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Litigation implications of pipeline integrity management practices.

(Editor's Note: Part One of this series was entitled "Litigation Consequences of Pipeline Integrity Management Choices" and appeared in the June 2007 issue of P&GJ. Part Two offers an overview of the strengths and potential litigation weaknesses of inline inspection, hydrostatic testing, direct assessment and related pipeline assessment approaches.)

Within the pipeline litigation arena, adherence to Department of Transportation (DOT) regulatory requirements are considered to represent a minimum operating obligation and standard for pipeline operators. The courtroom battles are actually won and lost over investigation of higher industry criterion relating to prevention of pipeline failure: that of Best Practices.

"Regulation" is defined by the American Heritage Dictionary as principle, rule, or law designed to control or govern conduct.

To take this definition one step further, the term "regulation" refers to a principle, rule, or law designed to control or govern conduct, mandating compliance and usually originating external to the organization or group to which it pertains.

Regulations as mandated by DOT pertaining to the operation of hazardous liquid pipelines are clearly defined. DOT CFR Title 49, Part 195 specifies regulations to assess, evaluate, repair and validate the integrity of hazardous liquid pipeline segments that, in the event of a leak or failure, could affect populated areas, areas unusually sensitive to environmental damage and commercially navigable waterways (High Consequence Areas or HCAs).

Hazardous liquid pipeline operators who own or operate jurisdictional pipelines are required to identify HCA segments, implement a Baseline Assessment Plan and develop an Integrity Management Plan (IMP) that addresses specified elements as mandated by DOT.

Classified defects identified through IMP assessment means must be repaired within time limits defined as immediate, 60-day or 180-day duration.

A Best Practice can be defined as a technique or methodology that, through experience and research, has proven to reliably lead to a desired result.

To expand further, Best Practices are those documented, accessible, effective, appropriate, and widely accepted strategies, plans, tactics, processes, methodologies, activities, and approaches that have been shown over time through research, evaluation, and practice to be effective at providing reasonable assurance of desired outcomes, and which are continually reviewed and improved upon as circumstances dictate.

It can be stated that a commitment to using Best Practices in the pipeline industry is a commitment to using all of the knowledge and technology at one's disposal to reduce risk and ensure continued safe pipeline operation.

For the pipeline operator, the application of a defensible Best Practices approach equates to development of an IMP that not only serves to follow industry standards and satisfy minimum regulatory requirements, but accounts for the latest pipeline assessment or repair technologies in application with key factors, including material aspects of the pipe steel, construction issues, pipe vintage, soil environments, aspects of terrain, proximity and rate of public encroachment, future service requirements and historical operational and maintenance records.

Budgetary factors obviously are another component of the approach an operator must consider when preparing an IME The company's economics are an unavoidable fact of life, as the most elaborate and extensive IMP cannot be placed into effect unless the capital resources exist and are committed to financing it.

During start-up or otherwise lean years for a company, pipeline assessment and maintenance often becomes a tempting area for the deferral of capital expense. In itself, this is a normal consequence of economic viability. The deferral of capital expenditure for integrity management only becomes problematic when regulatory compliance is compromised or a temporary deferral in pipeline integrity-related financing evolves into a permanent corporate standard.

As under-financing of a company's pipeline integrity budget is so economically tempting, the operator's IMP should include a worst-case failure scenario along with the multitude of other factors that more directly impact integrity management in order to maintain an appropriate level of priority for safety. In other words, the operator should consider hypothetical failures at various pipeline locations and the likely consequences of those failures.

If a particular hypothetical failure were to occur, the company should assess whether the operator IMP would be defensible and whether the company could withstand the public and litigation scrutiny that would follow. Although this exercise should not dominate the development of a company's IMP, assessment of litigation risk factors should be a substantive factor weighted accordingly, relative to the other aspects of proper integrity management and business risk taking.

The processes for assessment of the worstcase hypothetical scenarios and for analyzing the consequences of any given failure are beyond the scope of this article, primarily for the reasons that the range of hypothetical failures and consequences will vary with each pipeline, the pipeline operator approach and the land use area surrounding the pipeline. Instead, the purpose of this article is to provide a framework for the operator to begin thinking about the significance of its integrity management practices with a litigation defense appreciation.

