINES INCREASED IN
1 5 RECENT YEARS?
1 6 A. Yes. Over the last decade, the Company has been required to perform more
17 rigorous pipeline assessments pursuant to new and amended state and federal laws and
1 8 regulations related to pipeline integrity.29 During this time, the pipeline community at
1 9 large has become more aware of the threats associated with accelerated corrosion caused
20 by AC interference, and the Company has become more aware of the potential damage to
27 See supra note 18. 28 See, e.g , Yunovich, supra note 18, at 5. 29 See, e g., 26 Tex. Reg. 3214 (2001) (adopting new Railroad Commission Rule 16 Tex. Admin. Code § 8.101 (R.R. Comm'n of Tex.)). Page 17
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1 its facilities.3° Furthermore, because the recent expansion of renewable energy resources
2 in Texas have required installation of longer, higher-capacity transmission lines,
3 mitigation costs have risen.31 Higher voltage and current load generally result in higher
4 levels of AC interference, which generally requires more mitigation. Also, longer
5 electric transmission line installations typically involve more pipeline crossings and
6 longer stretches of pipeline paralleling, which can also require more mitigation.
7 Q. HAS THIS COMMISSION RECOGNIZED THE THREATS ASSOCIATED
8 WITH AC INTERFERENCE ON PIPELINES AND THE NEED TO TAKE
9 ACTION TO MITIGATE THESE IMPACTS?
10 A. Yes. This Commission specifically identified this as an area of concern in routing
11 determinations and, as a result of these concerns, modified its CCN routing criteria rule to
12 remove the preference for routing transmission lines in pipeline ROW.32 Furthermore,
13 during the May 21, 2015 Open Meeting at the Commission, Commissioner Anderson
14 concluded that the Texas Health and Safety Code provided a remedy.33 That sentiment
15 has been echoed by other administrative law judges in various CCN proceedings in front
16 of the Commission.34
17
30 NACE International Publication 35110 at 1. 'I Id. at 2; Shane Finneran & Barry Krebs, "Advances in HVAC Transmission Industry and Its Effects on Pipeline Induced AC Corrosion" at 4-6 (NACE Corrosion 2014, Paper No. 4421, 2014) attached hereto as Exhibit I. 32 See Docket No. 42583, Open Meeting Tr. at 32-33 (May 21, 2015) (addressing the need for mitigation and the applicability of the Texas Health and Safety Code to electric transmission line projects); Rulemaking To Amend Substantive Rule 25 101, Relating To Certification Criteria, Project No. 42740, Order Adopting Amendments to § 25.101 at 1 (Apr. 22, 2015) ("This intentional omission of pipelines from the list of compatible rights-of-way is intended to remove any preference for paralleling or utilizing pipeline rights-of-way while not prohibiting such consideration."). 13 Docket No. 42583, Open Meeting Tr. at 32-33 (May 21, 2015) (addressing the need for mitigation and the applicability of the Texas Health and Safety Code to electric transmission line projects). 34 See, e g , Docket No. 42087, Proposal for Decision, at 64 ("Most importantly, Atmos Energy is not without a remedy if the Commission does not order Oncor to pay for mitigation. Depending on the facts, the Texas Health and Safety Code may require Oncor to reimburse Atmos Energy's mitigation costs.")
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I VI. MITIGATING RISKS TO PIPELINE INTEGRITY IS REQUIRED BY STATE 2 AND FEDERAL LAW. 3
4 Q. IS KINDER MORGAN REQUIRED BY STATE OR FEDERAL LAW TO
5 MITIGATE CORROSION DAMAGE IN ORDER TO PROTECT PUBLIC
6 SAFETY AND PIPELINE INTEGRITY?
7 A. Yes. The Company is required by the Minimum Federal Safety Standards35 and
8 the rules of the Railroad Commission of Texas36 to assess and mitigate threats to public
9 safety and pipeline integrity, including the risks of corrosion damage. In addition,
1 0 PHMSA issued an advisory bulletin (ADB-03-06 Pipeline Safety Corrosion Threat)
1 1 directing pipeline operators to "identify, mitigate and monitor any detrimental stray
1 2 currents" associated with overhead electric transmission lines and to follow the
1 3 recommended practices and guidance provided by NACE, ASME, and GPTC regarding
1 4 mitigation techniques.37
1 5 Q. DO ANY FEDERAL OR STATE LAWS RELIEVE KINDER MORGAN OF
1 6 ITS OBLIGATION TO ADDRESS THREATS TO THE SAFETY OF ITS
17 PIPELINES BELOW CERTAIN THRESHOLDS?
1 8 A. No. Federal and state laws require the Company to assess and mitigate "threats"
19 to its pipelines and to "minimize" the detrimental effects of electric current without
20 regard to actual voltage levels or current densities, irrespective of the thresholds I have
35 See generally 49 CFR Part 192 & Part 195. 36 16 TAC §8.1(b)(1) (2015) (adopting 49 C.F.R. Part 192 in its entirety as a minimum safety standard for operation of natural gas pipelines); 16 TAC § 8.101 (2015) (requiring natural gas pipeline operators to establish ongoing pipeline integrity assessment and management plans and to promptly address any defects detected by the Company during its inspection); 16 TAC § 8.203 (2015) ("When a condition of active external corrosion is found, positive action must be taken to mitigate and control the effects of the corrosion. Schedules must be established for application of corrosion control. Monitoring effectiveness must be adequate to mitigate and control the effects of the corrosion prior to its becoming a public hazard or endangering public safety.") 37 U.S. Department of Transportation, ADB 03-06, Fed. Reg. 64189-64190 (Nov. 12, 2003).
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1 identified in my testimony.38 Kinder Morgan adopted the industry-recognized 15-volt
2 and 30 A/m2 thresholds in order to ensure that its steel pipelines comply with applicable
3 state and federal guidelines and pipeline safety regulations.
4 VII. REQUESTED RELIEF
5 Q. WHAT RELIEF DOES KINDER MORGAN SEEK IN THIS
6 PROCEEDING?
7 A. Kinder Morgan requests that the Commission include similar language in its Final
8 Order to that which it approved in prior CCN proceedings involving an electric
9 transmission line that impacts pipeline facilities.39 Specifically it requests that the
10 Commission include the following ordering paragraph:
11 Oncor must conduct surveys to identify pipelines that could be affected by
12 the proposed transmission line, and coordinate with pipeline owners in
13 modeling, and analyzing potential hazards prior to energizing the power
14 lines because of AC interference affecting pipelines being paralleled or
15 crossed.
16 Kinder Morgan requests the addition of "prior to energizing the power line" as a small
17 deviation from language the Commission has previously approved in order to ensure that
18 the electric transmission facilities do not pose the risks discussed above once energized. I
19 also recommend that the Commission include the following ordering paragraph:
20 Once any such hazards caused by AC interference are identified, Oncor
21 shall work with the impacted pipeline(s) to ensure that at any points at
38 See, e.g., 49 C.F.R. § 192.473(a) & .917(e) (2015). 39 Docket No. 43878, Final Order at Ordering Paragraph No. 13 (Mar. 30, 2016); Docket No. 42583, Final Order at FoF 110 & Ordering Paragraph No. 10 (May 27, 2015); Docket No. 42087, Final Order at Ordering Paragraph No. 10 (Dec. 19, 2014).
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1 which the transmission facilities parallel or cross the pipeline(s) the
2 transmission facilities will be sited and constructed so as to minimize the
3 amount of AC interference mitigation measures required to be
4 implemented by the pipeline(s) to ensure the safest conditions and to
5 minimize the cost of mitigation measures.
6 Because it has yet to be determined how the line will ultimately be constructed, it is not
7 certain what effects the line with have on Kinder Morgan's pipelines or the costs of
8 mitigating those effects. This language would provide Oncor and Kinder Morgan
9 flexibility in how to address the safety concerns created by AC Interference going
10 forward. This language would also provide Kinder Morgan, Oncor, affected landowners,
11 and Oncor's customers more clarity regarding how safety concerns created by AC
12 Interference will be addressed in the future.
13 Q. DO YOU RECOMMEND THE COMMISSION APPROVE ANY
1 4 PARTICULAR ROUTE?
15 A. No. As I said before, my testimony is intended to provide the Commission with
16 as much information as possible about the potential impacts to Kinder Morgan's natural
17 gas, oil, and CO2 pipelines so that the Commission is aware of any public safety risks or
18 mitigation costs that may be associated with a particular route. The Company only
19 requests that the Commission include the requested language in the final order so that the
20 Company and Oncor can work together to resolve these issues in the future.
21 Q. HOW WILL KINDER MORGAN DETERMINE WHETHER THE
22 APPROVED ROUTE REQUIRES MITIGATION ACTIVITIES?
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1 A. Once a final route has been selected, Kinder Morgan will work with Oncor and a
2 qualified third-party engineering firm to model the potential impacts of the proposed
3 electric transmission line on the affected steel pipelines and assess what mitigation
4 measures, if any, are necessary maintain safe levels of induced voltage and current.
5 Based on the recommendations of the modeling engineers, the Company will seek bids
6 on the installation of the recommended modeling measures. After the mitigation is
7 installed, the Company will conduct testing to determine if the mitigation is effective and
8 will continue to monitor the effects of the induced voltage and current as part of our
9 corrosion control program.
10 Q. WHAT SPECIFIC MITIGATION MEASURES DO YOU EXPECT WILL
11 BE NECESSARY TO ADDRESS AC INTERFERENCE FROM ONCOR'S
12 PROPOSED TRANSMISSION LINE?
13 A. Kinder Morgan expects that where the proposed electric transmission line crosses
14 a Kinder Morgan pipeline, efforts should be made to ensure that the crossing occurs at a
15 90-degree angle or as close thereto as possible. Kinder Morgan also expects efforts to be
16 made to minimize the portion of the proposed electric transmission line that runs parallel
17 to a Kinder Morgan pipeline at a distance of 1,000 feet or less.
18 More specifically, upon initial review, the proposed Route 1180 creates
19 significant parallels to Kinder Morgan's Wink 20" oil pipeline as well as Kinder
20 Morgan's 2000 30" natural gas pipeline. Between segments N2 and U, Oncor's proposed
21 Route 1180 parallels Kinder Morgan's Wink 20" oil pipeline at a distance of less than
22 1,000 feet for 16.3 miles. In the same corridor, Oncor's proposed Route 1180 parallels
23 Kinder Morgan's 2000 30" natural gas pipeline at a distance of less than 1,000 feet for
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1 5.5 miles. Because of the distance of these parallels, significant mitigation activities will
2 be required to prevent unsafe conditions along the affected pipelines.
3 Until modeling studies are complete, it is not possible to identify what level of
4 mitigation activity may be required to protect Kinder Morgan's pipeline facilities against
5 potential AC interference resulting from Oncor's proposed electric transmission line.
6 However, depending on the severity of the potential impacts to Kinder Morgan's
7 facilities, it would likely be necessary to install additional grounding systems along
8 impacted portions of an affected pipeline or relocate Kinder Morgan's facilities at least
9 1,000 feet away from any new electric transmission line, whichever is the most feasible
10 and cost-effective. Upon approval of a final route, Kinder Morgan will work with Oncor
11 to determine what mitigation measures, if any, are necessary, and that all operations
12 satisfy Kinder Morgan's requirements for overhead power lines in the vicinity of Kinder
13 Morgan's pipelines.4°
14 Q. WHAT IS THE ESTIMATED COST ASSOCIATED WITH INSTALLING
15 THE MITIGATION MEASURES YOU HAVE IDENTIFIED?
16 A. The costs will vary depending on the selected route and the actual impacts. It is
17 also reasonable to assume that over the life of an impacted pipeline, depending on the
18 level of AC interference, the grounding system may have to be replaced, which would
19 entail additional costs.
20 Q. COULD KINDER MORGAN'S MITIGATION COSTS BE HIGHER OR
21 LOWER THAN THESE ESTIMATES?
4° CorrPD-011 Requirements for Overhead Power Lines in the Vicinity of Kinder Morgan Pipelines, attached hereto as Exhibit J.
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1 A. Yes. Mitigation needs and costs can only be precisely determined once the exact
2 location of the approved route is determined. Costs will vary depending on numerous
3 factors including soil conditions (i.e. the resistivity of the soil), right-of-way conditions,
4 the configuration of the electric transmission line and amount of current it is expected to
5 carry, the type and configuration of the grounding system, the impact of other
6 engineering constraints, and any deviation or adjustments that are ultimately incorporated
7 into a final route that affect any of these variables. Upon final route approval, the Kinder
8 Morgan and Oncor will work together to model the impacts of AC interference and
9 determine the amount of mitigation necessary and what those mitigation costs may be.
10 Q. WHY IS IT NECESSARY TO MENTION THESE COSTS IN THE
1 1 CONTEXT OF THIS PROCEEDING?
12 A. Kinder Morgan acknowledges that the Commission will not require Oncor to pay
13 the costs of mitigation. However, the Commission should have as much information as
14 possible about the potential costs to Oncor in order to assess which route best meets the
15 Commission's routing criteria. I understand that the Texas Health and Safety Code
16 specifically requires any person building on, across, over or under a pipeline easement or
17 right-of-way to reimburse pipeline operators for the reasonable, necessary and
18 documented costs of measures necessary to protect the public or pipeline facility from
19 risks it creates on the Company's pipelines.41 Kinder Morgan mentions these costs in this
20 proceeding because all 89 of Oncor's proposed routes will be built on, across, over or
21 under one of Kinder Morgan's pipeline easements or rights-of-way, and because the
22 Commission's routing criteria include consideration of the costs of each route.42
41 TEX. HEALTH & SAFETY CODE § 756.123 (West 2015). 42 16 TAC § 25.101(b)(3)(B).
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1 Moreover, while Kinder Morgan is committed to working with Oncor to determine the
2 safest way to site and construct its electric transmission facilities near Kinder Morgan's
3 pipelines, it is equally committed to ensuring that Oncor reimburse it for having
4 prompted the need for significant and costly mitigation measures.
5 Q. DO ONCOR'S COST ESTIMATES FOR EACH ROUTE INCLUDE
6 POTENTIAL MITIGATION COSTS?
7 A. No. Oncor's estimated costs do not specifically include potential costs associated
8 with pipeline mitigation.
9 Q. HAVE YOU IDENTIFIED ANY ADDITIONAL MITIGATION
1 0 ACTIVITIES THAT MAY BE NECESSARY?
11 A. Kinder Morgan has identified above reasonably anticipated hazards created by the
12 new electric transmission lines and mitigative measures required to address these hazards,
13 but there may be additional mitigation activities that emerge once the lines are
14 constructed and energized.
15 In addition, if a route is selected that requires that heavy construction activities or
16 blasting be performed in close proximity to any existing pipeline facilities, the Company
17 requests that Oncor be directed to seek prior approval from the Company before it
18 operates any construction equipment on existing Kinder Morgan ROW or before it
19 conducts any blasting within 1,000 feet of existing pipeline facilities.
20 Q. IS THE RELIEF KINDER MORGAN SEEKS IN THIS PROCEEDING
21 CONSISTENT WITH HOW THIS COMMISSION HAS ADDRESSED AC
22 INTERFERENCE IN PREVIOUS CCN PROCEEDINGS?
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000025 1 A. Yes. As I stated above, the Company requests that the Commission include
2 language in the Final Order similar to the findings and ordering language it approved in
3 Docket Nos. 43878, 42583, and 42087, and ensure that the results of the required analysis
4 mean that the transmission facilities will be sited and constructed as safely as possible in
5 relation to the locations of existing pipelines.43
6 VIII. CONCLUSION
7 Q. DOES THIS CONCLUDE YOUR TESTIMONY?
8 A. Yes.
43 Final Order at FoF 110 & Ordering Paragraph No. 10 (May 27, 2015); Docket No. 42087, Final Order at Ordering Paragraph No. 10 (Dec. 19, 2014).
Page 26
000026 SOAH DOCKET NO. 473-18-2800 PUC DOCKET NO. 48095
APPLICATION OF ONCOR ELECTRIC BEFORE THE DELIVERY COMPANY LLC TO AMEND A CERTIFICATE OF CONVENIENCE AND NECESSITY FOR STATE OFFICE OF A 345-KV TRANSMISSION LINE IN CRANE, ECTOR, LOVING, REEVES, WARD, AND WINKLER COUNTIES ADMINISTRATIVE HEARINGS (ODESSA EHV — RIVERTON AND MOSS — RIVERTON CCN)
AFFIDAVIT OF ANDREW G. HEVLE
STATE OF TEXAS
COUNTY OF HARRIS
BEFORE ME, the undersigned authority, on this day personally appeared Andrew G. Ilevle who having been placed under oath by me did depose as follows:
I. My name is Andrew G. Heyle. 1 am of sound mind and capable of making this affidavit. The facts stated herein are true and correct based upon my personal knowledge. My current position is Manager of Corrosion Control at Kinder Morgan.
2. I have prepared the foregoing Direct Testimony and the information contained in this document is true and correct to the best of my knowledge.
Further alTiant sayeth not.
Andre-w G. Ilevle
SUBSCRIBED AND SWOR11 0 BEFORE ME this the day Of .2018. ;
CARYN 8 ARAGUZ NOTARY PUBLtC IN AND Notary 0 # 129013306 FOR THE STATE OF My Comnssion Expires 'TEXAS June 7 2020 My Comrnission Expires.. - le -Nor -gor
000027 Exhibit A
000028
1 No.: L-O&M 903 KINDERMORGAN Title: External Corrosion Control for Buried or Submerged Pipelines LIQUIDS O&M PROCEDURE Revised: 04-11-2018
Table of Contents 1. Applicability 1 2. Scope 1 3. Core Information and Requirements 1 3.1 Responsibilities 1 3.2. Protective Coatings . . 2 3.3 Cathodic Protection . 3 3.4 External Corrosion Design Considerations ... 4 3.5 Cathodic Protection Design 8 3.6 Criteria for Cathodic Protection . 11 3.7. CP Surveys, Monitoring and Adjustments 13 3.8. Shorted Casing Tests 19 3.9. AC Voltage and Fault Current Mitigation 21 4. Generate Annual Data and Transmit to GIS Database Gatekeeper 25 5. Training ..... 26 6. Documentation 26 6.1. External Corrosion CP Records 26 6.2. External Corrosion Inspection Records and Forms 27 6.3. External Corrosion Facility Installation Records 27 6.4. Cathodic Protection Surveys 28 6.5. Exposed Pipe Field Inspection . 29 7 References . 29
1. Applicability El CO2 [S] Crude E Highly Volatile Liquids (HVLs) / High Vapor Pressure (HVPs) Z Refined Products /Natural Gasoline
2. Scope This procedure prescribes: a. Requirements for protecting buried or submerged metallic pipelines from external corrosion in conformance with applicable codes, accepted industry practices and company specifications b External corrosion control procedures, including those for designing, installing, operating and maintaining cathodic protection systems. c. Requirements to collect, compile and distribute corrosion data for use in the KM Integrity Management process (IMP).
