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Pipeline Integrity: Program Develpoment, Risk Assessment and Data Management

Bruce R. Nelson, P.E.
Gas Distribution Manager, Montana-Dakota Utilities Co.
400 North Fourth Street
Bismarck, ND 58501
Telephone: 701.222.7784, Fax: 701.222.7853
Email: bruce.nelson@mdu.com


Abstract
The Office of Pipeline Safety (OPS), Research and Special Programs Administration (RSPA) of the US Department of Transportation (DOT) intend to issue pipeline integrity management program requirements for gas transmission pipeline operators. These integrity management program requirements will be issued as part of a two-step process. The first part deals with the definition of High Consequence Areas (HCA) and was issued on August 6, 2002. The second part deals with the requirements for the implementation of a Integrity Management Plan (IMP), and is anticipated to be issued by OPS as part of the final integrity regulations in 2003. Gas transmission pipelines that “affect” HCA’s will require inspection under an operator-developed IMP. This paper presents Montana-Dakota Utilities Co.’s process for integrating these new regulatory requirements within its complex, multi-company, corporation to both efficiently and effectively maintain compliance with DOT’s proposed pipeline integrity rule. Montana-Dakota’s methods include the use of a team approach and Geographic Information System (GIS) technology to enhance the cost effectiveness of its process that will cover over 3,300 miles of DOT classified gas transmission pipeline.

Company Background
MDU Resources Group, Inc (MDU) started in 1924 as a small electric company along the Montana-North Dakota state line and added a 50-mile gas line to fuel an electric power plant. Today, with a continuing growth strategy, 80 companies and approximately 10,000 employees comprise MDU. We have 2.2 billion in revenues and 2.6 billion in assets and operate in 42 states including, Alaska and Hawaii, and in the Gulf of Mexico, United Kingdom and recently Brazil, South America.

MDU Resources Group, Inc. (MDU) provides energy, value-added natural resource products and related services that are essential to our country’s energy, transportation and communication infrastructure. MDU includes electric and natural gas utilities, a natural gas pipeline, utility services, natural gas and oil production, construction materials and mining, and energy services.

Integrity Management Program
MDU companies own, operate and maintain over 4,500 miles of natural gas gathering, transmission, and distribution pipelines throughout seven midwestern states. These lines vary in pipe size, operating pressures, materials and installation vintage. The Integrity Management Program (IMP) being developed is a composite effort of all these companies. Since the integrity regulation is still being formulated, MDU’s plan is based on the Final Rule HCA definition, anticipated final integrity management program requirements, industry publications published by the Gas Piping Technology Committee, ASME and other industry related papers. Some of the data presented, was created to exemplify and illustrate how the elements of an IMP, including baseline assessment, integrity assessment inspection methodologies, i.e. in-line inspection, pressure testing, and direct assessment; interval periods; risk assessment; mitigation; and re-assessment actions.

For MDU, the first step in developing our Integrity Management Plan was the creation of a team of experts. We identified our internal core expertise and supplemented shortfalls with outside assistance to formulate a strong integrity management team. Our team is comprised of individuals from our three companies operating transmission pipelines, Harp Engineering, Inc, a consulting engineering company, and the James W. Sewall Company. Each entity brings special skills that we believe will result in an effective compliance plan.

Our Integrity Management Plan is an iterative process that involves data gathering and organizing and completion of the risk assessment of each threat and for each of our pipeline segments. The plan establishes a template for use in writing the site-specific options for cost effective data management, risk assessment and mitigation techniques.

MDU is a complex, multi-company, corporation and effective communication is an important part of our program. The communication plan follows a specific format to ensure that effective communications exist with our employees, the public, emergency responders, local officials and DOT jurisdictional authorities. This plan incorporates our existing emergency response procedures and builds on the relationships established through routine operations.

Pipeline systems and the environment in which they operate are dynamic. Our corporations’ goal is to provide high quality, cost-effective products and services to our customers while conducting business with “integrity” and with respect to all. Since operations continuously change, we developed a systematic process to ensure that prior to implementing changes to the pipeline system, design, operation, or maintenance functions, options are evaluated for their potential risk and cost impacts. This process also assures good communication and coordination between business units for alternative analysis, thereby achieving each business units’ strategic plan, while maintaining the corporations financial performance.