We will explore pipeline IMP applications in terms of litigation strengths and weaknesses; the "Best Practices Gap" between the obligatory regulatory requirement and the "commitment to using all the knowledge and technology at one's disposal to ensure success."

DOT regulations allow hazardous liquid pipeline operators to assess the integrity condition of a jurisdictional pipeline segment through the following means:

* External Corrosion Direct Assessment (ECDA)--A four-step process that combines pre-assessment, indirect inspection, direct examination, and post-assessment to evaluate the threat of external corrosion to the integrity of a pipeline.

Note: that Internal Dry Gas Corrosion Direct Assessment (DG-ICDA) has been approved for selected gas pipelines; Wet Gas Internal Corrosion Direct Assessment (WG-ICDA), Liquid Petroleum Internal Corrosion Direct Assessment (LP-ICDA) and Stress Corrosion Cracking Direct Assessment (SCDA) are currently under development at NACE.

* Hydrostatic Testing--A strength and tightness test of a closed pressure vessel by water pressure; a test using non-compressible liquid under pressure at a level equal to or greater than the maximum pressure that will be utilized when in use.

* Inline Inspection (ILI) Tool--A tool to inspect the condition of the pipeline wall that is sent down a pipeline and propelled by the pressure of the product in the pipeline itself.

Note: Also permitted is utilization of an "Other Equivalent Technology" (operator must demonstrate that an equivalent understanding of pipe condition will be achieved). This approach by definition must involve critical engineering assessment and secondary engineering scrutiny to obtain approval by DOT and is not addressed in this article.


The ECDA concept involves utilization of several integrated data sets, i.e. cathodic protection, external coating surveys, soil resistivity surveys in combination with pipeline historical leak records to locate, evaluate, predict and excavate, inspect and repair faults in regions where external metal loss through corrosion is most likely to have occurred. ECDA as a concept has been applied in various forms by pipeline companies for many years, however, it has now become a DOT-recognized assessment technique for those pipelines that cannot be inspected utilizing ILI tools.

The major weakness of an ECDA program is the technical limitations in regards to quantification of pipeline defects other than external corrosion, i.e. construction dents, mechanical damage, internal corrosion, cracks.

From a litigation perspective, ECDA potentially sounds defensible if presented to a jury. ECDA has an element of credibility to it by the notion of what could be better than actually excavating the pipe and examining it with your "own two hands." Juries can respond to notions of "getting your hands dirty" the "old fashioned way" in order to inspect a pipe. While the idea harkens back to a simpler time and could awaken feelings of nostalgia in some jurors, particularly older blue-collar workers, if ECDA is not performed meticulously, then it has the potential to sink a company in court.

In order to survive scrutiny, an IMP based on largely subjective ECDA conclusions must provide assurances that the decision to apply ECDA was not solely based upon the advantages of reduced cost and that every step of the process is performed in an objectively verifiable manner.

As a practical matter, reliance on ECDA as the cornerstone of a company's external corrosion IMP may be acceptable, depending upon the age of the pipeline segment, its maintenance history, and the absence of leaks. DOT will accept an IMP constructed around ECDA. Nevertheless, if a major failure subsequently occurs on the pipeline segment, a company may have considerable difficulty defending an IMP centered on that methodology. From a litigation perspective, reliance upon ECDA as the cornerstone of an IMP can be problematic because human error and subjectivity easily can impact testing authenticity and validity.

Companies typically perform pipeline section corrosion leak history analysis as a major component within an ECDA program. Leak history analysis is a combination of historical research and statistical probability. The primary weaknesses of leak history analysis arise from the inconsistency of reliable, comprehensive data about a pipeline and the inherently subjective nature of the analysis process. For leak history analysis to have any verifiability, assessment personnel must have good data regarding the history of leaks on a pipeline.

This can be problematic for many pipeline companies where consistent record-keeping over the course of decades may be questionable. Nevertheless, assuming good historical data, a pipeline technician literally reviews past leak data, the location of leaks, frequency of occurrence, size and morphology of particular leaks, and corresponding cathodic protection pipe-to-soil readings in the years prior to the respective leaks. Once all this data is synthesized, the technician then attempts to identify problematic areas or sections along the pipeline where corrosion is more likely to be occurring.