3. Core Information and Requirements 3.1. Responsibilities Supervisors and personnel responsible for insuring compliance with the corrosion control processes in this procedure shall maintain a thorough knowledge of corrosion processes and these procedures through means such as.
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a. Reviewing this procedure during annual corrosion team meetings or individually if team meetings are not possible. Refer to L-O&M Procedure 003, Procedure Review. b Attending National Association of Corrosion Engineers Training Courses. c. Attending/completing other industry recognized corrosion courses. d. On the job application of the procedures. e In-house corrosion training and presentations
3.1.1 Local Management Teams Ensure that regional corrosion specialists or other corrosion SMEs compile updated CPDM files into the region database and submit the data to the KMEP Business Unit Gatekeeper (refer to L-O&M Procedure 276, Annual IMP Schedule). Where CPDM is not used, ensure that other corrosion records are compiled and submitted to the KMEP Business Unit GIS Database Gatekeeper (refer L-O&M Procedure 276, Annual IMP Schedule). All local Management shall evaluate their external corrosion control programs with the responsible corrosion personnel (L-O&M Procedure 1700, L-I&M 1-1107.00) and develop a plan for any modifications of the CP system as required. The program should encompass all types of external corrosion to buried or submerged pipeline systems.
3 1 2 KMEP Business Unit GIS Database Gatekeeper Receive and input all applicable corrosion data from CPDM and other records into the GIS Database. Corrosion data is required for inclusion in the IMP risk model and will be routed to the Business Unit GIS Database Gatekeeper.
3 1 3 KMEP Manager, Risk Engineering Communicate risk model results to appropriate stakeholders, including KMEP Business Unit Integrity Management Team members.
3 1 4 KMEP Risk Management Team Support the KMEP Manager, Risk Engineering. Import Cathodic Protection Data Management (CPDM) databases or other corrosion records into the Risk Model, recalculate risk factor tables, and communicate results to KMEP Manager, Risk Engineering
Standard company and industry procedures are established for corrosion design. Designs that fall outside the areas covered in standard company procedures should be submitted per L-O&M Procedure 155, Management of Change.
3.2. Protective Coatings Per DOT 49 CFR 195.557, each buried or submerged pipeline (not including the bottoms of aboveground breakout tanks) must have an external coating for corrosion control if the pipeline:
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a. Was constructed, relocated, replaced or otherwise changed (not including pipe movement) after the applicable dates listed below (49 CFR 195.401(c)): b. An interstate pipeline, other than a low-stress pipeline, on which construction was begun after March 31, 1970, that transports hazardous liquid. c. An interstate offshore gathering line, other than a low-stress, on which construction was begun after July 31, 1977, that transports hazardous liquid. d. An intrastate pipeline, other than a low-stress pipeline, on which construction was begun after October 20, 1985, that transports hazardous liquid. e. A pipeline, on which construction was begun after July 11, 1991 that transports carbon dioxide. f. A low-stress pipeline on which construction was begun after August 10, 1994 9. Was converted for use in transporting hazardous liquids per 49 CFR 195.5 and: i. Has an external coating that: 1. Is designed to mitigate corrosion of the pipeline (if buried or submerged) 2. Adheres sufficiently to the metal surface to prevent under-film moisture migration 3. Is sufficiently ductile that it resists cracking 4. Has enough strength to resist damage due to handling and soil stress 5. Can support any supplemental cathodic protection 6. Has low moisture absorption and high electrical resistance (when coating is an insulating type)
ii. Is a segment that is relocated, replaced or substantially altered
3.3. Cathodic Protection a. Per DOT 49 CFR 195.563, each buried or submerged pipeline that is constructed, replaced or otherwise changed subject to the dates of 49 CFR 195 401(c) must have cathodic protection that is in operation no later than one (1) year after the construction, replacement or change. i. The cathodic protection will comply with one or more applicable criteria contained in Section 3.6.
b. Each buried or submerged pipeline converted under 49 CFR 195.5 for use in transporting hazardous liquids must have cathodic protection if the pipeline: i. Has cathodic protection that meets the requirements of Section 3.6, refer to Section 3.3.a.i. above, before the pipeline is placed in service; or ii. Is a segment that is relocated, replaced or substantially altered
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No.: L-O&M 903 KINDERrNORGAN Title: External Corrosion Control for Buried or Submerged Pipelines LIQUIDS O&M PROCEDURE Revised: 04-11-2018
c. All other buried or submerged pipelines that have an effective external coatingl must also have cathodic protection. Except as stated in Section d. below, this requirement does not apply to breakout tanks, and does not apply to buried piping in breakout tank areas and pumping stations until December 29, 2003. d. Bare pipelines, breakout tank areas, and buried pumping station piping must have cathodic protection in places where regulations in effect before January 28, 2002 required cathodic protection as a result of electrical inspections. e. Cathodic protection must be applied in areas where active corrosion is found on previously unprotected pipe.
3.4. External Corrosion Design Considerations Structure design should include but not be limited to corrosion control considerations and cathodic protection current requirements in the following sections. Electrically isolate the pipeline from all the following points except where the pipeline is electrically interconnected with a structure and both are cathodically protected as a single unit or where the pipeline is intentionally bonded to mitigate interference currents: a. Shipper/customer and other mechanically interconnected pipelines at changes in ownership b. Metallic casings and wall sleeves c Metal buildings and foundation steel d. River weights e. Valve enclosures (metallic buried valve boxes) f Pipeline bridges g. Other foreign metallic structures h. Anywhere electrical isolation is required to facilitate applying cathodic protection
NOTE: Avoid installing insulating devices in areas containing a combustible or explosive atmosphere without taking precautions to prevent arcing. Consider the following when designing for external corrosion: Induced AC current while operating in power line rights-of-way j. Shielding k. Other foreign cathodic protection systems near the facility l. Protect pipelines and insulating devices from fault currents and lightning with grounding anodes and fault current mitigation devices such as solid state surge suppressors
3 4 1. Test Stations and Other Contact Points Provide sufficient test stations or other contact points for electrical measurements to determine if cathodic protection is adequate. All test stations shall be entered into CPDM. Refer to Section 6.3 for new installations, changes, repairs, upgrades, etc.
A pipeline does not have an effective external coating if the current required to cathodically protect the line is the same as if the line was bare. Highlighting indicates revisions made as of the date on this procedure. Page 4 of 29 000032 No.: L-O&M 903 KINDER ORGAN Title: External Corrosion Control for Buried or Submerged Pipelines LIQUIDS O&M PROCEDURE Revised: 04-11-2018
Test points include test leads, valves, taps, meters, risers and other aboveground piping and should generally be no more than one mile apart Install corrosion control test leads at: a Pipe casings b. Foreign metallic structure crossings, if practical c. Buried insulating joints (install insulating joints above ground when practical)
Test leads necessary to determine whether cathodic protection complies with Section 3.6 of this procedure shall be maintained in a condition that enables obtaining electrical measurements. Test lead wires installed in conduit shall be suitably insulated to prevent the wire from being shorted to the conduit. These factors are important when selecting test point locations: d. Land use e. Accessibility f. Distance from other test points g. Population density h. Pipe coating condition and pipeline current demand i. Problem areas indicated by close interval survey data j. Span length test stations
The following may also be used in conjunction with test stations: k. Cathodic protection determining coupons I. Permanent reference electrodes
3.4.2. Using CTS's for Cathodic Protection and Static/Depolarized Structure to Soil Potentials The following provides guidelines for the use of Coupon Test Stations (CTSs) for the evaluation of effective levels of cathodic protection and determining static/depolarized structure to soil potentials. Cathodic Protection CTS's can be used for structure to soil potential measurements on pipelines and to represent the static or depolarized structure to soil potential on buried or submerged pipelines. CTS's are to have an area of 1.4 sq. inches per coupon. When Cathodic Protection CTS's are properly installed and maintained, they may be used, either by themselves or in conjunction with other measurement techniques, for evaluating compliance with NACE Cathodic Protection Criteria CTS's should be placed with guidance from ANSI/NACE RP0104 and NACE Technical Report 3201. Coupon test stations can be used to measure interferences to obtaining accurate pipe to soil readings.
3.4.2.1. Cathodic Protection Test Station Coupons can be used for structure to soil potential measurements on pipelines and to represent the static or depolarized structure to soil potential on buried or submerged pipelines. Highlighting indicates revisions made as of the date on this procedure. Page 5 of 29 000033 No.: L-O&M 903 KINDER ORGAN Title: External Corrosion Control for Buried or Submerged Pipelines LIQUIDS O&M PROCEDURE Revised: 04-11-2018
When Cathodic Protection Test Station Coupons are properly installed and maintained, Cathodic Protection Test Station Coupons may be used, either by themselves or in conjunction with other measurement techniques, for evaluating compliance with NACE Cathodic Protection Criteria.
3 4.2.2. IR drop that produces an error in the structure to soil on potential exists in the electrolyte and across the coating IR-drop error varies from pipeline to pipeline and along the length of a given pipe because of variations in soil resistivity, depth of burial, coating condition, stray current, local and long-line corrosion cells, galvanic or bimetallic structure contacts, multiple pipeline right of ways and the magnitude of cathodic protection current. 3.4.2.3. One method for determining IR drop error is by obtaining the mathematical difference between the on structure to soil potential and the instant-off structure to soil potential (obtained immediately after interrupting the CP current). The instant off structure to soil potential measured without delay after interruption of cathodic protection currents is an accepted method of determining the polarized structure to soil potential of buried or submerged pipelines. Galvanic or bimetallic structure connections that may be in contact with cathodically protected structures and that cannot be interrupted during on/instant off structure to soil surveys can influence the instant off structure to soil readings. Galvanic or bimetallic structure connections that cannot practicably be disconnected from the pipeline system can influence static or depolarized structure to soil readings
3.4.3. Where Coupon Test Stations can be used for determining Cathodic Protection Levels: 3.4.3.1. Pipeline systems that are by design, cathodically protected with galvanic anodes (sacrificial anodes) which for whatever reason cannot be interrupted to determine if IR exist in structure to soil potentials. Coupon Test Stations should be placed with guidance from ANSI/NACE RP0104 and NACE Technical Report 3201 on the pipeline where data obtained from the Coupon Test Stations is representative of cathodic protection levels and effective corrosion control.
3 4.3.2. Pipeline systems that are in the voltage gradient from other cathodically protected entities that may not be known These pipeline systems typically reflect high (more negative) readings than can be justified by good engineering judgment, instant off structure to soil readings and or high (more negative) readings than can be justified by good engineering judgment, static/depolarized structure to soil readings. Coupon Test Stations should be placed with guidance from ANSI/NACE RP0104 and NACE Technical Report 35201 on the pipeline where data obtained from the Coupon Test Stations is representative of cathodic protection levels and effective corrosion control.
3.4.3.3. Pipeline systems that are protected with impressed cathodic protection systems and are known to have or suspected to have galvanic (sacrificial) anodes connected directly to the pipeline. The areas that are affected by galvanic (sacrificial) anodes that are directly connected to the pipeline typically reflect high (more negative) readings than can be justified by good engineering judgment, instant off structure to soil readings and or high (more negative) than can be justified by good engineering judgment,
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static/depolanzed structure to soil readings Coupon Test Stations should be placed with guidance from ANSI/NACE RP0104 and NACE Technical Report 35201 on the pipeline where data obtained from the Coupon Test Stations is representative of cathodic protection levels and effective corrosion control
3 4 3.4. NACE RP 0104, ANSI/NACE Standard TM 0497 and NACE Technical Report 35201 should be used as guidelines for installation, monitoring and interpretation of data from cathodic protection test station coupons. LINK NACE RP 0104 — LINK ANSI/NACE Standard TM 0497 - LINK NACE Technical Report 35201.
3.4.4 Attaching Test Leads Use the exothermic welding or soldering/pin brazing process as the standard method to attach test leads to the pipe. For all methods: a To avoid the breaking of test leads due to stresses associated with backfilling, test leads will be install with sufficient slack or looping b Attach each test lead wire to the pipeline in a manner that minimizes stress concentration on the pipe c. Coat each test wire connection to the pipe with an electrical insulating material compatible with the pipe coating and the wiring insulation New test station locations must be added to CPDM.
3 4.4.1. Exothermic Welding a Perform ultrasonic testing on pipe prior to attaching any test lead (pipe wall thickness shall be 13.125-inch and the pipe shall have no detrimental surface or internal defects) b. Do not use welding powder charges larger than 15 grams c. Separate multiple lead attachments by a minimum of 4-inches
When exothermic welding is used with the above stated restrictions, there will be no need to reduce pressure or to perform maximum pressure calculations per L O&M 404.
3 4.4.2 Soldering/Pin Brazing Use only materials recommended by the manufacturer
3.4.5. Coatings Follow coating requirements contained in L-O&M Procedure 203, Coating Pipelines for external coating for buried lines.
3 4.6. New and Existing Casings
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Avoid installing casings whenever allowable or practical. Remove all casings that are no longer required if practical, such as at abandoned railroad crossings, road crossings and canals.
3.5. Cathodic Protection Design Consider particular characteristics of the pipeline system segment to be protected, such as coating quality at new and old pipeline segments, casings, bonds, bridges, foreign structures, right-of-way availability, unusual electrolytes and previous operating experience 3.5 1 Pipelines and Stations Follow these considerations when designing cathodic protection systems. a. Materials and installation practices shall conform to existing codes and National Electrical Manufacturers Association standards. b. Select and design the cathodic protection system for optimum economies of installation, maintenance and operation c. Deliver sufficient cathodic protection current to the structure to meet an applicable criterion for cathodic protection efficiency d. Minimize interference currents on neighboring structures
3 5.2 Breakout Tanks This procedure shall apply to the design, construction, and monitoring of all KMEP tank facilities. 3.5.2.1 Responsibility Regional corrosion personnel shall be responsible for determining the level of protection on protected facilities and implementing appropriate remedial action when so required.
3.5.2.2. Cathodic Protection Installed to Protect Tank Bottoms after 10/2/2000 When cathodic protection is installed to protect the bottom of an aboveground breakout tank of more than 500 barrels (79.5m3) capacity built to API Specifications 12F, API Standard 620, or API Standard 650 (or its predecessor Standard 12C), it must be installed in accordance with ANSI/API Recommended Practice 651. For new tank construction, the cathodic protection must be in operation no later than 1 year after construction is complete. Engineering standards for tank bottom cathodic protection shall be used for the cathodic protection systems. The following equipment may be considered during the design. a. Cathodic protection anode located under and near the center of the tank to provide protection to the center-most area of the soil side of the tank bottom b. Perforated access tube for the purposes of monitoring the pipe-to- soil levels of the cathodic protection system under the center area of the tank bottom c. Installation of a "permanenr half cell (may be replaceable type)
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d Installation of an electronic coupon, electrical resistance (E/R) probe, or other corrosion measurement device\See API RP 651 and API Standard 652 for additional information
3.5.2.3. Limitations of Installing Cathodic Protection Per ANSI/API RP 651 Cathodic protection is an effective means of corrosion control only if it is possible to pass electrical current between the anode and cathode (tank bottom). Many factors can either reduce or eliminate the flow of electrical current and, therefore, may limit the effectiveness of cathodic protection in some cases or preclude its use in others. Such factors that may preclude the use of cathodic protection include: a. tank pads such as concrete, asphalt, or oiled sand; b. an impervious external liner between the tank bottom and anodes; c. high resistance soil or rock aggregate pads, d. old storage tank bottoms left in place when a new bottom is installed.
Consult the local Regional corrosion personnel for appropriate corrosion control methods.
3.5.2.4. Monitoring of Tank Cathodic Protection Systems Annual structure-to-soil potential surveys should be performed and rectifiers should be checked for proper operation every two months in accordance with ANSI/API RP 651. However, due to unexpected delays and to allow flexibility in scheduling , annual surveys may extend to 15 months (but at least once each calendar year) and rectifier inspections may extend to 2 %month (but at least 6 times per year) This is consistent with the reasoning of Amendment 195-24, which extended all periodic inspection intervals. 3.5.2.4.1. Cathodic Protection Structure-to-Soil Readings Structure-to-soil potential measurements taken with the reference electrode in contact with soil at the perimeter of the tank is the most common method of determining the effectiveness of the cathodic protection system. Consideration must be given to the IR drop in the soil
3.5.2 4 2 E/R Probes Electrical resistance probes or other monitoring devices may be used to assess the corrosion rate of tank bottoms. E/R probes are typically connected to and cathodically protected along with the tank bottom to provide useful information. E/R probes may not be used as the sole method of assessment of cathodic protection performance for DOT regulated tanks.
3.5.2.4.3. E/R Probe Criteria When E/R probes are used, corrosion rates should be expected to be less than 5 mils/year.
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3.5.2 5 See API Recommended Practice 651 for more details.
3.5 3 Current Requirements Current requirement estimates may be obtained from: a. Using a "generator test to arrive at the actual current required to meet one or more of the applicable cathodic protection criteria b. Prior experience or test data obtained from pipelines with a similar coating material in similar electrolytes
NOTE: Additional current capacity should be provided in the design based on a best engineering estimate of coating deterioration rates, pipeline expansion, bond currents, etc
3.5 4. Field Survey Work For all impressed current cathodic groundbed designs: a. Determine the foreign facility crossings within the projected influence of the designed cathodic protection facility b. Obtain accurate measurements of the proposed cathodic protection system hardware locations c. Conduct current requirement and interference testing when practical d. Verify accessibility to the proposed work site e Verify AC power availability, voltage and phase f. Verify and document any existing/historical groundbed locations g. Review site for environmental considerations
For deep anode groundbed designs, determine the geology of the strata at the deep anode location. For distributed and conventional impressed current groundbed designs and galvanic anode designs, determine the electrolyte resistivity for the proposed anode locations.
3.5 5 Reviewing Design and Construction Work Personnel knowledgeable in corrosion and/or KM engineering practices shall review impressed current and galvanic anode groundbed designs The review should include calculation accuracy an agreement with assumptions and empirical design parameters, conformance to KM material and design standards, drawings, specifications and applicable codes. All construction work designed for corrosion control systems shall be in conformance with the latest revisions of construction drawings, specifications and applicable codes
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3.6. Criteria for Cathodic Protection This procedure specifies NACE Standard SP0169-2007 criteria and other considerations for cathodic protection contained in paragraphs 6.2.2, 6.2.3, 6.2.4, 6.2.5 and 6.3 (applied individually or collectively) to provide adequate cathodic protection for all applicable regulated facilities. No single criterion has proven satisfactory or practical to evaluate cathodic protection effectiveness for all conditions. Special cases may require using other NACE Standard SP0169-2007 criteria different from those provided in this procedure. The effectiveness of cathodic protection or other external corrosion control measures can be confirmed by visual observation, by measurements of pipe wall thickness, or by use of internal inspection devices. Because methods sometimes are not practical, meeting any criterion or combination of criteria in this section is evidence that adequate cathodic protection has been achieved. Corrosion leak history is valuable in assessing the effectiveness of cathodic protection Corrosion leak history itself, however, shall not be used to determine whether adequate levels of cathodic protection have been achieved unless it is impractical to make electrical surveys It is not intended that persons responsible for external corrosion control be limited to the criteria listed below. Criteria that have been successfully applied on existing piping systems can continue to be used on those piping systems. Any other criteria used must achieve corrosion control comparable to that attained with the criteria herein. Consult with the area corrosion representative for assistance with applications that may require other monitoring criteria.