IMP Approach
Gas industry organizations have researched and identified two paths for operators to collect and effectively use data for risk assessment. The two paths are Prescriptive-Based or Performance-Based. MDU will use both the Prescriptive and Performance based methods depending on the pipeline segment. Based on the knowledge of our system, Performance- Based will be the primary method used. The two methods are:
  • Prescriptive-Based: limited, and no flexibility, but easier to implement. All of the specified data elements must be available in order to perform risk assessment. Elements include pipe attributes, construction, operational, and inspection.
  • Performance-Based – more options for: inspection intervals, inspection methods, mitigation and prevention activities. Requires more knowledge and data intensive, risk assessments and analysis to perform integrity assessment. Performance-Based IMP’s require the following:
    1. Description of risk analysis methods
    2. Documentation of all applicable data
    3. Documentation analysis for integrity assessment intervals, mitigation and prevention methods
    4. Documentation performance matrix that will effectively evaluate intervals, mitigation and prevention methods chosen.
IMP for Performance Process
Montana-Dakota’s IMP is based on the following six facets:
  1. Identify Pipeline Integrity Threats
  2. Data Identification, Collection and Integration
  3. Risk and Integrity Assessment
  4. Develop Integrity Management Plan
  5. Mitigation Strategy
  6. Continuing Assessment
A. Identify Pipeline Integrity Threats
The identification, management and assessment of threats to a pipeline are key components of an Integrity Management Plan. Therefore, identification of threats becomes the first step in the process. These threats are numerous, with significant threats to particular pipeline segments, and the commensurate risk they impose, being considered in determining an overall approach to integrity management.

In the threat phase, pipeline segments are identified. We defined operating pipeline segments as a pipeline system that connects a primary gas source to a primary gas delivery point or from major pipeline facilities such as valve – valve or pig launcher – pig receiver, etc. This differentiates operating segments from High Consequence Areas (HCA) segments.

After identifying each pipe segment, High Consequence Areas are located, based on OPS’s HCA rule. It is essential to recognize the impacts of threats that exist in a HCA segment versus elsewhere on the operating segment. This is particularly critical in the mitigation step, where it is imperative to understand the condition of the pipeline segment extending beyond the HCA, but within the specific operating pipeline segment.

A High Consequence Area or HCA is defined as areas where the potential consequences of a gas pipeline accident may be significant or may do considerable harm to people or their property.

The OPS definition includes:
  • All class 3 & 4 locations, and
  • Areas where the pipeline is within 300, 660 or 1000 feet of a building occupied by person who are confined, or are of impaired mobility, or would be difficult to evacuate, and
  • Areas where the pipeline is within 300, 600 or 1000 feet of a building or outside area where 20 or more persons congregate at least 50 days in any 12-month period.
OPS’s HCA definition takes into consideration the area potentially affected by a pipeline rupture and subsequent ignition and fire. This heat affected zone is based on GRI Report: GRI-00/0189. The C-FER model equation is:



MDU’s case study is an eight-inch pipeline, operating at 500 psig and in a Class 3 area. Therefore, the segment falls within the 300 foot HCA rule criteria.

Once the HCA’s are identified, we focus on threats. The demands on the pipeline system and threats to pipeline integrity are constantly changing. The types of threats to a pipeline are numerous and the mechanics of failure may be time dependent, stable and time independent. Time dependent is external and internal corrosion, and stress corrosion cracking. Stable is manufacturing related defects, welding/fabrication defects and equipment. Time independent threats include items such as third party damage, incorrect operations, weather related and outside force.

The case study considers the specific threats of defective girth weld, defective pipe, earth movement, equipment malfunction, erosion, excavation damage, external and internal corrosion, hydrogen induced cracking (HIC), hydrogen induced damage, pipe seam defects, stress corrosion cracking (SCC) and vandalism. Through system knowledge, we eliminated threats such as defective pipe and seam defects as this should have been discovered during the original hydrostatic test or during the manufacturing process.

B. Data Identification, Collection and Integration
The next step in this integrity process is performing a resource inventory of existing pipeline system data. The amount and type of data to support risk assessment will vary depending on the threat being assessed. Planning for collection and maintaining data is required. This can be accomplished by use of GIS, database, spreadsheets, etc. Our Company is using a combination of GIS, Class Location, Walking Survey software, the PODS data model in GeoDatabase format, with data management services provided by the James W. Sewall Company. A key step in managing data involves correlating data to a common reference and maintaining quality control measures. Both of these are in place within our IMP.