Although some pipeline technicians can boast a remarkable record of successful leak prediction, leak history analysis is incredibly subjective and imprecise by its nature. Innumerable variables can cause a pipe to corrode at any given point. The fact that a cluster of leaks may be identifiable in a particular section of pipe does not mean that a leak in a different segment will not occur. Soil conductivity can fluctuate, sometimes widely, depending on the climate. The replacement of pipe sections over the years, other repairs or changes to the pipe, is another factor.

If the pipeline runs through mountainous terrain, soil resistivity can fluctuate dramatically as elevation changes. Multiple foreign pipeline crossings, underground mining operations and other energy sources can exponentially multiply the variables influencing a pipeline. Human encroachment and changes to the pipeline's surrounding environment can be difficult to factor. Micro-bacterial changes to the soil in discrete portions of a pipeline can be difficult to ascertain. In short, the land through which a pipeline runs and the pipeline itself is always changing.

The accumulation of complete data about a pipeline and the interpretation of that data are subject to wide margins of human error, inconsistency and subjectivity. Computer software has been able to eliminate some of these issues by providing better mathematical plotting of leak probability, but the accumulation and inputting of data remains subject to human imprecision.

A Best Practices approach to an ECDA-based IMP should:

1. As a prerequisite, establish and document solid technical justification for not using other more objective assessment techniques to assess the pipeline section.

2. Establish a data management approach that ensures security of data and allows for seamless data integration and manipulation.

3. Ensure that all data sets provide sufficient long-term data for acceptable statistical conclusions and that all data sets contain results that are accurate within acceptable industry tolerances.

4. Establish and document solid engineering criteria for selection of excavation sites and examination of excavated pipe.

5. Ensure that all involved personnel are trained and qualified and that all certifications are documented.

6. Ensure that the program evolves to a conclusion in a timely manner.

7. Ensure that a backup plan for pipeline integrity assessment is in place that can be implemented quickly if required.

8. Ensure the IMP recognizes and fully addresses the limitations of the ECDA program in regards to quantification of pipeline defects other than corrosion.

Hydrostatic Testing

A typical industry hydrostatic test involves purging all natural product out of the pipeline, cleaning the inside of the pipeline, filling the pipe segment with water and pressurizing the pipeline to a level higher than normal operating pressure and "holding" that pressure for a predetermined time duration.

The test is designed to locate defects in the pipeline that cannot tolerate the higher pressure. Under normal soil and climate conditions, when a hydrostatic test leak occurs, there is an immediate drop in pressure and water is released. The pipeline segment where the leak occurred is excavated, repairs made and then retested. This process is repeated as often as necessary in order to obtain a successful test result.

Hydrostatic testing of hazardous liquid pipelines requires testing to at least 125% of the maximum operating pressure (MOP) for at least four continuous hours, and an additional four hours at a pressure of at least 110% of MOP if the piping is not visible.

Periodic hydrostatic testing is an acceptable method to ensure the integrity of hazardous liquid pipelines. Hydrostatic testing will remove material wall loss defects and crack defects, regardless of geometry or orientation, that have critical dimensions at the pressure test level of the pipeline segment.

Hydrostatic testing has several technical and operational limitations:

* It is not always practical to take a pipeline segment out of service.

* No information is gained regarding the presence or absence of sub-critical flaws and in some cases (crack defects) hydrostatic testing may actually result in defect growth.

* If water is not completely removed from the pipeline, internal corrosion can initiate within low elevation pipe sections.

* Water disposal following the hydrostatic test program can be a major environment concern.

* It is, particularly in regards to an older pipeline, difficult to predict and plan for the number of hydrostatic leaks and the type of pipeline defects that will be exposed. From a litigation perspective, hydrostatic testing is more defensible than ECDA analysis.

For purposes of this article a hypothetical approach may be helpful for evaluating the strengths and weaknesses of hydrostatic testing from a litigation perspective. A pipeline operator recently has performed hydrostatic testing of a 36"O.D., 0.312" wall thickness, grade API X70 pipeline segment to a minimum test pressure of 1,092 psi (125% of MOP of 874 psi). Two years after completion of the successful hydrostatic test program, a catastrophic failure occurs at an operating pressure significantly lower than recent hydrostatic test pressures. Third-party interference is eliminated as a cause and excavation of the failure site reveals external corrosion at the point of failure.