3.6.1. Buried or Submerged Steel Structures CP Criteria External corrosion control can be achieved at various levels of cathodic polarization depending on the environmental conditions. However, in absence of specific data that demonstrate the adequate cathodic protection has been achieved, one or more of the following shall apply: 3.6.1.1. A negative (cathodic) potential of at least 850mV with the cathodic protection applied. This potential is measured with respect to a saturated copper/copper sulfate reference electrode contacting the electrolyte. Voltage drops other than those across the structure-to-electrolyte boundary must be considered for valid interpretation of this voltage measurement. NOTE: Consideration is understood to mean the application of sound engineering practice in determining the significance of voltage drops by methods such as: a. Measuring or calculating the voltage drop(s); b Reviewing the historical performance of the cathodic protection system; c. Evaluating the physical and electrical characteristics of the pipe and its environment; and d. Determining whether or not there is physical evidence of corrosion.
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3.6.1.2. A negative polarized potential of at least 850mV relative to a saturated copper/copper sulfate reference electrode. Polarized Potential: The potential across the structure/electrolyte interface that is the sum of the corrosion potential and the cathodic polarization.
3.6.1.3. A minimum of 100 mV of cathodic polarization between the structure surface and a stable reference electrode contacting the electrolyte. The formation or decay of polarization can be measured to satisfy this criterion.
Special Considerations. a. In some situations, such as the presence of sulfides, bacteria, elevated temperatures, acid environments, and dissimilar metals, the above criteria may not be sufficient. b. When a pipeline is encased in concrete or buried in dry or aerated high- restivity soil, values less negative that the criteria listed above may be sufficient.
Following are two methods for determining the 100 millivolt polarization shift: First method: Determine polarization voltage shift by interrupting the protective current and measuring the polarization decay When the current is initially interrupted, an immediate voltage shift will occur. Use the voltage reading after the immediate shift as the base reading from which to measure polarization decay. When polarization decays 100 millivolts or more, compliance is achieved. Second method: Determine the instant-off (polarized potential) by interrupting all current sources affecting the test point and recording the instant-off P/S potential Compare the instant-off polarized potential to the static potential and confirm 100 millivolts or greater difference. If 100 millivolt polarization shift is used the area CP Supervisor will determine if Section 3 6 2 is applicable.
3.6.2. Calculating A New "On" P/S Target Criteria Based on application of 100 millivolt polarization shift. Where polarization measurements have been taken and the ON P/S, Instant OFF P/S, Polarized P/S, IR drop, and Native P/S are known, a new ON criteria can be calculated as follows. 3.6.2.1. Calculate the IR Drop The IR drop is the arithmetic difference between the ON P/S and the Instant OFF P/S.
3.6.2.2. Calculate the new ON Criteria Use L-0M900-16, Polarization Work Sheet to calculate the new ON criteria by adding the Rest P/S plus the IR drop plus 100 mV of desired polarization.
3.6.2.3. Example:
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In the example below, it can be said that cathodic protection has been achieved and that protection would be adequate at an ON P/S of at least 650 mV CSE Polarization readings are measured as follows:
P/S Reading P/S Value Remarks ON 750
Instant OFF 600 Current interrupters on all current sources Measured after a 24-48 hour CP shut Rest (static) 400 down Calculations IR Drop 150 On minus Instant Off Polarization 200 Instant Off minus Rest (static)
A new target ON potential can be calculated as follows. This new target may be used for annual LOP readings for a maximum of 3 years. Should the environmental or operating conditions change significantly, tests should be conducted on a more frequent basis.
Calculating a New Target ON P/S P/S Reading P/S Value Remarks Measured after a 24-48 hour CP shut Rest (static) 400 down Desired polarization 100 Known IR Drop 150 At given rectifier outputs New Target ON P/S 650
3.7. CP Surveys, Monitoring and Adjustments Conduct periodic measurements and inspections to detect changes in the cathodic protection system to ensure that each part of the CP system is operating properly. As conditions that affect cathodic protection change with time, changes may be required to maintain protection (refer to 49 CFR 195 573) 3.7 1 Pipe-to-Soil Surveys Measure pipe-to-soil readings at least once each calendar year, not to exceed 15 months at all established test points on all pipelines and appurtenances needed to meet the applicable criteria Interrupted On/Instant Off pipe to soil surveys will be run every year to obtain I/R free readings. IMP Protocol 13 is to be used for interrupter installation and removal. Recommended cycle time for interruption is 4 seconds On and 1 second Off. Coupon Test Stations (CTS) can be used to help determine UR drop in CP readings.
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If the CTS's are in adequate numbers on a pipeline or facility and placed in representative locations, then an interrupted annual survey can be run every third year and CTS's used the two years in between to determine IR effect in CP readings If a pipeline, terminal, facility or station does not have adequate CTS's then an interrupted annual survey is to be run every year. A minimum of a CTS at approximate midpoint between rectifiers and approximate half way between the midpoint and the rectifier on pipelines is required to obtain UR free readings in the year that an interrupted survey was not run. The Corrosion Manager or lead CP Technical person should determine adequate numbers and locations for CTS's in facilities. New metallic pipelines shall be cathodically protected and must have a post- installation cathodic survey performed within one year of the installation date.
3 7.2 Cathodic Protection Units (CPU) Surveys Electrically check all impressed current rectifiers or other impressed current sources for proper operation. Read and record output at least six times each calendar year, not to exceed 2.5 months. (Remote monitoring units that will provide volt and amp readings that can be electronically moved into the American Innovations — Pipeline Compliance Systems — Cathodic Protection Data Management (PCS-CPDM) program will be accepted as means to monitor cathodic protection.) 3.7.2.1. RMU Channel Designation for Cathodic Protection Rectifiers a. Analog Channel one (1) is designated to monitor DC Amp output from the rectifier. b. Analog Channel two (2) is designated to monitor DC Volt output from the rectifier. c. Analog Channel three (3) is designated to read Pipe to Soil Potentials (recorded as —DC Millivolts mV) using a permanent half cell. d. Analog Channel four (4) is designated to read other negative leads for DC Amp output that may be connected to the rectifier.
3.7 2 2. Channel Designation for AC Monitoring a. Analog Channel one (1) is designated for monitoring AC Amps from a decoupling device to ground, b. Analog Channel two (2) is designated for monitoring Pipe to Soil Potentials (recorded as —DC Millivolts mV) using a permanent half cell. c. Analog Channel three (3) is designated for monitoring AC Current Density The readings are to be recorded in Amps per square meter. Coupons are to be standardized with 1.4 square inch coupons. Current Density as measured in this manner is a measure of AC amp flow from the pipe to earth. d. Analog Channel four (4) is designated to record AC volts on the pipeline. This channel should be connected to the permanent half cell and the pipeline
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3.7.2.3. Remote Monitoring Frequency for Obtaining Readings a. Remote Monitors Units monitoring rectifiers should be set to obtain data once a week. b. Remote Monitoring Units monitoring AC should initially be set to obtain data once an hour. Readings are to be obtained at the beginning of the hour, (example 6:00, 7:00, 8:00). When data trending has allowed a database to be established showing AC Current Densities are mitigated to levels not allowing AC Corrosion to occur, then RMU's can be set to obtain data once a week. Please refer to IMP Protocol AC Voltage and AC Corrosion Mitigation and Monitoring IMP Protocol 15
3.7.2.4. Remote Monitoring Alarms Remote Monitoring Unit alarms for rectifiers should be set to notify the corrosion person responsible for the area and their supervisor in the event the power to the rectifier is lost.
3.7.2.5. Remote Monitor Units monitoring AC should be set to notify the corrosion person responsible for the area and their supervisor in the event any of the following occur: a. AC Current Densities rise above 75 Amps per square meter, as measured on a 1.4 square inch coupon in contact with earth. b. Alarm Notifications are to be sent to the corrosion person responsible for the area and their immediate supervisor.
3.7 3. Interference Bond Surveys (Positive and Negative) Test positive interference bonds, diodes, and reverse current switches whose failure would be detrimental to structure protection for proper operation at least six times each calendar year, not to exceed 2.5 months. Test positive interference bonds, diodes, and reverse current switches whose failure would be detrimental to structure protection for proper operation as needed (not to exceed 2.5 months) if associated with underground direct current (DC) transmission systems, DC railroad operations or similar high DC energy systems. Test negative interference bonds, system bonds, diodes, or reverse current switches whose failure would not be detrimental to structure protection for proper operation at least once each calendar year, not to exceed 15 months
3.7.4. Isolation Device Surveys Test the insulating effectiveness of each insulating set necessary to facilitate applying corrosion control to ensure that electrical isolation is adequate at least once each calendar year, not to exceed 15 months.
3.7.5 Criteria for Close Interval Survey
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This procedure shall apply when pipe-to-soil Close Interval Survey (CIS) readings are being considered and/or taken on mainline pipelines. Also, within 2 years after cathodic protection is installed, identify the circumstances in which a CIS or comparable technology is practicable and necessary, to accomplish the objectives of NACE SP 0169 paragraph 10.1.1.3. 3.7.5.1. Responsibility The Area Corrosion Engineer/Specialist/Engineering Assistant shall be responsible for determining the need for CIS, for the selection of qualified personnel to gather close interval field data, and for analysis of (CIS) data.
3.7.5.2. Determination of Need Sound engineering judgment shall be applied in considering potential deficiencies identified in field data. Review of ancillary data, such as in-line inspections (ILI) data, should be conducted. Determination of the best course for future action should include review of ILI inspection schedules and other integrity management, inspection, and testing programs. Where the facility can not be inspected with ILI tools or where there is no recent (within 3 years) ILI information and where a combination of two or more of the following circumstances apply, close interval survey (CIS) should be considered: Where multiple (3 or more) sequential electrical test station readings along the pipeline have significant decreases (e.g. +300 mV) from one year to the next, or, Where multiple (3 or more) sequential electrical test station readings along the pipeline are near (+20 mV), are at, or below minimum protection levels, or, In densely populated areas where there has been significant construction with potential undetected 3rd party damage and for which there is no ILI inspection data post construction, or; Where multiple foreign pipeline without test leads cross the pipeline and/or where the possibility of additional unknown foreign pipelines may cross the pipeline, or; Where high cathodic protection densities (+2 mAgt2) may be present AND where polarization criteria being utilized AND where un-inspected and un- repaired ILI corrosion anomalies are present from previous ILI inspections, or, In an area where more than one leak has been directly caused by external corrosion of the pipeline. Where recent (within 3 years) ILI information is available and two or more of the above conditions exist, a thorough review of the most recent ILI information should be conducted with consideration begin given to further investigation (e.g. additional inspection digs).
3.7.6. Unprotected Pipe Evaluation Unprotected pipe will be evaluated to determine areas of active corrosion by electrical survey as follows. a. Before December 29, 2003, at least once every 5 years not to exceed 63 months.
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b. Beginning December 29, 2003,at least once every 3 calendar years, but with intervals not exceeding 39 months.
If electrical survey is deemed impractical, other means may be used, which will include review and analysis of leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment.
3.7.7. Remedial Action Corrective action must be taken when any deficiencies in cathodic protection are discovered during cathodic protection monitoring before the next monitoring period (includes all aspects of CP monitoring rectifiers, bonds, annual surveys, etc.) If corrective actions cannot be completed before the next monitoring period, a corrective action plan must be established with justification. The corrective action plan is to be submitted to the proper manager for tracking as needed. A copy of the corrective action plan will be maintained in the local file. When cathodic protection levels are discovered to be below established criteria levels, take remedial action to restore cathodic protection to acceptable levels Consider the particular problem affecting pipeline and pipeline integrity in completing the remedial action. Any remedial action necessary to facilitate the effective application of corrosion control regarding annual pipe to soil surveys must not extend 15 months beyond discovery. When local knowledge determines that CP data indicates a change in corrosion rate for any pipeline segment, the Local Management Team reports these segments to the regional KMEP Algorithm Team member for review and potential inclusion/modification to the Risk Algorithm (refer to L-O&M Procedure 277, Review Risk Alwrithm).
3 7 8 CPU Adjustments Adjust all cathodic protection unit (CPU) voltage and current settings considering soil moisture conditions along the affected pipeline that can affect soil resistivity. This will help ensure maintaining an acceptable level of output for the unit under varying soil conditions that will prevent damage to the pipe and pipe coating. Review the rectifier manufacturer owner's manual to determine the unit operating characteristics. Confirm that the installation is correct and that the rectifier groundbed is ready to energize. Items to verify for new rectifier installations include: a. The rectifier positive and negative terminals are labeled correctly b The rectifier AC input voltage is as indicated for the rectifier unit installed c. The rectifier is grounded correctly d. Pipeline cables are connected to the negative rectifier terminal e. Anode cables are connected to the positive rectifier terminal f. Rectifier output does not exceed the rated capacity
3.7 9 Post-Installation Survey
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Conduct a survey after installing any cathodic protection bond, isolation device or CPU system to determine if the installation and CP adjustments satisfy applicable criteria and operate efficiently. a. Post-installation tests shall include the following survey information: b. Pipe-to-soil potentials at all affected test points c. Casing-to-soil potentials at all affected casings d. Foreign line-to-soil potentials at affected crossings e. Foreign line-to-soil potentials at all affected insulating fittings f. Copies of all interference test data (if performed), completed company forms and correspondence g. Current and voltage of impressed current rectifiers affecting the pipeline segment (if applicable) h. Current of galvanic anodes affecting the pipeline segment (if applicable) i. Other types of measurements that may be required to document the post- installation survey include: j. Static pipe-to-soil potentials k. Close interval, DCVG, PCM or other appropriate CP surveys
3.7.10. Interference Test Surveys Each impressed current-type cathodic protection system or galvanic anode system must be designed and installed to minimize any adverse effects on existing adjacent underground metallic structures Conduct interference tests on metallic structures in the immediate area after energizing new CP units or after installing metallic structures in the area of influence of a CP unit if either party desires. Use L-0M900-02 Interference Test Report to record results. Resolve any interference problem to the mutual satisfaction of the parties involved When KM becomes aware that other entities have installed cathodic protection units in the vicinity of KM pipelines that may cause interference, testing will be conducted to determine detrimental effects and mitigative actions taken when necessary. When local knowledge determines that interference test data indicates a need for corrective action for any pipeline segment, the Local Management Team reports these segments to the regional KMEP Algorithm Team member for review and potential inclusion/modification to the Risk Algorithm (refer to L-O&M Procedure 277, Review Risk Algorithm).
3.7.11. Interfering Current Susceptibility Actions (Texas Intrastate Only) Kinder Morgan Personnel shall utilize right-of-way inspections to determine areas where interfering currents are suspected. In the course of these inspections, personnel shall be alert for electrical or physical conditions which could indicate interference from a neighboring source. Whenever suspected areas are identified, the operator shall conduct appropriate electrical tests within six months to determine the extent of interference and take appropriate action.
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3.8. Shorted Casing Tests Pipelines at many road and railroad crossings pass through casings. Casings can be either electrolytically or mechanically shorted. An electrolytic short is a pipe that is shorted to the casing through a non-metallic path, such as mud water. or. It is generally not harmful since the electrolyte will distribute the current throughout the casing. A mechanical short is pipe that is shorted to the casing through a mechanical or direct path. Generally, a mechanical short will reduce the effectiveness of cathodic protection. Test electrical isolation by comparing the casing-to-soil potentials to the matching pipe-to-soil potentials at least once each calendar year, not to exceed 15 months.
Difference Electrical Isolation Action
> 50 millivolts Yes Inspect at required rate 50 millivolts No Test for type of short
3.8 1. Testing Casings for Type of Short Test to determine the type of short using L-0M900-01, Data Sheet for Testing Casings. Electrolytic shorts must be re-tested in five (5) years. Metallic shorts must be inspected as stated in 3.8.2.1. or 3.8.2.2.
Average Resistance Type of Short
> 0.08 ohms Electrolytic 0.08 ohms Mechanical
3.8 2. Casing Inspections 3 8 2.1. Inspection of Metallically Shorted Casings Metallically shorted casings shall be monitored for leakage by "sniffing" using a portable gas detector at intervals not exceeding 7% months but at least twice each calendar year. L-0M900-17, Shorted Casing Inspection Report or a computerized maintenance management system shall be used to document the monitoring of the shorted casings and will include the following informa- tion.
a. Line Section/Name and Line Size b. Location Description c. Date of Inspection d. Initials of Inspector e. Results of Inspection with remarks, if necessary
3 8.2.2 Internal inspection of Line Pipe Inside Shorted Casings
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In the event an internal inspection survey ("smart pig") and subsequent field verification indicate corrosion on a pipeline inside a shorted casing, and the corrosion is judged to be severe, corrective action shall be initiated in accordance with Kinder Morgan's Integrity Management Plan (IMP) If light or moderate corrosion is indicated by the survey, and the integrity of the line has not been compromised, the crossing shall be monitored as des- cribed in 3.8.2.1. A reevaluation pig run or visual examination will be per- formed within five (5) years to provide information as to corrosion rate for these locations. Where a shorted casing exists, and no corrosion is indicated by the survey, no further special monitoring of the casing is required, provided a -850 mV minimum pipe to soil potential is achieved at both adjacent test stations.
3 8.3 Clearing Mechanically Shorted Casings Clear mechanical shorts if practical, prior to the next inspection. Approved methods to attempt to clear shorted casings include: a. Cutting bond straps b. Trimming back the casing end c. Installing new end seals d. Installing additional insulators at casing ends e. Minor movement of the carrier pipe using sound engineering practices
Equipment for lifting includes side boom slings or belts and air bags (preferred) The pipe/casing alignment should be maintained by adequate earth compaction or by earth filled bags or poured concrete supports, as required by the particular situation. If exposing one end clears the short, it is not necessary to expose both ends of the casing. Install approved end seals on any exposed casing end. Replace Dresser-type end seals when practical If possible, use smart pigging to monitor for corrosion inside the casing. Smart pigging and increased inspection cannot replace practical attempts to clear the short. When local knowledge determines that mechanically shorted casings exist and cannot be cleared for any pipeline segment, the Local Management Team reports these segments to the regional KMEP Algorithm Team member for review and potential inclusion/modification to the Risk Algorithm (refer to L-O&M Procedure 277, Review Risk Algorithm.
3.8.4. Filling Shorted Casings Filing shorted casings may be used as an option in dealing with shorted casings. Guidelines for filling shorted casings follow: a. Verify adequate opening from vent pipe into casing. 1 1/2" diameter minimum to accommodate injection of inhibited fluid or dielectric casing filler if needed.
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b Retest the casing to determine if the short has been cleared. If the short has been cleared then casing end seals should be installed and the casing and carriers pipe backfilled insuring that settling will not cause another short in the future Test leads should be installed or repaired Newly installed test stations must be added to CPDM.
