Direct assessment, data integration important in establishing pipeline integrity

Direct assessment is a process through which an operator can integrate knowledge of a pipeline system's physical characteristics and operating history with the results of diagnostic testing performed to determine the integrity of the line pipe.

The DA process is further validated by physical inspection of the line pipe to verify that conditions predicted by the integration of knowledge and diagnostic testing were actually found upon direct examination.

An initial goal of the DA program was to develop an integrity-assessment process that was equivalent to in-line inspection or pressure testing.

It was immediately recognized, however, that such a goal was incomplete, at best, because in-line inspection and pressure testing themselves are not equivalent. Each technique assesses pipeline integrity in a different manner and provides a different type of integrity assurance.

With regard to external corrosion, pressure testing provides a measure of assurance against a limited set of relatively large defect geometries at a given pressure. In-line inspection provides assurance against a broader set of defect geometries, but suffers from uncertainties from errors in data recording, interpretation, and reporting.

Pressure testing and in-line inspection, therefore, provide different integrity benefits, even though both seek to provide an equivalent level of integrity assurance. The same is true for direct assessment.

New US state and federal pipeline integrity-management regulations state that acceptable technologies for assessing pipeline integrity include in-line inspection and pressure testing, with DA considered on a case-by-case basis or within "other technologies." None of these technologies individually is capable of fully characterizing all potential threats to pipeline integrity.

Therefore, the appropriate technology should be selected after consideration of risk-assessment results, the type or types of anomalies likely to be present, the method's validity under current conditions, and its practical feasibility.

Several current gas-pipeline-industry-sponsored initiatives aim at validating DA, showing how under certain circumstances it can provide an understanding of the condition of line pipe equivalent to in-line inspection and pressure testing as part of an operator's baseline or continuing integrity-assessment plans.

DA initiative

On the national level, three committees of the Interstate Natural Gas Association of America are addressing both pipeline industry and regulatory agency DA objectives.

These committees are working hand-in-hand with the Gas Technology Institute (GTI), the US Office of Pipeline Safety (OPS), state agencies, and vendors as part of a joint industry-government initiative to validate application of DA for assessment of external corrosion, internal corrosion, and stress-corrosion-cracking-related pipeline integrity threats.

NACE International is currently preparing an internal-corrosion DA standard using a proven gas-flow model that identifies areas susceptible to internal corrosion against in-line inspection results in what are considered normally dry-gas systems. In addition, NACE has formed a stress-corrosion-cracking DA task group.

The American Petroleum Institute and the Pipeline Research Council International Inc. (PRCI) are currently considering similar DA validation projects among hazardous liquids pipeline operators.

INGAA's external-corrosion DA (ECDA) committee has initially undertaken a DA validation project designed to determine the effectiveness of external-corrosion DA technologies under various operating conditions. OPS is co-funding this project and providing project-management oversight, while state agencies are providing data-management oversight.

After evaluation of all data-integration tools available on the market, INGAA's external-corrosion DA committee selected Baseline Technology's Pipeline Information Control System (PICS) as the application to manage all pipeline-data gathering, storage, integration, reporting, and analysis.

Currently, 16 interstate gas pipeline operators are participating in the external-corrosion DA validation project by contributing data for a segment of line pipe. Data sets associated with pipe attributes, right-of-way conditions, and in-line inspection caliper and magnetic-flux-leakage (MFL) tool runs were all integrated, then spatially normalized and correlated with multiple aboveground DA techniques capable of isolating external-corrosion anomaly locations.

This month, INGAA and GTI are to deliver a final industry report "Development of External Corrosion Direct Assessment Methodology."

Preliminary data integration outputs show a significant correlation of DA-related data-set variances with recorded in-line inspection anomaly locations. It should be noted that additional field data by the American Gas Association (AGA), companies that make up the New York Gas Group, and INGAA in the coming year will complete and enhance existing data sets.

The external-corrosion DA process effectiveness is currently being evaluated by comparing DA and in-line inspection anomaly indications with actual nondestructive examination defect measurements obtained through direct examinations (bell-hole inspections) at locations calculated along the segment's 3D virtual pipeline model centerline distance.