How could this occur? The frequency for pipeline hydrostatic testing must equate to the time required for a flaw to grow from a geometry that just survived a hydrostatic test to a geometry that becomes critical at the operating pressure of the pipeline. In this hypothetical case, a sub critical corrosion defect measuring 6" in axial length and exhibiting a wall thickness penetration of 45%, survived the hydrostatic test minimum failure test pressure (Modified B31G calculated predicted failure pressure of 1,111 psi). An aggressive stray current influenced growth rate resulted in a l"axial, pitting length extension and accelerated progression of defect depth to 75% of wall thickness penetration (growth rate of 0.004" per month; modified B31G calculated predicted failure pressure of 873 psi).

This possible, but simplistic, worst case-based hypothetical scenario does not account for all influencing factors, however does serve to illustrate the strengths and weaknesses of the hydrostatic test program. The program identifies at the time of testing exactly where weak points are on the pipeline segment. Those points can then be excavated and replaced with new pipe. The weakness of hydrostatic testing is that it provides no data as to where sub-critical flaws may be present at points along the pipeline segment which survived the day of testing.

Granted, if the pipe section survives a consistent elevation in pressure that is maintained for a significant period of time, that success is an indication that the pipe at points which did not fail are subject to lesser corrosive influences. The pipeline operator, however, still lacks any actual knowledge as to the condition of the pipe at those points and failures have happened in short periods following hydrostatic testing. Although hydrostatic testing can be very defensible in court, particularly as it is reliable and subject to objective verification, it does have this shortcoming that will be exploited during the litigation process.

A Best Practices approach to a hydrostatic test IMP-based program should:

1. Ensure that the hydrostatic test program follows strict engineering protocols and that accurate records of the test program are maintained for the life of the pipeline.

2. Ensure that the engineering approach to the hydrostatic testing program is based upon the type of defect anticipated, i.e. corrosion wall loss may require implementation of a simple hydrostatic test pressuring approach; pipe wall cracking may require implementation of a "spike" test at a higher maximum pressure for a short period (30 minutes).

3. Ensure that the time duration between hydrostatic testing programs is based upon solid demonstrable critical assessment studies in regards to the operating condition of the pipeline and the category of pipeline defects involved. Studies have been performed that demonstrate the acceptability of the pipeline for extended service after a hydrostatic pressure test, "if for there are no factors present that would accelerate corrosion growth or crack growth such as environmental factors or aggressive pressure cycles".

Inline Inspection (ILI)

The technologies for metal loss inspections are magnetic-flux leakage (MFL) and ultrasonic (UT) wall thickness measurement. MFL technology can be applied axially or circumferentially, depending upon the nature of the targeted defect. MFL and UT-based ILI provide information regarding the location, depth and length of corrosion and wall loss-related defects.

Other more recent technologies are available for detection of pipeline cracks including sophisticated ultrasonic and the EMAT-based (Electromagnetic Acoustic Transducer).

ILI consists of the introduction into the pipeline segment of a series of devices that inspect and literally map every square inch of the pipeline wall. MFL and UT inspection devices gather detailed readings of pipe wall thickness and density throughout the length of the line and relay that data to a centralized data storage unit.

ILI is likely the preferred method for operators whose lines are piggable. However, some pipeline designs (telescoping pipe diameters, the presence of offsets, multiple undersized diameter valves, etc.) may prohibit the use of ILI tools. In such cases, pipeline modification to allow ILI may be impractical, if not impossible.

Inherent limitations relative to detection and measurement of specific geometry or pipeline defect types exist for each technology and are now defined as Probability Of Detection (POD), Probability Of Identification (POI), in application with related severity measurement accuracy tolerances.

Despite such limitations, ILI remains the most advanced and reliable method of testing a pipeline to date. Once this process is completed, the operator has a precise map of the wall condition for the entire pipeline.

If, for example, corrosion is occurring, an operator may prioritize repairs based on severity of corrosion at the weakest points and establish a plan for addressing sites of corrosion that may be in the process of developing. As ILI is the most comprehensive and objectively verifiable of current testing methodologies, by necessary implication it is the most defensible basis for integrity management for a pipeline company.

If a company experiences a major failure after having performed a successful and well-managed ILI program and has undertaken all necessary repairs of weak spots identified by the ILI, then the company has a strong basis to argue other factors or influences caused the leak, which then become the most likely causes of the failure. In the alternative, the company at a minimum can legitimately argue that it did everything possible within the confines of existing human technology and the leak was genuinely an anomaly.