If the short has not been cleared then continue preparation for filling the casing with inhibited fluid or dielectric casing filler. c. Flush the casing annulus with clean water to remove trapped mud, dirt and to insure an open annulus is obtained. Adapt end of casing vents as needed to facilitate connections for pumping the casing with casing filler. Note which end of the casing is the lowest as this is the end where casing filler should be pumped into the casing. d After the casing has been drained and dried, install appropriate non- conductive casing seals. Suggested casing seals: Link seals by Thunderline Corp. or equivalent should be installed behind the vent pipe away from the casing end. Canusa LRK (Heat Shrinkable) casing seal, by Shaw Pipe, Inc , or equivalent This seal should be installed in addition to the Link seals. iii. Replace or repair test stations as required. It is recommended that two wires from the test station be attached to the carrier pipe and one wire from the test station be attached to the casing.
e. Casing fillers should be pumped through the casing vent n the lowest end of the casing. Casing fillers should be pumped at a slow rate. Volumes of casing fillers should be monitored to insure the annuals area in the casing is completely filled.
3.9. AC Voltage and Fault Current Mitigation Pipelines operating in the same corridor or near electric high voltage transmission lines often experience high voltage levels due to a combination of conditions. These conditions can occur both during steady AC transmission system operation as well as during fault conditions. Take remedial measures to prevent the voltage level from exceeding 15 VAC-RMS. Pipelines operating in the same corridor or near high voltage AC electric transmission lines often experience unwanted induced AC voltage and/or current levels due to a combination of conditions. The induced AC Voltage and current occurs during steady AC transmission system operation, which creates an inductive couple with the pipeline and is a function of several variables including the proximity of the power lines to the pipeline, the current level flowing in the power line, atmospheric conditions, soil resistivity, pipeline depth of cover, etc. In some cases there can be a safety hazard (AC Voltages above 15v) resulting from the induced voltage level and in others, there can be pipeline deterioration in the form of metal loss (AC corrosion) from high current density discharge to ground. Typically newer pipeline systems coated with technologically advanced coatings such as Fusion Bond Epoxy, Coal Tar Enamel, Extruded Polyethylene, etc, are the most vulnerable to AC corrosion. In any event, a path to ground (holiday) is required or AC corrosion will not occur.
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It is the purpose of this section to identify locations along the pipelines where there is a reasonable probability for AC corrosion or safety issues to exit, to evaluate each for the presence of issues, to mitigate those issues that are found to be potentially injurious to the integrity of the pipeline, and to monitor to assure mitigative effectiveness on a continuing basis.
3.9 1. AC Voltage and Fault Current Remedial Action 3 9 1 1 Locations of Potential AC Inductance Coupling Regional Corrosion Personnel should identify locations where AC inductance coupling can exist on Kinder Morgan Pipelines using the following methods: a Applying electric grid mapping data provided by the GIS Manager b Applying locations established while performing annual pipe to soil surveys. c. Applying Identified Overhead Power Line locations observed during day-to-day travel along the Pipeline Corridors.
3 9 1 2. AC Corrosion Pipeline Deterioration Susceptibility Criteria Criteria for consideration as having susceptibility to pipeline deterioration caused by AC corrosion when evaluating above identified locations that may require further investigation: a. Pipelines coated with newer coating materials/technologies such as FBE, Coal Tar, Extruded Polyethylene, multilayer coatings, etc. typically are more conducive to having issues in the presence of holidays than the older coatings. b. Inductance couples are known to possibly exist where the pipeline runs more than 250 feet along and parallel to a 35 KV or higher overhead power line and within a 150 foot lateral distance from the outer line of the overhead power line. Overhead power lines that operate at higher KV give a higher probability of inductance coupling. c. Issues are known to possibly exist where 35 KV or higher overhead power lines cross pipelines at angles equal to or less than a 45'angle. Higher KV yields higher concern.
3 9 1.3 AC Corrosion Pipeline Deterioration Susceptibility Action Required a. Action required, if susceptibility is found (as described above), can be one of two options: Determine if the conditions exist for AC corrosion by installing coupon test stations at the beginning and ending of the interaction between the pipeline and the HVAC overhead power line. Low soil resistance areas are preferred locations for coupon test stations. If the defined area runs for several thousand feet it may require several coupon test stations. Following is the Information that should be obtained from coupon test stations: i. AC Voltage
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AC Current Density (Amps/Meter2) iii. Instant Off DC Pipe to Soil potential iv. On DC Pipe to Soil potential v. Native DC Pipe to Soil potential vi. DC Current Density
b. Or, employ the services of a qualified engineering firm to develop a model to define the probability of there being of AC corrosion. If this method is chosen the engineering firm choice must be approved by the Corrosion Process Manager and an explicit Site Specific Protocol must be developed and approved prior to commencement of the study.
In addition to performing either 1 or 2, above, when ILI is used as the assessment method, the start and end of each location described above will be provided to the Director of Pipeline Integrity in Houston so that a complete ILI examination can be performed to ascertain whether or not the telltale signature for AC corrosion exists
3.9.2. AC Corrosion Probability AC current density is the primary indicator of the probability that AC Corrosion will occur, and the following criteria will be used to ascertain that probability. a. When AC current densities are less than 50 amps per square meter, AC Corrosion is less likely to occur and no mitigation is required. b. When AC current densities are between 50 amps per square meter and 100 amps per square meter, AC Corrosion is possible and mitigation should be initiated on an important basis depending on the current density level, ILI evaluation, location, and other risk considerations c. When AC current densities are more than 100 amps per square meter, AC Corrosion will occur and mitigation should be initiated on an urgent basis
3.9.3. AC Corrosion Mitigation Mitigation can take many forms and the following methods have proven to be effective under many situations. The method(s) chosen for each location must be supported by mitigation design criteria and must be approved by the Corrosion Process Manager. a. Installing point drains b Installing magnesium anodes c. Installing zinc anodes d. Installing zinc ribbon in the affected area e. Installing copper wire encased in carbon
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f. Installing grounding cells g. Other methods may be used upon approval by the Corrosion Process Manager
3.9.4. Trending AC Corrosion Monitoring Parameters Remote Monitoring Units should be used to trend AC Voltages, AC current densities, AC AMPs to ground and cathodic protection levels. Refer to IMP. IMP Protocol 15 - Set Up for Remote Monitoring Units or Section 3 7 2 in this Procedure to assure the RMU's are set up correctly After installing induced AC mitigation devices, follow up surveys and measurements are to be obtained to assure AC current densities are mitigated to a level that will not cause AC corrosion (Less than 50 amps per square meter). The monitoring needs to continue over time to assure all peak loads on the AC power line are observed and environmental changes are taken into consideration (a period of one year)
3.9.5. Design for Mitigation and Monitoring for AC Induced Coupling on New Pipelines Pipelines operating in the same corridor or near high voltage AC electric transmission circuits often experience induced AC voltage and/or current interference effects due to a combination of conditions. The induced AC Voltage and current effects to the pipeline occur during normal operation of these electric circuits. These AC interference effects are a function of several variables including: a The proximity of these circuits and the towers to the pipeline, b. The amount of AC current flowing in the power line, c. Atmospheric conditions, d. Soil resistivity, e. Pipeline depth of cover, f. Pipeline coating type, etc.
These AC interference effects can result in safety hazards to personnel and the public and/or pipeline deterioration in the form of metal loss (AC corrosion) from high level current density discharge to ground at coating holiday locations. It is the purpose of this section to provide guidance for proper engineering, design and installation of effective AC mitigation systems during new pipeline construction.
3.9 5 1. Information Required for Design and Modeling for AC Induced Coupling on New Pipelines a. Alignment sheets showing the route and adjacent power lines need to be supplied to the engineering firm performing the AC interference analysis and designing the AC mitigation systems. b. After the new pipeline route is staked, a field survey of the pipeline route and adjacent facilities is required by the engineering firm. The information obtained in the field should consist of: i. Details of the orientation of the pipeline in relationship to overhead power lines.
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ii. Soil resistivity studies will be conducted at sites selected prior to and during the field survey. All soil resistivity test locations will be recorded using sub meter GPS equipment. iii. Identification of overhead power line owners and contact information
Contact with overhead power line owner — operators will be made by the engineering firm after completion of the field survey. Specifics about power line loads, tower dimensions, phase orientation, etc will be obtained for use in the AC interference analysis modeling program. d Modeling will begin using the pipeline and power company circuit information obtained. The modeling process may take 4 or 5 weeks, depending upon scope of work and length of new pipeline in proximity to these electric transmission circuits.
3 9 5 2. Deliverables from Design and Modeling A proposed AC mitigation system design package including proposed grounding locations will be delivered to the Engineering Manager. A design review meeting should be held within 10 working days from the date of delivery with the Engineering Firm and the Engineering Manager to review the proposed design for technical acceptance and any installation issues. Any required changes should be noted and agreed to by the Engineering Firm and the Engineering Manager. A final design will be delivered in 20 working days from the date of the design review meeting. The final AC mitigation system design package will contain the following, as a minimum. a. Detailed drawings of the proposed AC mitigation systems b. Proposed locations (to a sub meter GPS level) for installation of the AC mitigation systems. c. A detailed material list for the AC mitigation systems. d Installation cost for each AC mitigation system location. e. Technical report outlining all data, analysis, and results for the AC interference analysis on the new pipeline
NOTE. Each AC Mitigation System will have a remote monitoring system installed as defined in IMP Protocol 15 - Set Up for Remote Monitoring Units or Section 3.7.2 of this Procedure AC current density measurements on steel coupons that are electrically connected to the pipeline and are of a known dimension (1 4 square inch) are a key tool in identifying locations where AC corrosion will occur. The most practical way to obtain AC current density information is by using coupon test stations to measure AC Current Density
4. Generate Annual Data and Transmit to GIS Database Gatekeeper
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The Business Unit GIS Gatekeeper imports the CPDM database and other corrosion records into the GIS Database. The KMEP Risk Management Team utilizes the corrosion data as one element in the GIS Database to recalculate risk model risk factors as a part of the annual review cycle and integration of data as described in L-O&M Procedure 275, Continuing Analysis to Identify Prevention and Mitigation Measures and L-O&M Procedure 276 Annual IMP Schedule.
5. Training Review the preceding information as necessary before performing the procedure. Employees performing this procedure will be qualified per the KM Operator Qualification program (Refer to L-O&M Procedure 199, Operator Qualification).
6. Documentation Local corrosion technicians/corrosion personnel will use Allegros to collect all bimonthly/monthly rectifier readings (unless the CP reading is obtained by a remote monitor that can electronically move the CP readings into the CPDM Program) (195.573 (c)) and bond readings (195.573 (c)) Local corrosion technicians will use Allegros to collect all cathodic protection data for annual surveys (195.573 (a) (1). Local corrosion technicians will use Allegros to collect all sacrificial anode readings. Allegros will be used to GPS (Longitude - Latitude) and date/time stamp all readings taken. Allegros are to be used to collect all CIS data. Allegros (will be used to record all analysis, checks, demonstrations, examinations, inspections, investigations, reviews, surveys, and test (195.589 (c)) for cathodic protection. All galvanic anodes (195.589 (a) (2)) locations installed after January 28, 2002 will be documented with Allegros. All structures bonded to cathodic protection systems (195.589 (3)) will be documented with Allegros. All cathodic protection data will be maintained in the American Innovations — Pipeline Compliance System - Cathodic Protection Data Management program (PCS- CPDM). Allegros will be uploaded into PCS-CPDM program monthly. The PCS-CPDM program will be synchronized with the administrative program monthly. The GIS-PODS Manager will access all cathodic protection data through the PCS-CPDM administrative program. Refer to L-O&M Procedure 1404, Maps and Records for corrosion record retention periods. In addition, a five (5) year history of all cathodic protection records is to be converted and reside in PCS- CPDM program by December 31, 2010 The records within the PCS-CPDM program will be updated annually to reflect the latest records plus the previous four annual surveys. NOTE: Effective December 31, 2010 all Terminal facilities are to be set up in the PCS-CPDM program. As annual cathodic protection, surveys are due for terminal facilities that do not currently exist in the PCS-CPDM program they are to be set up in the program and all readings obtained with an Allegro. NOTE: If a Pipeline is cathodically protected with Sacrificial Anodes only - As long as a Pipeline system is protected with Sacrificial Anodes only, it will only be required to synchronize annual survey information
6.1. External Corrosion CP Records Use the PCS-CPDM program as the primary external CP corrosion control record maintenance format. Refer to L-O&M Procedure 1404, Maps and Records for corrosion record retention periods. The PCS-CPDM program maintains all analysis, check, demonstration, examination, inspection, investigation, review, survey, and test (195.589 (c)). Corrosion data is required for inclusion in the IMP risk model and will be accessed by the GIS-PODS Manager in the PCS-CPDM administrative program.
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These include but are not limited to' a. Pipe-to-soil potential surveys (annual surveys, close interval surveys, DCVG, PCM or other similar type CP surveys) b. Casing potential readings and status - MShort (mechanically shorted), EShort (electrolytically short), Clear (no short) c. Foreign structure crossing potentials d. Smart test lead coupon potentials (Coupon Test Stations) e. Interference bond readings f. Insulating device effectiveness g. Galvanic anodes output and location h. Reverse current switches i. CPU annual output records j. CPU bi-monthly records k. CPU installation data I. Record the following data relative to CP corrosion control facilities maintenance: m Repairing rectifiers and other DC power sources n. Repairing or replacing anodes, connections and cable o. Repairing interference bonds p. Repairing drainage switches or equivalent devices q. Repairing insulating devices, test leads and other test facilities including why test stations are abandoned r. Document remedial action taken in reaction to a problem with a test or survey
6.2. External Corrosion Inspection Records and Forms Maintain records of all external corrosion inspections, including coating repairs, corrosion leaks, breaks and replacements, or excavations in the Region Gate Keepers office. Cathodic protection Records will only be maintained in the PCS-CPDM a. PCS-CPDM programs will be synchronized monthly with the administrative program. b. L-0M200-02, Pipeline Inspection/Repair Report c. Upon completion route copies to the Business Unit GIS Database Gatekeeper and others, as noted on the form. d. L-0M900-02, Interference Test Report or Interference Test Field Notes e. Upon completion route copies to the Business Unit GIS Database Gatekeeper and others, as noted on the form.
6.3. External Corrosion Facility Installation Records Record the following information relative to corrosion control facility design and installation. Maintain records, maps or drawings to show the location of cathodically protected piping and facilities, galvanic anodes and neighboring structures bonded to the cathodic protection system.
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6.3.1. Cathodic Protection Facilities Design a Results of soil resistivity surveys at groundbed locations (if applicable) b. Results of current requirement tests c. Cathodic protection design data d. Interference surveys and interference bond and drainage switch installation designs
6.3.2. Cathodic Protection Facilities Installation As-built sketches or drawings documenting the cathodic protection installation(s) for a. Impressed current systems i. Location and date placed in service ii. Type, depth, backfill and anode spacing iii Specifications of rectifier or other energy sources
b. Galvanic anode system i. Location and date placed in service ii. Type, depth, backfill and anode spacing
6.3.3. Interference Bonds and Drainage Switches Installation a Interference bonds and drainage switches i. Location and name of company involved ii. Resistance value or other pertinent information iii. Magnitude and polarity of drainage current
b. Drainage switch installation i. Location and name of companies involved ii. Type switch or equivalent device iii. Data showing operating effectiveness
c Other remedial measures
NOTE: All new installations, changes, repairs, upgrades, etc are to be entered into the PCS-CPDM program within 10 (ten) days of completing the project/job (unless the employee is on vacation or sick leave).
6.4. Cathodic Protection Surveys Maintain records of all Close Interval Surveys, DCVG, PCM or other similar type CP surveys performed by company or outside contractors in the PCS-CPDM program.
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6.5. Exposed Pipe Field Inspection Refer to L-O&M Procedure 268, Exposed Pipe Field Inspection.
7. References • 49 CFR Part 195.551, .553, .555, .557, .561, 563, .565, .567, 569, .571, .573, .575, 577, 579, 585, .587, and .589 • NEB OPR, Part 25 (3), 56 • CSA Z662-159,1.6 9.1.7 9.2 9.2.1 9.5 9.6 9.7 98 9.10.3 • NACE Standard Practices • National Electrical Manufacturers Association Standards • L-O&M Procedure 003, Procedure Review • L-O&M Procedure 155, Management of Change • L-O&M Procedure 199, Operator Qualification • L-O&M Procedure 203, Coating Pipelines • L-O&M Procedure 204, Construction Near Company Facilities • L-O&M Procedure 206, Land and Right-of-Way • L-O&M Procedure 215, Patrolling and Leak Detection • L-O&M Procedure 268, Exposed Pipe Field Inspection • L-O&M Procedure 275, Continuing Analysis to Identify Prevention and Mitigation Measures • L-O&M Procedure 276 Annual IMP Schedule • L-O&M Procedure 277, Review Risk Algorithm • L-O&M Procedure 1404, Maps and Records • L-O&M Procedure 1700, L-I&M I -1106,1-1107.00 • L-O&M Procedure 2101, Atmospheric Breakout Tank Inspection • L-0M200-02, Pipeline Inspection/Repair Report • L-0M900-01, Data Sheet for Testing Casings • L-0M900-02, Interference Test Report • L-0M900-16, Polarization Work Sheet • L-0M900-17, Shorted Casing Inspection Report • BASS-TRIGON CPDM Software Program • IMP Protocol 13 • IMP Protocol 14 • IMP Protocol 15 • IMP Protocol 16 • ANSI/API RP 651 • NACE SP0169-2007 • NACE SP0177 • NACE 35101 AC Corrosion State of the Art COR Rates-Mechinsam-Mitiqation
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000058 The INGAA Foundation, Inc.
Criteria for Pipelines Co-Existing with Electric Power Lines
Prepared For: The 1NGAA Foundation
Prepared By: DNV GL
October 2015
The 1NGAA Foundation FINAL Report No. 2015-04
1 000059 Report name: Criteria for Pipelines Co-Existing with Det Norske Veritas (U.S.A.), Inc. Oil & Gas Electric Power Lines Computational Modeling Customer: The INGAA Foundation, Inc. 5777 Frantz Road Contact person: Richard Hoffmann 43017-1386 Dublin Date of issue: October 5, 2015 OH Project No.: PP105012 United States Organization unit: OAPUS310 / OAPUS312 Tel: +1 614 761 1214 Report No.: 2015-04, Rev. 0 Document No.: 1E02G9N-4
Objective:
The primary objective of this report is to present the technical background, and provide best practice guidelines and summary criteria for pipelines collocated with high voltage AC power lines. The report addresses interference effects with respect to corrosion and safety hazards, and fault threats.
Prepared by: Verified by: Approved by:
Shane Finneran Barry Krebs Lynsay Bensman Senior Engineer Principal Engineer Flead of Section, Materials Advisory Service
Draft 2015-06-18 First Issue SF BK LB 0 2015-10-05 Final Issue SF BK LB
2 000060 EXECUTIVE SUMMARY
The primary objective of this report is to present the technical background, and provide best practice guidelines and summary criteria for pipelines collocated with high voltage AC power lines. The report addresses interference effects with respect to corrosion and safety hazards, and fault threats. The guidelines presented address mitigation and monitoring, encroachment and construction, risk severity classification, and recommendations for further industry development.