By January 2002, GTI, Battelle, Paragon Engineering Corp., Houston, and CC Technologies Services Inc., Dublin, Ohio, had completed an independent assessment of all DA project results, justified the statistical basis for validating an external-corrosion DA process, and identified conditions when it is appropriate to apply external-corrosion DA to achieve an equivalent understanding of the line pipe's integrity.

INGAA intends to address the processes surrounding DA technology by working with NACE, the American Society of Mechanical Engineers (ASME), API, PRCI, and GTI to develop a comprehensive set of DA-related guidelines.

These guidelines will lead to pipeline-industry standards and recommended practices covering the DA processes of information management, data integration, risk assessment, integrity management, survey technique validation, and personnel qualifications.

Texas DA initiative

On the state level, the uncertainty over DA as a viable integrity-assessment alternative was evident at a July 19, 2001, Texas intrastate pipeline operator workshop attended by the Texas Railroad Commission (TRC).

Most operators present indicated their intent to identify specific intrastate pipeline segments (up to 50% of systems) where DA would be the baseline integrity-assessment method selected in advance of the federally mandated Feb. 1, 2002, deadline for hazardous liquids operators and first quarter 2003 deadline for gas pipeline operators.

For Texas intrastate lines, however, all DA and other technology assessments require a hearing and approval by the TRC before commencing. At the July 19 meeting, TRC's Pipeline Safety Director Mary McDaniel asked the major operators of about 150,000 miles of jurisdictional intrastate oil and gas pipelines in Texas to validate their DA technologies-in Texas.

The INGAA initiative's external-corrosion DA validation project approach and verbal TRC recommendations make it clear that operators proposing to perform baseline or continuing integrity assessments using DA technologies in Texas should consider:

• Validating DA technologies before presenting DA justifications on similar Texas pipeline segments.
• Managing all data electronically within a tool that can demonstrate accurate data integration.
• Defining all industry-accepted DA-related processes within the framework of the company's IMP plan.
• Establishing personnel training requirements (under the US Department of Transportation's Operator Qualification rule) covering DA equipment use, data-management application use, and related processes.
• Documenting DA technology justifications for each similar segment.
• Presenting preliminary DA technology justifications to the TRC's Pipeline Safety Division before final presentation for approval at a TRC hearing.

McDaniel also clarified that DA technologies will remain an acceptable integrity-assessment alternative in Texas, independent of national regulatory requirements, and that the TRC will take the lead nationally on evaluating DA technology justifications.

The commission's current expectation is that DA technology justification must be approved within that operator's pipeline system and integrity plan.

Many Texas pipeline system laterals are not looped, making it unfeasible to use in-line inspection or to pressure test them. Therefore, DA may become an economic lifeline to save a number of Texas intrastate pipeline operators from the rapidly escalating costs of taking the line out of service and modifying it in order to conduct in-line inspection and pressure testing.

Several Texas-specific issues will also affect an operator's selection of DA as the appropriate integrity-assessment technology. These included potential interruption of critical gas supplies, use of water within drought areas, and proximity to drinking water aquifers.

What is it?

Like most other assessment technologies, DA is not without limitations in its application. Depending on available pipeline information and the internal and external environmental conditions under which the line pipe has been operating, DA techniques may provide all of the information needed to determine the line's integrity.

DA may also be used in conjunction with, or as an enhancement to, the findings of other assessment technologies such as in-line inspection and pressure testing. Regardless of where DA is applied, following the DA process is one of the most valuable tools an integrity manager has to enhance the safety of his or her pipelines.

The process of DA, as described presently and in the accompanying box on this page, may occur in the future, at coating faults or other corrosion-protection anomalies. Two or more complementary indirect inspections are required over the entire pipeline segment to improve the reliability by which corrosion-protection anomalies are detected under the wide variety of conditions that may be encountered along a right-of-way.