A Best Practices approach to an ILI IMPbased program should:

1. Ensure that the correct technology tool is utilized for the anticipated target pipeline defect; MFL technology may be the selected tool for detection of specific corrosion wall loss geometries, however, it should not be the selected tool if the pipeline has experienced failures due to pipe wall crack defects.

2. Create a pipeline operator-based Request For Quotation (RFQ) document that:

a. Summarizes all pipeline operating parameters and characteristics, including pipe steel grades, wall thickness, diameters, product flows, product temperatures and pipeline geographic characteristics.

b. Outlines the target schedule of activities, based upon logistical and product delivery requirements.

c. States expectations relative to final reporting and deliverables.

d. States the requirement to validate all stated POD and POI tolerances for all involved pipe diameters and wall thicknesses, through pull-testing programs, component bench testing or previous documented inspection results. Identifies the minimum reporting requirement to be provided for each type of defect.

e. Allows for auditing of data by pipeline operator representatives throughout the program.

f. Provides a well-defined criteria and signature approval process for field acceptance of ILI data.

g. Summarizes signal response interpretation and call-out requirements that were in application with DOT guidelines and ILI inspection tool reporting tolerances.

3. Ensure that ILI reporting is validated through a series of excavation and pipe examinations as conducted by independent certified nondestructive examination (NDE) personnel and results are clearly documented.

4. Ensure that validation reporting is compared to ILI technology-stated accuracy, detection and identification tolerances and that discrepancies, if any, are noted and addressed.

5. Ensure that the selected ILI technology POD, POI and accuracy tolerances are accounted for within any subsequent excavation and repair programs.


It is not the objective of this two-part series to advocate that the potential for litigation should be a primary component within the IMP decision-making process. Public safety, regulatory requirements and pipeline operating conditions and budgetary considerations should always be the governing factors that control pipeline IMP development and implementation.

Intense scrutiny of pipeline pre-failure and post-failure decisions are, however, an inevitable follow-up to any catastrophic pipeline incident and will form the basis for any litigation action that may occur.

It is the intent of the authors to create an awareness that such scrutiny, while focusing on adherence to regulatory requirements, will almost certainly include examination of decisions and actions undertaken on the basis of "using all of the knowledge and technology at one's disposal to reduce risk and ensure continued pipeline safe operation."

Referred to within this article as the "Best Practices Gap," litigation expert witness examination of decisions and actions based upon this criteria is almost certain to reveal weaknesses in any pipeline IMP no matter how well thought out or implemented. Hindsight is, after all, 20/20.

Pipeline companies must however, confront the realities involved with litigation and the accompanying post-failure examination process. Application of a Best Practices Gap analysis within the pipeline IMP process will not only diminish the risk of a catastrophic incident but will also serve to lay a solid foundation for responding to the question "What could you have done better?"

Authors: Phillip Nidd has more than 30 years of technical consulting experience relating to pipeline integrity assessment, operation and rehabilitation of crude oil, gas, chemical and products pipeline transportation systems. He has provided pipeline integrity and rehabilitation consultation to major oil and pipeline transmission companies on a global basis including management of projects within the U.S., Canada, Russia, Argentina, Brazil and Ecuador.

Anthony Sammons is an attorney with Woodward, Hobson & Fulton in Lexington, KY who concentrates his practice in the areas of product liability, complex litigation, and appellate advocacy. He has represented a number of national and multinational companies in the manufacturing, transportation and pipeline industries. Much of his recent practice has been focused in fire and explosion litigation. He is licensed to practice in Kentucky, Tennessee and Mississippi.

Jim Towers received a B.S. degree in general engineering from Texas A&I University in 1970, (now Texas A&M, Kingsville, TX). Jim has more than 37 years of diverse experience in the planning, permitting, construction, operation, and maintenance of crude oil, gas, chemical and products pipeline transportation systems onshore and offshore in the U.S., Canada, Azerbaijan, Russia and Kazakhstan.
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Title Annotation:Part Two
Comment:Litigation implications of pipeline integrity management practices.(Part Two)
Author:Nidd, Phillip; Summers, Anthony; Towers, James C.
Publication:Pipeline & Gas Journal
Geographic Code:1USA
Date:Sep 1, 2007
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