This report addresses the technical background to high voltage interference with respect to collocated and crossing pipelines, and presents basic procedures for dealing with interference scenarios. The provisions of this document are recommended to be used under the direction of competent persons, who are qualified in the practice of corrosion control on metallic structures, with specific suitable experience related to AC and/or DC interference and mitigation. This document is intended for use in conjunction with the reference materials cited herein.
Collocated pipelines, sharing, paralleling, or crossing high voltage power line rights-of-way (ROW), may be subject to electrical interference from electrostatic coupling, electromagnetic inductive, and conductive effects. If the interference effects are high enough, they may pose a safety hazard to personnel or the public, or may compromise the integrity of the pipeline. Because of increased opposition to pipeline and power line siting, many future projects propose collocating high voltage alternating current (HVAC) and high voltage direct current (HVDC) power lines and pipelines in shared corridors, worsening the threat.
Predicting HVAC interference on pipelines is a complex problem, with multiple interacting variables affecting the influence and consequences. In some cases, detailed modeling and field monitoring is used to estimate a collocated pipeline's susceptibility to HVAC interference, identify locations of possible AC current discharge, and design appropriate mitigation systems to reduce the effects of AC interference. This detailed computer modeling generally requires extensive data collection, field work, and subject-matter expertise. Basic industry guidelines are needed to help determine when more detailed analysis is warranted, or when detailed analysis can be ruled out based on the known collocation and loading parameters. A consistent technical guidance document will benefit the pipeline industry by increasing public safety and allowing for an efficient approach in assessment and mitigation of threats related to high voltage interference.
The INGAA Foundation contracted Det Norske Veritas (U.S.A), Inc. (DNV GL) to develop this guidance document. The project included a detailed industry literature review to identify applicable technical reports, international standards, existing guidance and operator procedures. In addition to the literature review, numerical modeling was performed to determine the effects of key parameters on the interference levels. The document addresses interference effects with respect to corrosion and safety hazards, mitigation, monitoring, encroachment and construction, prioritization and modeling. It also includes recommendations for further development.
The following severity ranking tables were developed for key variables and their impact on the severity of AC interference. Further background for the development of these rankings is provided throughout the report. Guidelines for determining the need for detailed analysis and applying these severity rankings are provided in Section 6.2.
3 000061 Separation Distance
Table 3-Severity Ranking of Separation Distance
Separation Distance - D (Feet) Severity Ranking of HVAC Interference D< 100 High 100 HVAC Power Line Current Table 4-Relative Ranking of HVAC Phase Current HVAC Current - I (amps) Relative Severity of HVAC Interference I> 1,000 Very High 500< I> 1,000 High 250 < I< 500 Med-High 100< I< 250 Medium I< 100 Low Soil Resistivity Table 5-Relative Ranking of Soil Resistivity Soil Resistivity - p (ohm-cm) Relative Severìty ofHVAC Corrosion p < 2,500 Very High 2,500 Collocation Length Table 6-Relative Ranking of Collocation Length Collocation Length: L (feet) Relative Severity L> 5,000 High 1,000 < L< 5,000 Medium L< 1,000 Low Collocation / Crossing Angle Table 7-Relative Ranking of Crossing Angle Collocation/Crossing Angle - 8 (Õ) Relative Severity 0 < 30 High 30<0<60 Med 0 > 60 Low 4 000062 The research and analytical studies accentuated the need for accurate power line current load data when assessing the susceptibility of a steel transmission line to high voltage interference. For this reason, collaboration between the respective pipeline and power line operators is advised to accurately determine where detailed assessment is required, and develop efficient mitigation where necessary. The general safety recommendations and guidelines for interference analysis presented in Section 6 provide guidance on the relative susceptibility of AC interference associated with the selected variables. They primarily address the likelihood or susceptibility of AC interference, and do not address the consequence aspect of an overall risk assessment, as these details are specific to each individual assessment. 5 000063 Table of Contents EXECUTIVE SUMMARY 3 ACRONYMS 7 1 INTRODUCTION 9 2 INDUSTRY LITERATURE REVIEW 9 3 HIGH VOLTAGE INTERFERENCE ON ADJACENT PIPELINES 10 3.1 HVAC Interference Modes 10 3.1.1 Capacitive Coupling 10 3.1.2 Inductive Coupling 11 3.1.3 Resistive Coupling 13 3.1.4 AC Faults 14 3.2 HVAC - Personnel Safety Hazards 14 3.2.1 Hazards During Operation 14 3.2.2 Encroachment and Construction Hazards 15 3.3 HVAC Threat to Pipeline Integrity 16 3.3.1 AC Corrosion 16 3.3.2 Faults 19 3.4 Underground HVAC / HVDC 20 3.5 Industry Procedure Summary 23 4 NUMERICAL MODELING 24 4.1 Modeling Software 24 4.2 Variable Analyses 25 4.2.1 HVAC Power Line Current 26 4.2.2 Soil Resistivity 28 4.2.3 Collocation Geometry 31 4.2.4 Coating Resistance 35 4.2.5 Pipeline Diameter and Depth of Cover 36 5 MITIGATION 37 5.1.1 DC Decouplers 38 5.2 Surface Grounding 38 5.3 Deep Grounding 40 5.4 Mitigation Comparison 41 5.5 Additional Mitigation Methodologies 42 5.5.1 Primary Threat Control of AC Interference 42 5.5.2 Secondary Threat Control of AC Interference 43 5.5.3 Tertiary Threat Control of AC Interference 44 5.6 MONITORING 45 6 GUIDELINES FOR INTERFERENCE ANALYSIS 45 6.1 Severity Ranking Guidelines 46 6.1.1 Separation Distance 46 6.1.2 HVAC Power Line Current 46 6.1.3 Soil Resistivity 47 6.1.4 Collocation Length 48 6.1.5 Collocation / Crossing Angle 48 6 000064 6.2 Recommendations for Detailed Analysis 48 6.2.1 Case 1 49 6.2.2 Case 2 49 6.2.3 Faults 49 6.2.4 Fault Arcing Distance 50 6.3 Data and Documentation Requirements 50 6.4 General Recommendations 51 7 REFERENCES 53 APPENDIX A LITERATURE REVIEW 55 Case Studies 56 International Standards 57 APPENDIX B COATING RESISTANCE ESTIMATES 60 APPENDIX C MITIGATION COMPARISON SUMMARY 62 APPENDIX D DATA REQUEST TEMPLATE 64 7 000065 Acronyms AC Alternating Current CAPP Canadian Association of Petroleum Producers CFR Code of Federal Regulation CP Cathodic Protection CSA Canadian Standards Association CTS Coupon Test Station DC Direct Current DCD DC Decoupler DOC Depth of Cover DOT Department of Transportation EMI Electromagnetic Interference ER Electrical Resistance FBE Fusion Bonded Epoxy GPR Ground Potential Rise HVAC High Voltage Alternating Current HVDC High Voltage Direct Current IEEE Institute of Electrical and Electronics Engineers IF Isolation Flange INGAA Interstate Natural Gas Association of America LEF Longitudinal Electric Field MPY Mils per year OSHA Occupational Safety and Health Administration PRCI Pipeline Research Council International ROW Right(s) of Way TLM Transmission Line Model 8 000066 1 INTRODUCTION Trends within both the electric power and pipeline industries have increased the number of projects that co- locate high voltage alternating current (HVAC) and high voltage direct current (HVDC) power lines with steel transmission pipelines in shared rights-of-way (ROW). The primary objective of this report is to provide technical guidance and present best practice guidelines and summary criteria for steel transmission pipelines collocated with high voltage AC power lines. Topography, permitting requirements, land access, increasingly vocal public opposition to infrastructure projects, and environmental concerns, including protected regions, all have led to an increase in sharing of common utility corridors. While there are numerous benefits to common utility corridors, there are also many concerns. Collocated steel transmission pipelines that share, parallel, or cross high voltage power line ROW may be subject to electrical interference from electrostatic coupling, electromagnetic inductive, and conductive effects. If these interference effects are high enough, they may pose a safety hazard to personnel or compromise the integrity of the pipeline. Pipelines collocated with overhead HVAC lines account for a significant portion of the high voltage interference conditions encountered in the transmission pipeline industry. However, interference effects due to buried power lines and HVDC are also of concern to pipeline operators where close collocations exist. As aboveground HVAC is still the primary concern for pipeline interference, it is the primary focus of this report. However, comparison background and technical discussion is included related to HVDC and buried power line interference as well, and the effects of both should be considered on a case-by-case basis when steel transmission pipelines are closely collocated with these systems. Numerous methodologies exist to analyze alternating current (AC) interference for specific collocations and crossings, but the analysis generally requires extensive data collection and detailed computational modeling. The accuracy of these models is sensitive to the HVAC power line operating parameters, which can often be difficult or costly for pipeline operators to obtain from electric power companies. Basic guidelines and prioritization criteria have been established in this report to provide guidance for pipeline operators to aid in a risk-based decision-making process and help prioritize regions for detailed modeling and mitigation design, or exclude further modeling analysis for a given region. This report addresses interference effects related to encroachment and construction, corrosion and safety hazards, mitigation, and monitoring. This project included a detailed industry literature review to identify applicable technical reports, international standards and, guidance documents. Several INGAA members provided procedures. In addition to the literature review, numerical models were developed and trends presented detailing the effects of critical variables on interference levels under the conditions defined. 2 INDUSTRY LITERATURE REVIEW There has been extensive research performed to understand the risks of high voltage interference and to develop efficient mitigation techniques. The effects of HVAC interference from a personnel safety and corrosion standpoint are a risk identified in much of the literature. Case studies in North America, the UK, and continental Europe have identified and documented AC corrosion concerns. Through-wall defects have been reported with corrosion rates greater than 50 mils/year (mpy) observed.1 9 000067 In development of this guidance document a literature review identified and reviewed more than fifty technical references, US and International standards, existing guidance documents, research theses, journal manuscripts, and technical symposia papers. Additionally, INGAA collected operating procedures and guidelines from 10 member companies for review and comparison. Where published, historically identified corrosion defects and pipeline failures associated with AC corrosion degradation have been reviewed and a selection are presented as case studies in Appendix A, demonstrating the magnitudes and variability in corrosion rates possible with AC accelerated corrosion. The primary finding from this review is that there is significant variation in operating procedures and technical literature with respect to AC interference. Various companies procedures were compared with published industry guidance, historical project data, and project experience to determine a best practice approach. Details and cross references are presented in each of the subsections of this document with a detailed review of the technical literature, case studies, and company procedures provided in Appendix A. 3 HIGH VOLTAGE INTERFERENCE ON ADJACENT PIPELINES 3.1. HVAC Interference Modes Electrical interference from capacitive, electromagnetic inductive, and conductive coupling can affect pipelines collocated in close proximity to HVAC power lines. The subject of AC interference has been a growing concern across multiple industries in recent decades as improved pipeline coatings and utility ROW congestion has contributed to an increase in identified AC corrosion incidents. Recent trends in the high voltage electric power transmission industry are leading to increased power capacity and higher operating currents in certain systems, in part to overcome long distance transmission line losses.2 This increase in operating current has a direct effect on the level of electromagnetic interference (EMI) and the corresponding magnitude of AC interference on affected pipelines. This trend toward elevated operating currents may present a significant challenge for achieving adequate mitigation on pipelines crossing or collocated with the high voltage power lines. The three primary physical phenomena by which AC can interfere or "couple" with pipelines are through capacitive, resistive, or inductive coupling as detailed in Sections 3.1.1 through 3.1.3. High voltage interference can occur during normal operation, generally referred to as steady state, or during a power line fault. HVAC power line faults are any abnormal current flow from the standard intended operating conditions, and discussed further in Section 3.1.4. 3.1.1 Capacitive Coupling Capacitive coupling, or electrostatic interference, occurs due to the electromagnetic field produced by AC current flowing in the conductors of a high voltage power line, which can induce a charge on an above ground steel pipeline that is electrically isolated from the ground. Capacitive effects are primarily a concern during construction when sections of the pipeline are aboveground on insulating supports, as indicated in Figure 1. The pipeline can build up charge as a capacitor with the surrounding air acting as the dielectric, which can maintain the electric field with a minimum loss in power, resulting in a potential difference with surrounding earth. The magnitude of potential is primarily dependent on the pipeline proximity to the HVAC conductors, the magnitude of power line current, and the individual phase arrangement. If the potential buildup due to 10 000068 capacitive coupling is significant, electrostatic interference may present a risk of electric shock or arcing. While elevated capacitive voltages may exist, the corresponding current is generally low, resulting in low shocking consequence34. Above Ground Pipeline Figure 1. Illustration of Capacitive Coupling 3.1.2 Inductive Coupling Electromagnetic induction is the primary interference effect of an HVAC power line on a buried steel pipeline during normal steady state operation. EMI occurs when AC flowing along power line conductors generates an electromagnetic field around the conductor, which can couple with adjacent buried pipelines, inducing an AC voltage, and corresponding current, on the structure as depicted in Figure 2. This induced AC potential may present a safety hazard to personnel, and can contribute to AC corrosion of the pipeline, as discussed in Section 3.3.1. 11 000069 •••••.„. Electromagnetic Induction Pipelines Figure 2. Illustration of Steady State HVAC Inductive Interference The inductive effects of the HVAC power line on an adjacent pipeline are a function of geometry, soil resistivity, coating resistance, and the power line operating parameters. The geometry characteristics include separation distance between the pipeline and the towers, depth of cover (DOC), pipe diameter, angle between pipeline and power line, tower footing design, and phase conductor configuration. These parameters remain relatively constant over the life of the installation. The coating resistance, power system resistance, and soil resistivity may vary with the seasonal changes and as the installations age, but they are considered constants for most analyses. However, the operating parameters of the power line - such as phase conductor load, phase balance, voltage, and available fault current - all have an influence on the effects of AC interference, and can vary significantly. The individual conductor current load and phase balance is dynamic and changes with load requirements and switching surges. These variations in operating parameters contribute to variations in levels of AC interference. During normal HVAC operation, the current load varies as the load demand changes both daily and seasonally.35 While normal operating conditions are often referred to as "steady state" throughout the industry, the term is somewhat misleading as the current loads and corresponding induced AC potentials can be continuously varying, adding further complexity to quantifying interference magnitude. For a straight, parallel, homogenous collocation, induced potentials are highest at the ends of the collocated segment, and fall exponentially with distance past the point of divergence.6 For more complex collocations, voltage peaks may occur at geometric or electrical discontinuities, where there is an abrupt change in the collocation geometry or electromagnetic field. Specifically, voltage peaks commonly occur where the pipeline converges or diverges with the HVAC power line, separation distance or soil resistivity changes significantly, isolation joints are present on the pipeline, or where the electromagnetic field varies such as at phase transpositions.3'7" 12 000070 3.1.3 Resistive Coupling Current traveling through the soil to a pipeline can cause resistive or conductive coupling. As the grounded tower of an HVAC power system shares an electrolytic path with adjacent buried pipelines through the soil, fault currents may transfer to adjacent steel pipelines if the pipeline presents a lower resistance electrical path. Resistive interference is primarily a concern when a phase-to-ground fault occurs in an area where a pipeline is in close proximity to an HVAC power line, and magnitudes of fault currents in the ground are high. However, a phase imbalance on an HVAC system with a grounded neutral can contribute to resistive interference as return currents will travel through the ground and may transfer to a nearby pipeline. During a fault condition (see Section 3.1.4), the primary concern is the resistive interference transferred through the soil. However, inductive interference can also be a concern as the phase current, and corresponding EMI, of at least one conductor can be high, as depicted in Figure 3. In other words, during a fault, the inductive effects during normal operation as described in Section 3.1.2 increase due the elevated EMI during the fault period. """••••..„ 47 Conducto Fault Fau It Cu rrents Conductive Sufi Pipelines Figure 3. Illustration of HVAC Fault Condition — Inductive and Conductive Interference If any of these electrical effects are high enough during operation, a possible shock hazard exists for anyone that touches an exposed part of the pipeline such as a valve, cathodic protection (CP) test station, or other aboveground appurtenance. During steady state normal power line operation, AC current density at a coating holiday (flaw) above a certain threshold may cause accelerated external corrosion damage to the pipeline. In addition, damage to the pipeline or its coating can occur if the voltage between the pipeline and surrounding soil becomes excessive during a fault condition. 1.3 000071 3.1.4 AC Faults For HVAC power lines, a fault is any abnormal current flow from the standard intended operating conditions. A fault can occur between one or more phase wires and the ground, or simply between adjacent phase wires. Faults can occur when one or more of the conductors are grounded or come in contact with each other, or due to other unforeseen events. This may be due to vegetation contacting the conductors, conductors contacting the towers or each other during high winds, physical damage to a tower, conductor, or insulator, flashover due to lightning strikes, or other abnormal operating condition. A phase-to-ground fault on a power line causes large currents in the soil at the location of the fault and large return currents on the phase conductor and ground return. Faults are generally short duration transient events. Typical clearing times for faults range from approximately 5 to 60 cycles (0.08 to 1.0 seconds for 60-hertz transmission) depending on the location of the fault, breakers and type of communications. While the fault effects are transient, high-induced potentials or resistive coupled voltages along the ROW present a possible shocking hazard for personnel or anyone who may be in contact with above grade pipeline or appurtenances. 3.2 HVAC - Personnel Safety Hazards An evaluation of the possible safety hazards for those working on a pipeline should take place whenever a pipeline is operating or constructed in close proximity to a HVAC power line. Personnel safety hazards are present during both pipeline construction and maintenance, and during normal steady state operation. 3.2.1 Hazards During Operation Touch and Step Potential Limits Personnel safety is of concern when a person is touching or standing near a pipeline when high voltages are present. The "touch potential" is defined as the voltage between an exposed feature of the pipeline, such as a CP test station or valve, and the surrounding soil or a nearby isolated metal object, such as a fence that can be touched at the same time. The touch potential is the voltage a person may be exposed to when contacting a pipe or electricaHy continuous appurtenance. The "step potential" is the voltage across a person's two feet and defined as the difference in the earth's surface potential between two spots one meter apart. The touch potential can be a concern during both normal steady state inductive and fault conductive/inductive conditions. Typically, the step potential is a concern during conductive fault conditions due to high currents and voltage gradients in the soil. The Canadian Standards Association (CSA) and NACE International (NACE) have published standards addressing HVAC interference hazards. Both NACE and CSA standards10'12 recommend reducing the steady state touch and step potential below 15 volts at any location where a person could contact the pipeline or any electrically continuous appurtenance. The 15-volt threshold is designed to limit the available maximum current through a typical human body to less than 10 mA. An 8 to 15 mA current results in a painful shock but is still in the maximum "let go" current range, for which a person can release an object or withdraw from contact." The Institute of Electrical and Electronics Engineers (IEEE) Guide for Safety in AC Substation Grounding, indicates that a current in the range of 9 to 25 mA range may produce painful shock and involuntary muscular contraction, making it difficult to release an energized object." Elevated body current in the range of 60 to 100 mA may cause severe injury or death as it can induce ventricular fibrillation, or 14 000072 inhibition of respiration. Current lower than nine (9) mA will generally result in a mild shock, but involuntary movement could still cause an accident.1° The touch potential is equal to the difference in voltage between an object and a contact point some distance away, and may be nearly the full voltage across the grounded object if that object is grounded at a point remote from where the person is in contact with it. For example, a crane that was grounded to the system neutral and that contacted an energized line would expose any person in contact with the crane or its un-insulated load line to a touch potential nearly equal to the full fault voltage. The step potential may pose a risk during a fault simply by standing near the grounding point due to large potential gradients present in the soil, typically during a short duration fault condition. A risk evaluation of the possible hazards to personnel for those working on the pipeline and possible pipeline coating damage should take place whenever a pipeline is in close proximity to a HVAC power line. This assessment should consider the possible likelihood and consequence of HVAC interference hazards to determine if further analytical assessment or mitigation is necessary. NACE International Standard Practice SP0177-2014 (Mitigation of Alternating Current and Lightning Effects on Metallic Structures and Corrosion Control Systems) indicates mitigation is necessary in those cases where step or touch potentials are in excess of 15 volts. Mitigation is further discussed in Section 5. 