The NACE ECDA process follows four defined steps:

• A preassessment step collects and integrates historic data to determine if ECDA is feasible, defines ECDA regions, and selects complementary indirect inspection tools. The types of data that are collected include information on design, materials, construction, environment, corrosion protection, previous surveys, previous inspections, previous integrity evaluations, and maintenance actions.
• An indirect inspection step requires aboveground inspections to identify locations where corrosion activity may be occurring, may have occurred, on the pipeline right-of-way. Consistent rules are required for defining potential corrosion-protection anomalies based on the inspection data.
• A direct-examination step includes additional analyses of the indirect-inspection data to prioritize sites for excavations. The data from the indirect measurements are combined with previous data to prioritize corrosion-protection indications as immediate, scheduled, or monitored (similar to the categories used in ASME B31.8S Integrity Management Plan Supplement).

These analyses are followed by pipe-surface examinations, measurements, remaining-strength analyses, "like-similar" evaluations, and mitigation of corrosion protection problems. Minimum requirements are included for determining how many excavations are required and for assessing the impact of external corrosion on the structural integrity of the pipeline.

• A postassessment step covers analyses of the data collected from the previous three steps to assess the effectiveness of the ECDA process and determine re-evaluation intervals. In addition, this step covers validation-dig requirements and measures required for monitoring the long-term effectiveness of ECDA.

Implementing ECDA

First, an operator must determine that DA is a feasible and appropriate integrity-assessment method for the segment of line pipe being evaluated.

Its feasibility is a function of the data, resources, and cost associated with completing the DA process on the segment. Its appropriateness is a function of the integrative risk-analyses results and validity of DA case studies completed for similar line pipe and conditions within the company's IMP plan.

A comprehensive integrative DA analysis begins with development and field validation of a unique risk algorithm that captures industry and the company's risk beliefs. In the case of indexing or probabilistic models, the company-specific DA algorithm acts as a filter of integrated, spatially accurate, risk-factor data, including pipe characteristics, environmental factors, operating conditions, leaks, land use, and protective measures.

Evaluation of the model's validated risk results will determine what additional data need to be gathered and integrated into the model, what enhancements to the risk algorithm need to be made, what integrity threats are likely to be significant, where significant integrity threats are likely to be present, and what assessment methods are best suited to characterize pipe condition.

Refer to ASME B31.8S or API 1160 for additional details on the analysis of risk-related data.

After the risk results are evaluated, DA can be identified as a valid primary integrity-assessment technology for areas of concern or trouble spots, or as a supplementary data-gathering and integration method, and is included within multiyear baseline assessment plans and associated budgets if its benefit-cost relationship is favorable over alternate in-line inspection and pressure testing technologies.

Preassessment analysis of the initial evaluation should answer the following questions:

• Will DA be applicable?
• What threats are significant?
• Where are threats likely to be present?
• What tools are best suited to characterize the problem?

Indirect examination

While aboveground examinations or surveys are made of the pipeline using a minimum of two or more DA technologies, areas are identified where coating defects (i.e., holidays, or disbondment) are likely and active corrosion may be present.

The use of DA technologies in an integrated process includes analysis results from new tools such as DC (or AC) voltage gradient (DCVG or ACVG), pipeline-current mapper (PCM), and coating attenuation (Corrosion-Scan).

Over the years, a variety of equipment and numerous aboveground surveys (indirect examinations) have been developed to measure various parameters related to the condition of buried pipelines.

For many reasons, these techniques were generally used as standalone tests to determine pipeline integrity. Extensive testing in the use of multiple techniques has indicated, however, that the assessment value of overlapping results is significantly greater than the individual result's value.

Selecting complementary DA techniques based on the likely threat, such as time-dependent external corrosion, enables the strengths of one technique to cover the limitations of another.

In addition, the DA process permits integration of large amounts of integrity-related knowledge and data into a diagnostic tool that can be used accurately to determine the location of line pipe anomalies, as well as to prioritize remedial activities.

Aboveground survey techniques or indirect examinations should identify and find coating faults (holidays, disbondment, and deterioration) and corrosion anomalies (active and inactive).

Direct examination

Direct examination of the line pipe's condition requires that excavations (bell holes) be used to expose the pipe in areas suspected to be experiencing active corrosion. Afterwards, the pipe is examined visually, and such other evaluative techniques as ultrasonic testing determine remaining wall thickness.

Bell-hole excavations for direct examination should include all pertinent information related to the integrity threats and correlate well to the aboveground survey.

Direct examinations reveal coating and pipe condition. The pipe can be visually and ultrasonically inspected for corrosion, damage, and defects. Direct examination also permits monitoring of cathodic protection at the pipe's depth and analysis of soils and other factors: pH, soil resistivity, bacteria, and chemicals.

Postassessment

Information from all available direct-examination excavations is integrated and normalized to determine whether and where additional bell holes should be dug to seek out additional potential active corrosion.

It is the integration and analysis of such pipeline data as environment, history, operating conditions, flow modeling, and a combination of survey techniques that identify any additional areas of concern along a pipeline and determine the maximum remaining defect severity.

The process of post-assessment requires integration of the following information and data:

• Assemble and integrate all previous and present excavations, aboveground or below ground surveys and attributes, operations, land use, cathodic-protection history, and construction information.

In addition, integrate, analyze, and assess all data to determine if additional surveys or bell holes are required, any false negatives or positives, and the actual condition of the pipeline.

Finally, prioritize remedial activities through "Like-similar analysis." Focus on critical anomalies with a view to whether the line is in a defined "high-consequence area" (HCA), a non-HCA, or an area of no concern.

Data integration

Data integration (Fig. 4) provides the means and information necessary to produce an effective integrity-management program.

Because data come from a variety of sources, internal and external, within an operating company, they must be correlated to allow the operator to assess the system in a holistic approach. Data come from such sources as single-user databases, spreadsheets, paper forms and records, and other company database systems.

Today, we stand at a crossroads in computer technology where data-management systems are capable of using data integration in analyzing a pipeline system in its entirety. Integrity management can be used better to manage risk and prioritize remedial activities.

There are, however, pitfalls to data integration.

Missing or incomplete data have always been an issue within companies. A quality-control process needs to be part of the overall program to bring the data to acceptable company standards.

Storage of data in different cities, offices, and other off-site locations is improving because of the broadband networks available. Speed, however, can sometimes be affected in different parts of the country.

Various data formats with different vendors, systems, and databases are now being recognized and addressed with open database architecture.

Engineering station numbers, decimal mile posts, mile-plus-feet, metric, GPS coordinates, projection systems, chainage, etc. have roiled companies to the extent that none wants to compromise on its methods of measurement. Some type of standard in data integration, however, is recommended for the industry.

Managing data effectively requires a common reference for data correlation. This reference will provide multiple and various data sources to be correlated to the pipeline's centerline. A geographic information system can provide the attribute data needed for these points.

Therefore, direct assessment or in-line-inspection anomalies can be compared and evaluated. And, the results of multiple aboveground and belowground surveys can be tied to a common reference. This type of data is called "floating data."

Tying floating-type data to GIS fixed-point data has always been a challenge, especially when different measurement systems are involved. It then becomes very important that the systems match so that the correct anomalies are addressed. Otherwise, unnecessary digs or the wrong anomaly may be excavated, while the one that affects the integrity of the line is missed.

Data information and integration systems will improve anomaly locations and accuracy, thus enhancing integrity in the eyes of the public and OPS.

Proactive approach

DA is designed to be proactive and prevent lapses in pipeline integrity rather than respond to them. This application process can locate coating anomalies well in advance of corrosion, leaks, or failures. In addition, corrosion anomalies can be located and determined to be active or inactive.

Like-similar analysis can determine critical areas of concern before integrity breaches occur on a pipeline system. Through the use of data integration and the results of direct examinations, DA technologies can be refined and enhanced to predict potential integrity problems. Also, defect modeling can be used to determine the safe operating conditions and reassessment or inspection frequency.

Areas of concern identified through DA are subject to direct examination just as with in-line inspection. The same criteria are applied to DA using industry standards such as the remaining pipe strength of corroded pipe.