3.2.2 Encroachment and Construction Hazards There are multiple safety hazards to consider associated with pipeline construction near a high voltage power line, the most obvious of which is the possibly lethal hazard of equipment directly contacting an energized overhead conductor.3 The Occupational Safety and Health Administration (OSHA) has multiple regulations for safety requirements and limitations for working near power lines that must be considered in addition to pertinent company standards, and industry best practice guidelines. These include, but are not limited to the following: • 29 CFR 1910.269: Electric power generation, transmission, and distribution • 29 CFR 1910.333: Selection and use of work practices • 29 CFR 1926, SUBPART V: Power Transmission and Distribution The OSHA standards address requirements for working near energized equipment, overhead power lines, underground power lines, and construction nearby. Elevated capacitive potentials generated on pipeline sections isolated from the ground on insulating skids as described in Section 3.1.1 can pose a safety hazard. Pipeline segments that are supported aboveground during pipeline construction near an HVAC power line are subject to EMI and electrical capacitance can build up between the pipeline segments and earth. If no electrical path to ground is present, even a relatively short section of piping may experience elevated AC potential, presenting a shock hazard to personnel near the pipeline. Cases presented in published literature indicate scenarios of measured potentials greater than 1,000 volts on a pipeline segment exposed to an HVAC corridor.4 In general, while the capacitive coupled voltages can exceed the NACE 15 volt touch potential safety threshold, the corresponding current is low reducing shocking hazard. However, arcing due to capacitive coupling may present a possible safety hazard, as an arc may be a possible ignition source for construction vehicles refueling along the ROW. Grounding pipelines in HVAC ROW will reduce the possibility of shocking or arcing. 15 000073 Capacitive coupling is generally mitigated by connecting temporary grounding or bonding during construction to provide a low resistance path to ground for any electrostatic interference. Section 6 addresses further mitigation techniques and guidance for construction practices. 3.3 HVAC Threat to Pipeline Integrity High voltage interference poses multiple threats to pipeline integrity for collocated and crossing pipelines under both steady state and fault conditions. During normal steady state HVAC power line operation, the inductive interference can contribute to accelerated external corrosion damage to the pipeline. Under faulted conditions, elevated potentials can lead to coating damage or a direct arcing to the pipeline. The steady state 15 VAC threshold presented in NACE and CSA standardsl°,12 considers personnel safety and does not necessarily address corrosion issues. Research and experience has shown that AC accelerated corrosion can occur in low resistivity soils at AC voltages well below this threshold.3,6,14 3.3.1 AC Corrosion External corrosion, whether controlled by AC or DC, may pose a threat to the integrity of an operating pipeline. DC corrosion protection utilizes a system of corrosion resistant coatings and a CP system to provide electrochemical protection at coating holidays to reduce corrosion rate. However, AC corrosion is possible even in the presence of cathodically protected DC potentials due to high AC current density at coating holidays. The concept of AC corrosion has been around since the early 1900s with only minor effects expected for many years.3'" AC accelerated corrosion has been recognized as a legitimate threat for collocated steel since the early 1990s, after several occurrences of accelerated pitting and leaks, ultimately associated with HVAC interference, were reported on cathodically protected pipelines. Historically, there has been little consensus on specific mechanisms driving AC corrosion, and the severity of degradation attributed. However, several recent publications show tentative agreement in a plausible mechanism.6•15•17 The explanation presented by Buchler, Tribollet, et al, suggests that AC corrosion on cathodically protected pipelines may be attributed to destabilization of pseudo-passive film that can normally form on exposed steel at a coating holiday under DC cathodic protection polarization. Due to the cyclic nature of AC current, the charge at the steel surface is continuously varying between anodic and cathodic polarization, which acts to reduce the passive film at the steel surface as shown in Figure 4. It is not the intention of this report to identify the specific mechanism driving material degradation due to AC corrosion, but rather to summarize a previously proposed mechanism and clarify the risks and contributing factors associated with AC corrosion. 16 000074 + A. vc,„\ \ '1\,\\'\\ Steel 1 Passive Film Corrosion Product Figure 4. Graphical representation of proposed processes occurring during AC corrosion. Reproduced from Tribollet.6 3.3.1.1. AC Current Density While there may be disagreement regarding the specific mechanism driving AC corrosion, AC current density is generally recognized as being an indicator of the likelihood of AC corrosion for a given location. In January of 2010, NACE International prepared and published a report entitled "AC Corrosion State-of-the-Art: Corrosion Rate, Mechanism, and Mitigation Requirements," which provides the following insight on AC corrosion current density. "In 1986, a corrosion failure on a high-pressure gas pipeline in Germany was attributed to AC corrosion. This failure initiated field and laboratory investigations that indicated induced AC- enhanced corrosion can occur on coated steel pipelines, even when protection criteria are met. In addition, the investigations ascertained that above a minimum AC density, typically accepted levels of CP would not control AC-enhanced corrosion. The German AC corrosion investigators conclusions can be summarized as follows: • AC-induced corrosion does not occur at AC densities less than 20 A/m2 (1.9 A/ft2). • AC corrosion is unpredictable for AC densities between 20 to 100 A/m2 (1.9 to 9.3 A/ft2). • AC corrosion occurs at current densities greater than 100 A/m2 (9.3 A/ft2)."31 The AC density for a given location is dependent on soil resistivity, induced voltage, and the size of a coating holiday. Research has indicated that the highest corrosion rates occur at holidays with surface areas of 1 to 3 cm2 (0.16 to 0.47 in2).1 AC current density is best obtained through direct measurement of a correctly sized coupon or probe. However, the theoretical AC current density can be calculated, utilizing the soil 17 000075 resistivity and AC potential on a pipeline, in conjunction with Equation 1, presented in the State of the Art Report.1 8VAc lAc = pIrd Equation (1) Where: IAC = Theoretical AC Current Density (A/m2) vac = Pipe AC Voltage to Remote Earth (V) = Soil Resistivity (ohm-m) (1 ohm-m = 100 ohm-cm) Diameter of a circular holiday having an area equal to that of the actual holiday (m) Multiple industry references discuss a current density threshold below which AC corrosion is not a significant factor; however, there is still disagreement on the magnitude of this threshold. While the majority of technical literature indicates AC corrosion is possible at current densities between 20 to 30 A/m2, there is experimental evidence presented by Goidanich, et al14 indicating that AC current densities as low as 10 A/m2 can contribute to a measureable increase in corrosion rate14. A significant conclusion of study published by Yunovich and Thompson in 20049, reiterated in the NACE AC Corrosion State of the Art Report in 2010, indicated that there might not be a theoretical threshold below which AC corrosion is active. The focus should rather be on a practical limit, below which the contribution of AC interference to the overall corrosion rate is low, or rate of corrosion due to AC is not appreciably greater than the free corrosion rate for the particular conditions.3'9 The results of the experimental study showed that a current density of approximately 20 A/m2 produced a 90% or greater increase in the corrosion rate versus the control, in the absence of CP.9 Experimental studies performed by Goidanich, Lazzari, et al in 2010 and 2014, in the presence of CP, concluded that while it was apparent AC current density greater than 30 A/m2 showed a considerable increase in the corrosion rate, a current density as low as 10 A/m2 resulted in a corrosion rate nearly double that of the specimens without AC.14 18 For reference, the European Standard EN 15280:2013, "Evaluation of AC corrosion Likelihood of Buried Pipelines Applicable to Cathodically Protected Pipelines" adopted the 30 A/m2 current density magnitude as a lower threshold, below which the likelihood of AC corrosion likelihood is low. In an effort to address the practical application seen in operation, considering interaction effects of CP current and AC interference, recent research has assessed the likelihood of AC corrosion in terms of the ratio between AC and DC current density (lAdiod• 3.3.1.2 Current Density Ratio Recent research has shown that the likelihood of AC corrosion on pipelines is dependent on both the level of AC interference and the level of cathodic current from either CP or other stray current sources.3' 18, 18 In general, AC current density values below the previously cited 20 A/m2 recommended limits were shown to accelerate corrosion rates in the presence of elevated DC current density due to excessive CP overprotection. The latest revision of EN 15280:2013 was revised to present criteria based upon the AC interference and DC current due to CP. Alternative acceptance criteria are presented in terms of limiting cathodic current density, or limiting the AC to DC current density ratio (IfdIDC) below a specified level. 18 000076 Current density obtained by use of coupons or electrical resistance (ER) probes will provide this ratio. However, both AC and DC current density data required to utilize these limits are often not available or easily obtained along the pipeline in practice. Therefore, the current density ratio limits provided within the EN 15280 standard are not widely used or easily applicable criteria. This reference demonstrates the recognized interaction of AC interference and CP systems, presenting an alternative approach that may be valuable for specific scenarios where data is available. As mentioned previously, the measurement or calculation of AC current density has been the primary indicator to determine the likelihood of AC corrosion across industry in North America. It is possible to measure AC current density on a representative holiday through the installation and use of metallic coupons. A coupon representative of the pipe material, with a defined bare surface area, buried near the pipeline and connected to the pipeline routed through a test station will allow the measurement of current. These current measurements along with the known surface area of the coupon, allow for calculation of a representative current density. In many cases, the coupons are supplemented with additional instrumentation such as ER probes and reference electrodes to provide additional pertinent information. The ER probes provide a time based corrosion rate while the reference electrodes provide both and AC and DC pipe-to-soil potentials. Section 6 provides further details related to mitigation and monitoring methods for to AC corrosion. Appendix A includes additional details related to literature review, historical AC corrosion rates, and industry case studies. 3.3.2 Faults During a phase-to-ground fault on a power line, an adjacent or crossing pipeline may be subject to both resistive and inductive interference. Although these faults are normally of short duration (generally less than one second), pipeline damage can occur from high potential breakdown of the coating and conductive arcing across the coating near the fault. Further, the fault current is typically carried by a single conductor, resulting in short term elevated induced voltages that can reach thousands of volts or greater. This presents a significant risk to personnel in contact with the pipeline or electrically continuous appurtenance during a fault. A phase-to-ground fault, or a lightning strike, on an HVAC power line can result in large potential differences with respect to the adjacent or crossing pipelines. If the potential gradient through the soil is sufficient, a direct arc to a collocated or crossing pipeline is possible, which can result in coating damage, or arc damage to the pipe wall up to the point of burn-through. Even if an arc is not sustained long enough to cause burn through, a short duration elevated current can cause molten pits on the pipe surface that may lead to crack development as the pipe cools. Fault arcing is generally a concern where fault potentials are greater than the dielectric strength of the coating, or at coating holidays within the possible arcing distance. Section 7.3 provides guidance limits for both issues. Where necessary, installation of grounding and shield wires can be used to mitigate the fault hazards as discussed in Section 6. 3.3.2.1. Coating Stress Voltage During fault conditions, damage to the pipeline or its coating can occur if the voltage between the pipeline and surrounding soil becomes excessive. Fault conditions that produce excess coating stress voltages across the coating are of concern for dielectric coatings. The main factors to consider are the magnitude of the voltage gradient and the dielectric strength of the coating type. It should be noted that there are several 19 000077 parameters that are utilized to assess these issues: magnitude of the fault current, distance between the pipeline and fault, soil resistivity, coating age/quality, duration of the fault and coating thickness. Guidance on allowable coating stress voltage varies across references. NACE SP0177-2014 indicates, "Limiting the coating stress voltage should be a mitigation objective." Multiple references offer varying coating stress limits and are generally considered to be in the range of 1 to 1.2 kV for bitumen, as low as 3 kV for coal tar and asphalt, and 3 to 5 kV for fusion-bonded epoxy (FBE) and polyethylene, for a short- duration fault."19 For reference, NACE SP0490-2007 "Holiday Detection of Fusion-Bonded Epoxy External Pipeline Coating of 250 to 760 pm (10 to 30 mil)" uses an equation for calculating test voltages which recommends a 15 mil (14 to 16 mils is a common specification for FBE coatings) fusion bonded coating (FBE) be tested at 2,050 volts. NACE SP0188 2006 "Discontinuity (Holiday) Testing of New Protective Coatings" also uses an equation for calculating test voltages for coatings in general. TV=1,250 41- Equation (2) Where: TV = Test Voltage (V) T = Average coating thickness in mils This results in a test voltage of 8,840 volts +/- 20% for a pipeline coated with a 50-mil coal tar coating. The first standard above is the subject of AC mitigation and the following two standards are the recommendations for holiday testing; however, there appear to be inconsistences as to what voltage will actually damage the various pipeline coatings. The inconsistences appear to be due to the unidentified coating thickness in SP0177-2014 and actual duration of the fault resulting in conservative values. Gummow et al. in their paper "Pipeline AC Mitigation Misconceptions"19 present data that include the duration and coating thickness in the analysis resulting in values that are more practical. They conclude that FBE coatings with a 16 mil thickness should conservatively use a voltage gradient limit of 5,000 volts and that the 3ky to 5 kV range indicated in NACE SP0177-2014 would be more applicable in the range of 7.5 kV to 12.5 kV. 3.4 HVDC / Underground HVAC High voltage power interference is primarily a concern for pipelines collocated with HVAC overhead power lines, due to the widespread sharing of common ROW, and the interference effects associated. However, there are associated concerns across industry regarding interference effects of aboveground HVDC transmission and underground AC power lines. Presently, the U.S. transmission grid consists of approximately 200,000 miles of 230 kV or greater high voltage transmission lines, with an estimate that underground transmission lines account for less than 1% of this total.2° Industry trends indicate that due to significant disparity in overall installation costs, it is expected that while buried transmission lines will continue to be developed and implemented, overhead transmission will remain the primary means for electric transmission for the foreseeable future.2 20 000078 In general, the level of interference from buried HVAC power lines is typically lower as the proximity between the individual phase conductors acts to balance electromagnetic fields, reducing EMI on foreign structures. Depending on the type of construction, sheathing or conduit may offer some level of electromagnetic shielding, further reducing inductive interference effects. As aboveground HVAC is still the primary concern for pipeline interference, it is the primary focus of this report. However, the effects of both aboveground HVDC and buried transmission cables require review on a case-by-case basis when pipelines are closely collocated. There are currently less than 30 identified high voltage direct current (HVDC) transmission lines operating in the United States21. Although there are few relative to overhead HVAC, and the interference effects on a pipeline are different from HVAC transmission lines, they do warrant a brief discussion so that pipeline operators are aware of potential issues. The Canadian Association of Petroleum Producers (CAPP)22 have produced a technical document that addresses in detail the issues associated with HVDC transmission lines influence on metallic pipelines. Due to the technical differences, the detailed extent of HVDC transmission line interference on steel pipelines necessitates its own study, beyond the scope of this document, however a summary overview of design and interference comparisons follows. HVDC transmission systems in operation today are typically of monopole or bipole design. In each case, the systems consist of a transmission line between stations with the major components being DC-AC convertors and large ground electrodes. In monopole systems, a single conductor transports the power with an earth return, as depicted in Figure 5. It should be noted that where HVDC systems use a ground return, the interference concerns are similar to typical DC stray current interference, which is addressed in NACE SP0169 and is outside the scope of this document. 1 Line 1 AC - 1G - AC L —is —G I Line 1 = IG Figure 5. Monopole System (34) In bipole systems, two conductors between stations allow the system to transport power through both conductors, one conductor and an earth return, or a combination of both, as depicted in Figure 6. The most common use of monopole systems is in submarine applications using the seawater as the earth return. The most common use of bipole systems consist of onshore overhead transmission towers to transport the power. 21 000079 I Line 1 AC AC 1 1.3ne 2 IG = 1 Line 1 - I Line 2 Figure 6. Bipole System (34) Tripole configurations have been considered and reviewed in research, but have not seen widespread use in practice. There are several types of designs and operation modes within the broad parameters of the monopole and bipole systems. During emergencies and in maintenance of the bipole system, an earth return is used. In an earth return mode there is a potential gradient generated and metallic objects, such as pipelines, can be subject to varying potentials and become a conductor of the return current if they provide a low resistance path. Where current is collected or received by the pipeline generally no damage occurs, unless the current is high enough to damage the coating. However, corrosion will occur at current discharge locations. The amount of corrosion is dependent on the amount of current and duration of discharge. In the case of large discharge current, significant corrosion damage can occur in relatively short time periods. The effects are similar to the interference currents caused by other DC power sources such as traction systems, cathodic protection systems or welding with an improper ground. HVDC transmission lines also have the same coupling modes with pipelines that occur with HVAC transmission lines capacitive, inductive, and resistive. Although under typical circumstances these effects may be negligible. However, interference levels under faulted conditions can be significant. 3.4.1.1 Capacitive coupling The results of research presented by Koshcheev indicate the electrical field below HVDC transmission lines does not generally require significant safety measures during construction when the pipe is isolated on skids, as the electric field influence associated with HVDC transmission is limited compared to HVAC.21 3.4.1.2 Inductive coupling CAPP indicates the voltages induced due to HVDC, under steady state conditions tend to be negligible. The magnitude of induction may contribute to minor interference problems with telephone lines, and possibly other communications systems, but is typically low enough that neither pipeline integrity nor safety hazards are considered likely under steady state conditions. However, during fault conditions, there is a possibility for short duration of elevated inductive coupling. 3.4.1.3 Resistive coupling During faulting both HVAC and HVDC transmission systems can present personnel safety issues and compromise pipeline integrity, with possible damage to the pipeline, coating, and associated equipment. A faulted HVDC power line presents a possible integrity concern for nearby pipelines. CAPP indicates that the fault current discharged to ground at the power line tower causes a ground potential rise (GPR) near the ground electrode. A voltage gradient exists relative to remote earth. A pipeline within the voltage gradient 22 000080 will experience a coating stress voltage as discussed in Section 3.3.2.1. If high enough, the voltage stress could puncture the insulating coating possibly damaging the pipeline. 