The DA process goes one final step further, however, by examining selected areas of no concern. This will validate the DA process to completion. This extra step allows the operator to use DA results confidently to manage the pipeline system safely and provide input for prioritizing remedial activities.

The goal of the DA program is to develop an integrity-assessment process equivalent to in-line inspection or pressure testing. But in-line inspection and pressure testing are themselves not equivalent, and ECDA mandates effective management and mitigation of the effects of corrosion.

ECDA performs a function different from in-line inspection or pressure testing by providing an equivalent level of understanding of pipeline integrity with respect to external corrosion. This is accomplished through the use of data integration that provides the means and information necessary to produce an effective integrity-management program.

The authors

Joe L. Pikas, at the time of this presentation, was risk assessment coordinator for Williams Gas Pipelines, Houston. He has since joined MATCOR, Sugar Land, Tex. Pikas was with Williams for more than 35 years and chairs INGAA's external corrosion DA committee.

Bruce Beighle, at the time of this presentation, was vice-president of risk management and regulatory affairs and chief operating officer for Baseline Technologies Inc., Calgary. Since then, he has joined WKM Consultancy LLC, Austin, Tex., as a risk management consultant and general partner, working from Boyd, Mont. Beighle founded Benchmark-Risk Management in 1996 before joining Baseline.

Based on a presentation to 82nd Annual Gas Processors Association Convention, Dallas, Mar. 11-13, 2002.

Definitions

49 CFR 195

No DA definition is provided within the new hazardous liquid pipeline integrity-management regulations under section 195.452 or Appendix C guidelines.

In the Dec. 1, 2000, Federal Register (Vol. 65, No. 232) Final Rule, "Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Operators With 500 or More Miles of Pipeline)" background Notice of Proposed Rulemaking, OPS stated: "To encourage innovation, the final rule also allows an operator to use other technology for the integrity assessment, if the operator demonstrates that an alternative technology can provide an equivalent understanding of the condition of the line pipe as the other permitted assessment methods."

Understanding that DA will be an alternative external technology used by many companies, OPS stated that "the 5-year integrity re-assessment period is not absolute. An operator may be able to justify an engineering basis for a longer assessment interval on a segment of line pipe, if the operator can support the justification by a reliable engineering evaluation combined with the use of other technology, such as external monitoring technologies, that provides an equivalent understanding of the condition of the line pipe."

49 CFR 192

A gas transmission pipeline integrity-management final rule (equivalent to 195.452) is expected by first quarter 2003. A DA definition and process are described in the June 27, 2001, Federal Register (Vol. 66, No. 124) Notice of Request for Comments, "Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines)" as "Direct assessment is a structured process for assessing pipeline integrity. While OPS focus on direct assessment at this stage is on assessing external corrosion, work is in process to explore its application to internal corrosion and stress corrosion cracking.

The process has four basic steps:

1. A comprehensive integrative analysis of risk factor data is used to determine whether direct assessment will apply, what threats are likely to be significant, where these significant threats are likely to be present, and what tools are best suited to characterize pipe conditionellipse .
2. An above ground examination is made of the pipeline using one or more direct assessment tools to identify areas where coating defects (holidays and disbondment) are likely to exist and whether or not active corrosion is likely to be present.
3. Excavation (digging bell holes) is used to expose the pipe in areas suspected to be experiencing active corrosion, then the pipeline is examined visually, and other evaluative techniques such as ultrasonic testing are used.
4. Information from all available excavations is integrated and generalized to determine whether and where additional bell holes should be dug to seek out additional potential active corrosion."

16.1 TAC Rule 8.101

A DA definition is provided in Texas' Apr. 10, 2001, "Pipeline Integrity Assessment and Management Plans for Natural Gas and Hazardous Liquids Pipelines" Final Rule as "A structured process that defines locations where a pipeline is physically examined to provide assessment of pipeline integrity. The process includes collection, analysis, assessment, and integration of data, including but not limited to the items listed in subsection (b)(1) of this section. The physical examination may include coating examination and other applicable non-destructive evaluation."