3.5 Industry Procedure Summary The lack of industry consensus on the subject of AC corrosion guidelines has led to varied practices among pipeline operators in regards to mitigating AC interference on pipelines. As part of this study, The INGAA Foundation requested a review of industry practices and procedures related to AC interference. Based upon this review, all of the procedures address a safety concern and define a maximum allowable AC pipe-to-soil potential limit for above-grade appurtenances. For pipelines in close proximity to HVAC power lines, faults are identified as a hazard in almost all of the procedures. However, few addressed coating stress limit above which mitigation is required. For current density criteria, several procedures had clearly defined limits, while others addressed it as a concern for AC corrosion but did not specify a targeted limit of AC current density or define limits for mitigation. Table 1 provides a summary comparison of the industry procedures reviewed. Table 1-Industry Procedure Summary Current Density induced AC Potentkil Limit Fault Protection/Coating Stress Criteria Requiring Requiring Mitigation Voltage Limit Requiring Mitigation Mitigation In accordance with NACE: 15 V Not specified Not Specified 15 V 2500 V Not Specified Mentions damage possible from 15 V Not Specified faults but no limit 15 V or higher - No work unless approved by area Not specified Not Specified supervisor Modeling Required > 2 V Consider with Modeling 30 A/m2 75 A/m2 requires mitigation, 50 A/m2 15 V 5000 V requires further evaluation 150-2000 V depending on fault 10-15 V 30 A/m2 duration Faults to be considered along with a 15 V minimum separation distance, but 20 A/m2 no limit specified Faults to be considered during 15 V mitigation analysis, but no limit 50 A/m2 specified Faults to be considered during 15 V mitigation analysis, but no limit 50 A/m2 specified 23 000081 4 NUMERICAL MODELING Predicting high voltage interference is a complex problem, with multiple interacting variables affecting the influence and impact. In recent decades, development of advanced calculation methods and computer-based tools for simulation of interference effects, analysis of faults, and development of mitigation methods has been significant.235•9•1° Computer based numerical modeling can be utilized to examine the collocated pipeline's susceptibility to HVAC interference, help identify locations of possible AC current discharge, and where necessary design appropriate mitigation systems to reduce the effects of AC voltage, fault currents, and AC current density to meet accepted industry standards. These numerical models are capable of analyzing the interacting contribution of multiple variables to the overall magnitude of AC interference. Computer modeling is used to analyze the interactions and sensitivity of the variables that affect the magnitude of AC induction on pipelines. This section provides a brief review of numerical modeling software in general, as well as the results of the individual variable analyses. 4.1 Modeling Software Previous research has compared the benefits of specific industry standard software; literature is available for each of the common software packages.39'2023 This review addresses the generalizations concerning the present industry standard software, but does not aim to address or endorse specific software packages. For the majority of simple collocations considering a single pipeline and single HVAC power line numerous industry-accepted models have shown to be consistent in the assessment of HVAC interference. Often, for these simple cases, the benefit of a more complex model is not gained due to uncertainty in the analysis inputs. That is to say that for a majority of simple collocations, any of several industry accepted models are capable of providing an accurate analysis. The applicability is limited by the accuracy of the input data, and expertise of the analyst in utilizing the specific model. Often the uncertainty in critical input variables, such as the HVAC load current and phasing, outweighs the benefits gained from a more complex model. However, as the collocation complexity increases, both in terms of the number of structures and geometric routing, the limitations of some basic models support the benefits of the more detailed modeling software. Typical industry standard software packages that were reviewed use a transmission line model (TLM) to calculate longitudinal electrical field (LEF), based on established fundamental Carson or Maxwell equations for electromagnetic fields. The geometry and routing of the complete pipeline and transmission line network incorporated in the model considers multiple pipelines, transmission lines, tower sections, and other collocation parameters. Collocations are simplified as a connected series of finite sections and nodes, with appropriate parameters applied simulating the pipeline, soil, and transmission load-ins. The modeling software can then calculate the LEF for each section and solve the fundamental equations to calculate the potential, current, and theoretical current density along a given collocation. Calculation of the EMI and corresponding effects on buried pipelines requires a thorough understanding of the variables involved. Detailed modeling requires knowledge of electric field interactions, transmission current, tower design, bulk and local soil resistivity, and pipeline parameters such as geometry, coating, depth, diameter, electrical connections or isolations, and existing CP. All of these variables may significantly affect the AC interference model, and similarly the analogous real world interference. Likewise, the assumptions and simplifications made during the model setup can have significant impact on the accuracy and applicability of the outputs. 24 000082 While most of the available models are able to analyze each of these variables, either directly or indirectly, the accuracy of the analysis is dependent on the expertise and understanding of the analyst to assess the given variables. Similarly, the accuracy of the models can only be as good as the input data. Multiple sources are required for the collection of data, i.e. measured in field, provided by power line or pipeline operators, or based off published nominal data. For that reason, the accuracy of the results is ultimately dependent on the expertise of analyst and the reliability of the data input to ensure technically appropriate setup, despite the presence of multiple models that have been shown to be capable of providing accurate analysis when used within their applicable limitations. 4.2 Variable Analyses Due to the number of interacting variables affecting the overall levels of AC interference, it is difficult to isolate the effects of a single variable for all collocations scenarios encountered. Consequently, it is difficult to determine distinct limits for individual variables outside of which interference becomes negligible. Considering several key interacting variables is a more viable approach. For example, reported recommendations cite a distance of 1,000 feet as considered 'far and assumed low risk for HVAC interference. However, in cases where power line current loads are greater than 1,000 amps and in regions of low soil resistivity, elevated induced AC potentials and corresponding current density exceeding recommended thresholds have resulted at even greater distances. Therefore, separation distance alone may not provide sufficient justification to exclude a collocation from further assessment. Conversely, considering the interacting effect of the key variables identified is necessary when determining the need for detailed analysis for a collocation. DNV GL developed a series of computer models to illustrate the influence of key variables affecting induced AC on pipelines from nearby HVAC power lines. The software used is a graphical simulation platform developed to predict the steady state interference and resistive fault effects of HVAC power lines on buried pipelines in shared right-of-ways (ROWs). Using a TLM and appropriate input data, the software calculated the LEF, which then calculated the magnitude of induced AC potential, and current along the modeled collocated pipelines. The models created for these studies are simplistic in terms of geometry and serve as a demonstration of the variables' influence on AC induction on adjacent pipelines. Based upon the number of variables and their interactions with respect to AC interference on pipelines, these studies determine the relevancy of the various parameters. The studies offer guidance demonstrating the trends associated with each parameter on the overall level of interference, and were used along with existing industry guidance and literature findings to develop the recommended guidelines presented in Section 6. The primary variables analyzed as part of this study are as follows: • HVAC Power Line Current • Soil Resistivity • Separation Distance Between Pipeline and Power Line • Collocation Length of Pipeline and Transmission Line • Angle Between Pipeline and Transmission Line • Coating Resistance • Pipeline Diameter and Depth of Cover The results of these studies are presented and summarized in the following sub-sections. 25 000083 4,2.1 HVAC Power Line Current A primary variable influencing the magnitude of induced AC potential on a pipeline collocated with HVAC power lines is the magnitude of the phase conductor current. The current load of the nearby power lines has a direct influence on the LEF generated by the HVAC power line circuit(s). The intensity of the LEF varies with the current loads affecting both magnitude of induced AC potential on the nearby pipeline, as well as the area of influence. The area of influence affects the separation distance at which a collocated pipeline experiences significant interference and is further discussed in Section 4.2.3.1. To demonstrate the sensitivity of power line current on pipeline interference, DNV GL created a computer model simulating a single circuit vertical transmission line, parallel to a 10-inch diameter pipeline for 5,000 feet at a horizontal separation distance of 100 feet. The pipeline approaches the transmission line at a 90- degree angle and parallels the transmission line for 5,000 feet before receding from the transmission line at a 90-degree angle, as depicted in Figure 7. The HVAC load current was varied while all other model inputs remained constant, to analyze the influence of current alone. A uniform soil resistivity of 10,000 ohm-cm was applied and constant throughout the analyses. The transmission line current loads analyzed were 250, 500, 1,000, 2,500, and 5,000 amps based on ranges of operating and emergency loading conditions reported in literature and previously provided from power transmission operator's design conditions. Figure 8 shows the maximum induced AC potential as a function of transmission line current load. PIPELINE t 100 FT 5,000 FT if HVAC LINE Figure 7. Simplified ROW Model Geometry 26 000084 Effects of Current Load on Induced AC Potential 5,000 ft Parallel Collocation Length at 100 ft Separation —0—Max Induced Potenttal 50 45 VAC) l ( 40 ia t ten 35 30 d AC Po 25 duce In 20 m 15 imu Max 10 5 o 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 Current Load (Amps) Figure 8. Maximum Induced AC Potential as a Function of HVAC Transmission Line Current The results of this analysis show that the relationship between transmission line current and maximum induced AC potential on the pipeline is linear for a parallel collocation, considering a single interfering power line. When all other variables remain constant, the HVAC operating current load has a direct linear effect on the magnitude of the induced AC potential. This relationship allows for estimating influence of elevated current loads based on field measured AC pipe-to-soil potentials. For the specific case, with a pipeline collocated with a single HVAC circuit, if sufficient measurements of AC pipe-to-soil potential are taken, and corresponding transmission line current loads are provided for the specific time of measurement, the values can be scaled linearly to estimate the induced AC potential likely at the correspondingly scaled transmission current. This may be applicable, for example, for estimating the effects associated with a power line upgrade with a new current load. However, this method of approximation is only applicable for pipelines collocated with a single transmission line where sufficient data is available. As the number of transmission line circuits increases, the multiple interference sources and interaction the complexity of the interference increases such that the simply linear relationship is no longer valid. As the number of influencing HVAC circuits and pipelines within the area of influence are increased, the complexity of the interaction necessitates analysis that is more detailed. It is known that while the higher current loads presented represent the high end of typical reported design loads, recent trends in the power transmission industry have shown development and installation of higher capacity HVAC transmission systems capable of carrying significantly greater current loads. For example, previous references indicate a typical load for 345kV to 500kV systems to be approximately 500 to 1,000 amps per circuit.324 Recent research indicates increased capacity for 345kV lines carrying up to 5,000 amps 27 000085 per circuit, and over 6,000 amps for 500kV systems.2'24 While these magnitudes are not considered typical, numerous projects have developed recently that require mitigation for circuits operating at these elevated loads, indicating a need to consider actual current ratings for certain collocations. For this reason, loads are presented in terms of current rather than line voltage rating, as current is the driving load to control the level of EMI. It is noted that line ratings are typically given in terms of voltage ratings such as 138 kV, 345 kV, etc. however, the current load is the more relevant variable when determining the level of HVAC interference. Voltage rating alone can be misleading as the associated loads can be significantly higher or lower than the 'typical current loads for that kV rating. For this reason, it is recommended to obtain current load data from the power utility company when assessing risk of interference. 4.2.2 Soil Resistivity The soil resistivity along the collocation affects the magnitude of induced AC potential distribution as well as the theoretical AC current density along a given pipeline. It is necessary to consider both the bulk and specific layer resistivity when assessing likelihood and severity of interference. The bulk resistivity to the pipeline depth is one of the controlling factors in the analysis of induced AC potential. The bulk resistivity is the average soil resistivity measured in a half-hemisphere to the depth of the pipe, as shown in Figure 9 below. However, the specific resistivity of the soil layer directly next to the pipe surface, shown as Layer 2 in Figure 9, is a primary factor affecting the corrosion activity at a coating holiday, considering both conventional galvanic and AC assisted corrosion. The bulk soil resistivity combined with the coating resistance of the pipeline affect the level of induced AC potential expected along the pipeline. LAYER 1 LAYER 2 Figure 9. Graphical representation of soil resistivity measurements, showing bulk and layer zones 28 000086 To demonstrate the sensitivity of soil resistivity on pipeline interference and current density, DNV GL created a computer model simulating a single circuit vertical transmission line, parallel to a 10-inch diameter pipeline with a configuration similar to the model setup described in Section 4.2.1. The soil resistivity was varied along the pipeline while all other model inputs remained constant, to analyze the influence of resistivity alone. The soil resistivity was uniform along the entire modeled collocation, considering 100, 1,000, 10,000, and 100,000 ohm-cm. Figure 10 shows the maximum induced AC potential corresponding to varying current loads. Effects of Soil Resistivity on Induced AC Potential 5000 ft Collocation Length at 100 ft Separation —41(-250 Amps —4-500 Amps —*-1000 Amps —III-2500 Amps —0-5000 Amps 60 50 > 40 0.0 30 -u a) 20 -a 10 • )( 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100 000 Bulk Soil Resistivity (ohm-cm) Figure 10. Maximum Induced AC Potential as a Function of Soil Resistivity The results of the analyses show that the induced AC potential increases logarithmically with increasing soil resistivity. This increase in induced AC potential changes significantly between 100 and 10,000 ohm-cm but approaches asymptotical limit at soil resistivity values greater than 10,000 ohm-cm. The effects of soil resistivity have greater influence however on the current density. While an increase in soil resistivity can result in a slight increase in the magnitude of induced AC voltage for a given collocation, the theoretical current density and associated risk of AC corrosion decreases linearly with the increased resistivity. The layer resistivity of the soil directly next to the pipe surface is a primary factor in the corrosion activity at a coating holiday. The specific resistivity near the pipe at a holiday is inversely related to theoretical AC current density, as shown by the calculation for theoretical AC current density in Equation 1. Thus, an increase in soil resistivity results in a decrease in theoretical AC current density. 29 000087 Considering the 250 amp current load case from Figure 10, the theoretical current density was calculated from the induced AC potential for each magnitude of soil resistivity, considering a 1 cm2 holiday, shown in Figure 11 and Table 2. While the soil resistivity values increase several orders of magnitude across the range, the theoretical current density decreases on similar order, with minimal change in the overall induced AC potential, as shown in Figure 11 and 0 Table 2. The red dashed line represents the lower bound 20 amps/m2 threshold for current density as discussed in Section 3.3.1.1. It can be seen that based on the calculations provided by Equation 1, a very high theoretical AC current density is possible for relatively low AC potential, if soil resistivity values are below 10,000 ohm-cm. This results in elevated risk for AC corrosion for soil resistivity ranges below 10,000 ohm-cm. Effects of Soil Resistivity on AC Potential and Holiday Current Density 5000 ft Collocation Length at 100 ft Separation Max Vac —10-- Max Current Density — 20 Amps/m2 100 100 2) 90 90 /m s VAC) 80 80 l ( ia t 70 70 (amp ity ten Po 60 60 Dens t d AC 50 50 duce 40 40 30 t 30 l AC Curren d AC In ica t 20 •••• 011M •••••• 1 41=a, OM 4.10 20 duce In 10 10 heore T 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 Bulk Soil Resistivity (ohm-cm) Figure 11. Effects of Soil Resistivity on Induced AC Potential and Corresponding Holiday Current Density. Current density presented for a theoretical 1cm2 holiday 30 000088 Table 2-Calculated current density and induced AC potential P Calculated Current Induced Potential (ohm-cm) Density (A/m2) (Vac) 100 234 1.0 1,000 35 1.5 10,000 5 2.3 100,000 0.6 2.8 Based on 5,000ft parallel collocation with a power line operating at 250 A load, 100-ft separation distance 4.2.3 Collocation Geometry The geometry of the pipeline relative to the transmission line is critical in determining the magnitude and distribution of induced AC potential along the pipeline. The level of AC interference for a given collocation or crossing, with respect to collocation geometry, is dependent on the relative distance between the phase conductors and pipeline, the locations of convergence or divergence, and angle of approach or crossing. Each of these variables affects the overall level of induction or susceptibility to fault hazards, and their influence is dependent on all other configuration variables. When assessing susceptibility to AC interference all of these variables are considered. However, for the sake of this assessment, the following studies analyzed each independently in order to provide a simplified assessment of the influence of each parameter. The figures presented in Section 4.2.3.1 to 4.2.3.3 incorporate a dashed line similar to the current density threshold indicator in Figure 11. The limit lines provide reference to the AC potential limit that may result in a theoretical AC current density of 20 amps/m2 for a hypothetical 1 cm2 holiday, at soil resistivity of 1,000 and 10,000 ohm-cm. The limit lines are included to provide guidance illustrating the levels that may pose an elevated risk of AC corrosion at potentials below the NACE specified 15 volt limit for personnel safety. 4.2.3.1 Separation Distance Between Pipeline and Power Line The separation distance between the pipeline and transmission line is a significant variable controlling the level of induced AC potential influencing a given pipeline. The proximity of the pipeline to the phase wires limits the strength of the LEF to which the pipeline is exposed. To demonstrate the sensitivity of separation distance on pipeline interference, DNV GL created a computer model simulating a single 10-inch pipeline, and single circuit vertical transmission line, with similar configuration as described in Section 4.2.1. The separation distance was varied between the models while all other model inputs remained constant, to analyze the influence of separation alone. Induced AC potential results are plotted for separation distances of 50, 100, 500, 1,000, and 2,500 feet in Figure 12. The results indicate that for the higher load currents, the 20 A/m2 recommended current density threshold is exceeded for separation distances greater than 500 feet is exceeded. 31 000089 Maximum Induced AC Potential vs. Separation Distance 2500 ft Parallel Segment 20 Amps/m2 @ 1,000 ohm-cm --)0— 250 Amps • 500 Amps - • .20 Amps/m2 @ 10,000 ohm-cm 1000 Amps • 2500 Amps - NACE 15 Volt Threshold ••••••••••••• 5000 Amps 25 VA l ( ia t 20 ten d AC Po e 15 1 duc In I 10 J -1- - imum it OM malt '• • • Yale • NM • ' MO 6 OM • amb • mi. Max 5 1••• Aw 1110.1.111111 ,...... • 0 0 500 1000 1500 2000 2500 Separation Distance (ft) Figure 12. Effects of separation distance on induced AC potential. Current density limits presented for a theoretical lcm2 holiday. As the distance between the pipeline and transmission line increases, the induction on the pipeline decreases. This is expected as where the distance between the pipeline and phase conductors increase the distance from the LEF origin increases, decreasing the coupling effects. The results of this study as presented in Figure 12 illustrate an important effect of the load current as well. The area of influence or separation distance at which a collocated pipeline experiences significant interference increases accordingly. The figure also depicts potential levels corresponding to a 20 amp/m2 current density for both 1,000 and 10,000 ohm-cm soil resistivity for reference. For the given parameters analyzed, a current load of 250 amps results in an induced potential of approximately 2 volts at a 50 foot separation distance which quickly decreases to less than 0.5 volts at a distance of 500 feet. However, a load of 2,500 amps results in an induced AC potential of approximately 21 volts at a separation distance of 50 feet, and approximately 1.5 volts at a separation distance of 1,000 feet. This is important when determining which pipeline collocations require detailed analysis, as there is variation among industry guidance documents for the limiting distance. A limiting distance of 1,000 feet is common practice, however, for HVAC current loads greater than 1,000 amps, significant interference might be possible at distances exceeding 1,000 feet. While the induced AC potentials magnitudes may appear relatively low in Figure 12, for separation greater than 2,000 feet, it should be noted this example is considering a single HVAC circuit, and only an approximately 0.5 mile collocation length. In practice additional interfering circuits collocated for longer distances would result in 32 000090 higher induced AC potentials. Further, as discussed in Section 4.2.2, it is possible to have an elevated AC current density under relatively low soil resistivity conditions, such that AC corrosion is a concern at relatively low induced potential. It is necessary to consider separation distance in conjunction with the other factors to exclude a collocation from further analysis for separation distances within 2,500 feet. At a minimum, operating current, or an estimate of it, is also necessary when determining if further analysis is required. 4.2.3.2 Collocation Length of Pipeline and Transmission Line Just as separation distance affects the magnitude and distribution of induced AC potential along the pipeline, so does the length of collocation. The collocation length is the distance along the ROW that a pipeline parallels or crosses the transmission line within a separation distance and angle that allow for inductive coupling. The collocation length affects the magnitude of induced AC potential that accumulates on the pipeline as it defines the length of the pipeline exposed to the LEF of the phase wires. To demonstrate the sensitivity of collocation length on pipeline interference, DNV GL created a computer model simulating a single 10-inch pipeline, parallel to a single circuit vertical transmission line at a 50 foot offset. The collocation length was varied between the models while all other model inputs remained constant, to analyze the influence of collocation length alone. Collocation lengths of 500, 1,000, 2,500, 5,000, and 10,000 feet of the pipeline and transmission line compare the maximum induced AC potential in Figure 13. Maximum Induced AC Potential vs. Collocation Length at SO ft Separation — — 20 Amps/m2 @ 1,000 ohm-cm —4.— 250 Amps —40-500 Amps 20 Amps/m2 @ 10,000 ohm-cm ....ote. 1000 Amps —41..— 2500 Amps — NACE 15 Volt Threshold —41.— 5000 Amps 40 : - - — — u — >4 35 :--: To : '.; 30 c - 4.,to : o 25 u a 20 -- = ucu -e3 15 c E 10 ...... _g x 5 _ ..."•< g 0 ' 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 Collocation Length (ft) Figure 13. Maximum Induced AC Potential as a Function of Collocation Length 33 000091 As the collocation length increases, the magnitude of induced AC potential on the pipeline increases, as the length of pipeline exposed to the LEF is increased. Collocation lengths as short as 500 feet are capable of inducing 2 - 10 VAC or greater considering a single collocated power line operating at 1,000 amps or greater. The potential levels corresponding to a 20 amp/m2 current density for both 1,000 and 10,000 ohm-cm soil resistivity have been included for reference. Considering a relatively low soil resistivity of 1,000 ohm-cm, the 20 amps/m2 current density criteria is exceeded at a 2,500 foot collocation length for all load currents analyzed. The results of the collocation length study also accentuate the sensitivity to HVAC load current as previously discussed in Section 4.2.1. The collocation length required prior to exceeding the 15 volt safety threshold for the 2,500 and 5,000 amp load conditions is approximately 1,750 and 800 feet respectively. These conditions are further increased in complex collocations where multiple lines exist. It is necessary to consider collocation length in conjunction with the other factors to exclude a collocation from further analysis for separation distances within 2,500 feet. At a minimum, operating current, or an estimate of it, is also necessary when determining if further analysis is necessary. 4.2.3.3 Angle Between Pipeline and Transmission Line The angle at which the pipeline and HVAC transmission line cross has an effect on the magnitude of induction on the pipeline at the crossing. As the angle increases between the pipeline and transmission line, the magnitude of the induction decreases as the component of the pipeline exposed to induction decreases. For a perpendicular crossing, with the pipeline crossing at or near 90° to the power line, the induction on the pipeline is minimized as the effective parallel length is minimized. The magnitude of the current on the transmission line also has a significant impact on the induced AC potential at crossing locations. Previous 'rule-of-thumb practices throughout industry may have indicated crossings greater than 60° resulted in negligible induction on adjacent pipelines.2 However, recent studies have resulted in HVAC installations with significantly greater current capacity, which acts to increase the corresponding interference resulting in cases with induced AC voltage at relatively high angle crossings. To demonstrate the sensitivity of collocation angle on pipeline interference, DNV GL created a computer model simulating a single 10-inch pipeline, and single circuit vertical transmission line, with similar configuration as described in Section 4.2.1. The pipeline was approximately 2 miles long and the angle between the pipeline and transmission line varied between models while all other model inputs remained constant, in order to analyze the influence of crossing angle alone. Figure 14 shows the results of an analysis of crossing angles between 15 and 90 degrees and the calculated maximum induced AC potential for each case. 34 000092 Maximum Induced AC Potential vs. Crossing Angle Considering a 2 mile section of 10-inch Diameter Pipe 4•1110 =MD 20 Amps/m2 @ 1,000 ohm-cm 250 Amps —0— 500 Amps 20 Amps/m2 @ 10,000 ohm-cm —0— 1000 Amps —0— 2500 Amps •••• NACE 15 Volt Threshold 5000 Amps 16 -1=11 14 VAC) l ( 12 ia t 10 : ten ...4 I 1 d AC Po duce In imum 2 x -VIM 4111110 ill•IIIII Ma 0 0 10 20 30 40 50 60 70 80 90 100 Crossing Angle (Degrees)) Figure 14. Maximum calculated induced voltage at various HVAC line crossing angles Considering a typical 345kV circuit, and current loads of up to 1,000 amps, a crossing angle of greater than 45° degrees resulted in an induced potential of less than two (2) VAC for the study presented. A crossing angle of greater than 60° induces minimal potential such that the corresponding current density is less than 20 amps/m2 even in a relatively low soil resistivity at 1,000 ohm-cm. Previous industry experience and general guidance practices across industry appear consistent with this understanding that crossings of greater than 60° are typically low-severity with respect to induction. However, as the transmission line load increases to greater than 1,000 amps, it can be shown that crossing angles up to 60° may induce potentials such that corresponding current density exceeds 100 amps/m2, in low resistivity soil conditions. Depending on target limits for current density, models show that crossing angles of 80° can cause high current density in relatively low soil resistivity locations. The crossing angles discussed above are with respect to induced AC interference specifically. Assessment for susceptibility to faults, and coating breakdown due to fault voltage, is required for all crossings where pipelines pass in close proximity to a tower ground. 4.2.4 Coating Resistance The resistance of the pipeline coating to ground is a significant factor controlling the level of induced potential that may build up on a pipeline. However, in practice the coating resistance is typically not known with great certainty and is generally inconsistent along the pipeline length. The coating resistance to ground is a function of the coating type, condition, thickness, and local soil resistivity, all of which may vary along a typical collocation length. 35 000093 In general, a poorly coated pipeline, or deteriorated coating with low resistance to ground allows multiple paths to ground for AC potential to dissipate. This reduces the buildup of induction, resulting in lower AC potential and lower current density discharge at any individual holiday. Conversely, considering a well coated line with high dielectric strength and excellent coating condition, the resistance to earth along the length of the pipeline is relatively high allowing for greater induction build up over longer distances. For example, this case may exist with a newly FBE coated pipeline, with minimal holidays, in proximity to a collocated HVAC power line. Due to the high resistance to ground, and relatively few ground paths, the induced AC potential can build along the collocation length. This can generate elevated AC potentials, which may be hazardous from a safety standpoint, but also create a possible corrosion risk, as the AC current can discharge from a relatively few holidays after a physical or electromagnetic discontinuity, such as the pipeline diverging from the collocation. Relative estimates of coating resistance are provided by Dabkoski in the report for Pipeline Research Council International (PRCI) and Parker24'25, and summarized in Appendix B for reference, to be utilized in detailed modeling analysis based on coating quality, and soil resistivity, however specific guidance is not provided for a relative risk associated with the various coating resistance values. 4.2.5 Pipeline Diameter and Depth of Cover The diameter of the pipeline collocated with or crossing an HVAC power line affects the level of induced AC potential on the pipeline. However, historical experience has indicated that the effect is relatively minor compared with the influence of other variables. To demonstrate the sensitivity of pipe diameter on pipeline interference, DNV GL created a computer model simulating a single pipeline, parallel to a single circuit vertical transmission line for 5,000 feet at a horizontal separation distance of 100 feet. The pipeline approaches the transmission line at a 90-degree angle and parallels the transmission line for 5,000 feet before receding from the transmission line at a 90-degree angle. The pipeline model considered diameters of 6, 10, 18, 24, 36, and 48 inches, while all other model inputs remained constant, to analyze the influence of diameter alone. The model used a uniform soil resistivity of 10,000 ohms-cm. The results of this study indicate that the magnitude of induced AC potential decreases with an increase in pipeline diameter, as shown in Figure 15. As the diameter of the pipeline decreases, the surface area exposed to the LEF also decreases. However, the magnitude of LEF generated by the transmission line remains unchanged. For a smaller diameter pipeline, the LEF influences a smaller surface area resulting in greater induced AC potential compared to a larger diameter line, considering all other variables equal. Further, the pipeline characteristic impedance varies inversely with pipeline diameter, as presented in previous work by PRCI324. Considering all other parameters equal, a larger diameter pipeline will have a generally lower effective resistance to ground, and therefore a lower tendency of HVAC interference. For relative comparison, an increase in diameter from 6 to 48 inches resulted in a 20% decrease in induced AC potential on the pipeline, regardless of the interfering current level. In the previous analysis, the models used 10-inch diameter pipeline, which will provide a conservative estimate relative to typical larger diameter transmission lines. This was chosen to clearly demonstrate the effects of the individual variables. 36 000094 Maximum Induced AC Potential vs. Pipeline Diameter s000 ft Collocation Length at 100 ft Separation Amps 500 Amps 1000 Amps Amps Amps 50 45 VAC) l ( 40 ia t 35 ten 30 d AC Po 25 duce 20 In 15 imum 10 Max 5 0 „ 0 5 10 15 20 25 30 35 40 45 50 Pipeline Diameter (in) Figure 15. Maximum Induced AC Potential as a Function of Pipeline Diameter Similar to pipeline diameter, the pipeline depth of cover has a relatively minor influence on the induced AC potential on the pipeline. In general, the level of AC interference decreases with increasing depth of cover as the distance from the individual phase conductors and total resistance to the LEF is increased, though the effect is relatively minor for typical burial depths. A fixed depth of cover of approximately 5 feet was used in the sensitivity studies above. 5 MITIGATION NACE International Standard Practice SP0177-2014 requires a mitigation system designed for pipelines where HVAC interference is present.1° Mitigation system design varies across the industry, but in general all involve a low resistance grounding system to pass interfering AC to ground. Typical mitigation system designs can be either surface or deep grounding designs. Both designs have benefits and detriments considering performance, cost, and constructability. Liquid and gas transmission pipelines are regulated under the Department of Transportation (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) Regulations §49 CFR Part 195 Subpart H Corrosion Control (195.551 - 195.589)26 and §49 CFR Part 192 Subpart I Requirements for Corrosion Control (192.451 - 192.491)27, respectively. The regulations have various requirements for corrosion control of which CP and electrical isolation are major factors in compliance. CP systems apply a DC to the pipeline, and electrical isolation quantifies the surface area or limits of the system. CP systems designed for transmission pipelines must meet federally regulated criteria. 37 000095 5.1.1 DC Decouplers When designing mitigation systems for induced AC and faults on transmission pipelines, detrimental effects to the CP system must be considered. It is essential to ensure they do not compromise the operation of the CP systems. Additional structures such as grounding and shield wires used in mitigating induced AC attached directly to the pipeline change the operating characteristics of the CP system, changing the surface area intended for the CP compromising its effectiveness. Direct current decouplers (DCD) alleviate this situation. However, there are some cases where the design of CP accounts for the mitigation. The decouplers, designed into the circuit, allow AC current to pass to ground, while blocking the DC CP current, maintaining the pipeline surface area. There are various types, sizes and ratings of decouplers used depending on the predicted faults or induced AC and mitigation design. DCDs are also used to block DC current at grounded above grade appurtenances, such as block valves, metering stations, and launcher/receiver stations. Decouplers installed across electrical isolation flanges (IF) prevent "burn over" which can occur when an AC fault current or lightening surge is large enough in magnitude to arc over the gap between flange faces or exceeds the rating of the IF. 5.2 Surface Grounding Surface grounding generally refers to one of several types of mitigation grounding installed at or near the surface or pipe depth. Typical designs may consist of bare copper cable, zinc ribbon, or engineered systems buried generally parallel to the pipe path and connected to the pipeline through a DCD. During new construction, surface grounding can be installed directly in the pipe trench, or laid parallel to the pipe in an adjacent trench or bore. This approach allows for cost-effective installation of a significant length of mitigation at a lower cost relative to alternative forms of mitigation, but is dependent on construction access along the ROW.16 If necessary, connecting additional mitigation ribbon in parallel and even adding shallow vertical anodes to the circuit will further reduce grounding resistance up to a certain extent. Installing this type of mitigation system at distributed, targeted locations, optimized from the interference model, reduces the induction along the pipeline. Additionally, when laid parallel to the pipeline in regions where transmission line towers are in close proximity, the mitigation ribbon also acts to protect and shield the pipeline from damage resulting from fault and arcing scenarios. Analysis of the reduction in ground resistance possible with various installation approaches included a calculation of the resistance of 1,000 foot long mitigation ribbon in varying soil resistivity, using the modified Dwight's Equation for multiple anodes installed horizontally28. Figure 16 illustrates how this calculated grounding resistance varies with the number of ribbons connected in parallel at multiple levels of soil resistivity. While numerous sizes of ribbon cables exist, the length is a much more significant factor in determining total resistance than diameter, when considering typical ribbon diameters, therefore this analysis considers a constant diameter ribbon. 38 000096 Grounding installation Resistance Distributed Horizontal Parallel Zinc Ribbons (Constant 1,000 ft Length) a 500 ohm-cm —11— 1,000 ohm-cm 5,000 ohm-cm 10,000 ohm-cm --•-- 20,000 ohm-cm 1.60 1.40 ) 1.20 hms (o ce 1.00 tan is 0.80 d Res 0.60 1- Groun 0.40 0.20 0.00 1 2 3 4 5 6 7 Number of Parallel Ribbons Figure 16. Grounding Resistance of Horizontal Parallel Zinc Ribbons at Varying Soil Resistivities As shown in Figure 17, at low soil resistivities, very low grounding resistance results with a single, relatively short ribbon length. As the soil resistivity increases, so does the achievable grounding resistance. The data is presented considering multiple parallel mitigation ribbons to demonstrate that further reduction in ground resistance is possible by adding additional grounding at a particular installation. However, diminishing returns exist such that further increasing the extent of grounding at a specific site, beyond a certain threshold, results in minimal additional reduction, as shown in Figure 16. The length of vertical grounding installations requires review of economics, construction, and practical design considerations. Multiple shorter grounding rods can be incorporated to achieve a low resistance to ground without requiring deep drilling, where parallel surface grounding does not sufficiently reduce the ground resistance. Vertical ground rods should be separated horizontally by the length of the ground rods at minimum for optimum efficiency.23 For locations of high surface resistivity, one drawback for horizontal surface grounding is the length of mitigation ribbon wire required to achieve a low resistance. Where multiple parallel ribbons are required to achieve sufficient grounding resistance significant ROW access may be required. As discussed, the shared utility ROW may limit construction access for mitigation parallel to a collocated pipeline. Additionally, as pipelines cross physical obstructions, such as roadways, railroads, access may limit the extent of parallel mitigation systems. However, surface grounding still continues to be the preferred mitigation technique and can efficiently provide adequate mitigation grounding for a majority of collocations. 39 000097 5.3 Deep Grounding Deep drilled ground wells (deep wells) offer another form of mitigation grounding, and may be considered for select applications. Deep wells generally consist of one or more anodes drilled vertically into the ground in order to achieve low ground resistance. Actual deep well depths can vary based on needs, but they generally range greater than 100 feet in depth. In general, construction costs are generally higher for deep well grounding than for comparable surface mitigation. However, deep well grounding can be a viable option in specific applications where one or both of the following criteria are satisfied. 1 The soil resistivity at the surface is significantly greater than (>20 x) the soil resistivity at lower depths. 2 Horizontal surface grounding is not feasible due to construction obstacles (roads, railways, right-of- way access, etc.) For typical mitigation systems, where parallel ribbon and deep grounding are both options, parallel ribbon proves to be more efficient and economical because it can achieve a lower resistance to ground for lower overall cost. For comparison, ground resistance calculations were analyzed to determine the approximate equivalency in effective ground resistance between parallel zinc ribbon, and an individual deep well anode. Figure 17 below shows a comparison of parallel horizontal grounding configurations compared to a single 6- inch diameter deep well anode approximately 200 feet deep. The soil resistivity ratio, plotted on the x-axis, is the ratio between the bulk soil resistivity to a depth of 10 feet for surface ribbon and the bulk soil resistivity to a 200 foot depth for a deep well. Along the y-axis is the equivalent length of horizontal surface grounding required to meet the same level of grounding resistance as the deep well anode. The two curves in the figure below display this trend for single and double surface ribbon installations. 40 000098 Comparison of Surface Mitigation with Deep Well Anodes Based on 200-foot, 6 -inch Diameter Deep Welt Anode Single Ribbon -Double Ribbon 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 0 2 4 6 8 10 12 14 16 18 20 Ratio of Soil Resistivities (Surface/Deep) Figure 17. Comparison of Surface Mitigation to Deep Well Anodes Considering a typical scenario where deep soil resistivity values are of similar order to the surface resistivity, a single deep well grounding installation would be necessary for approximately every 1,000 to 2,000 feet of individual parallel ribbon. However, considering a hypothetical location where the deep soil resistivity is an order of magnitude lower than at the surface (soil ratio of 10), it can be shown that a single deep well installation could provide a similar ground resistance as approximately 5,000 feet of individual parallel ribbon. Under certain scenarios, where the ratio between the surface and deep soil resistivity is high, deep well anodes may become a viable solution to obtain a low grounding resistance. Previous case studies and project experience have rarely shown soil resistivity ratios of this magnitude, such that deep well grounding was a preferred option. However, where construction access is limited, not allowing for installing longer lengths of surface grounding to achieve the required mitigation deep well grounding may be beneficial. In scenarios where grounding is only necessary at a single specific location on the pipeline, deep well grounding may be an option. 5.4 Mitigation Comparison Deep well anodes may provide a viable mitigation option under specific circumstances, but industry practice, historical assessments, and construction practice have generally shown that surface mitigation provides more economical and efficient mitigation for the majority of collocations. In cases where arc shielding protection is required to guard against fault scenarios, deep well anodes do not provide such protection, thus necessitating the installation of surface ribbon in addition to primary mitigation. Surface mitigation can also serve as fault shielding, protecting against damage to the pipeline and its coating when properly placed between the pipeline and power transmission ground. 41 000099