Below are primary data categories and some potential data sources:
  • Material Information – pipe attributes.
  • Construction and Installation Data - repair methods, hydrostatic tests.
  • Corrosion Control History- internal and external..
  • Operating Data - gas composition, pressures, temperatures, pipeline liquids.
  • Leak and Failure Data - leak history; pipeline condition reports, failure data.
  • Excavation Activities - class location, right-of- way encroachments.
  • Prior Assessment Data- bellhole inspection, in-line inspection.
  • Other data – maps, alignment sheets, digital photos, stationing data.
After conducting a resource inventory, data integration begins. Layering of data provides ability for an integrated analysis. A key in the analysis is spotting changes and entering new data into the assessment process. Integration can be accomplished in many different ways, i.e. manual, manual within GIS, or automatic within GIS. We are employing primarily automated within GIS methods, however, manual intervention is imperative to better comprehend certain data and test results. This integration process helps to prevent reviews of incorrect areas of interest with resulting incorrect conclusions.

C. Risk and Integrity Assessment
Risk is defined as the product of likelihood or probability of failure and consequence. Gas pipeline incident data has been analyzed and classified by the Pipeline Research Committee International into 22 root causes (threats). Except for one class identified as “unknown”, the remaining 21 should be considered, when applying the performance-based approach.

Risk assessment provides a method for prioritization of pipeline segments, for scheduling integrity assessments and for mitigation actions. The methods used by operators to assess data and prioritize pipeline segment integrity concerns range from the collection of operational knowledge through the use of probabilistic models. Two types of models for prioritization are the index model and probabilistic model. We chose the index model that identifies critical factors and ranks their relative importance. The relative importance of each factor is quantified by giving it a weighted value.



The assessment of the identified threats to the pipeline are expressed in the product of the likelihood of the threat causing a pipeline breech with the consequence of the breech. Using the threats identified as part of the IMP, the Risk Model allows for the prioritization of response to the risks along the operating pipeline segments. The use of GIS technology permits central storage of the risk data, complex analysis of the overlapping identified threats and the identification of a mitigation strategy to efficiently uses the company’s resources.

The development of a Risk Management Program begins with the development of standards and practices that are acceptable for the Company and the pipelines it operates. Based on the identified threats, or risks, to the pipeline, the screening methodologies and intervals are established. Screening methods can include patrols and locate requests, inline- inspection, and direct assessment. The interval between the screenings is based on the pipe itself and its operating parameters as well as the specific risk involved. These include pipe diameter, wall thickness, material, weld type, age, depth-of-cover, cathodic protection, soils, pipe coating, and expressions of how often the pipe is patrolled and tested, as well as how well the pipe is protected from third-party damage.

Weighting factors are based on accepted industry standards and operating experiences with the pipeline. Consequences are expressed in terms of the potential amount of product lost, property damaged, and number of people injured or killed. Once quantified, the mitigation strategies are applied, starting with those segments that have the highest identified risk.

Once the risk assessment is made, the appropriate integrity assessments are selected and conducted. The integrity assessment methods are in-line inspection, pressure testing or direct assessment. More than one integrity method may be used to address all the threats of a single pipeline segment. The following is a brief description of each integrity assessment method.

Direct Assessment
Direct assessment is performing inspections on active pipelines without removing them from service. It is an integrity assessment method that uses a structured process by integrating knowledge of the physical characteristics and operating history of a pipeline system or segment with the results of inspection, examination and evaluation to determine a level of integrity. There are techniques for external corrosion direct assessment (ECDA) threats and internal corrosion direct assessment (ICDA) threats.

The majority of the MDU’s pipeline segments will rely on the Direct Assessment (DA) technique due to a number of facilities anomalies that exist in the pipeline system. Such anomalies include plug valves and compression style fittings, short radius elbows, etc. that preclude the use of alternate assessment techniques.

Inline Inspection
There are a variety of commercially available in-line inspection (ILI) tools. Some are geometric tools (Caliper pigs) that identify geometric shapes such as dents and bends in the pipeline. With advanced Caliper style tools, operators can virtually re-build a set of alignment sheets with the electronic data recovered from this tool. Next, are ultrasonic and magnetic flux ILI tools capable of inspecting the pipe wall. They come in the form of low and high-resolution tools. A magnetic field and sensors measure fluctuations in the magnetic field. These fluctuations come from changes in wall thickness from corrosion, gouges or fittings. They will also detect casing or metallic items near the pipeline. This data is graphically plotted for interpretation.

Ultrasonic ILI tools require a liquid couplant and therefore may not be an effective assessment tool. for gas pipelines.

Pressure testing
Pressure testing is raising a pressure substantially higher than the operating pressure and holding for a set time period to ensure there are no remaining weak links in the pipeline. The pipeline safety code allows for several test mediums ranging from natural gas to inert gases or water. Ideally, transmissions lines are tested to a pressure ranging from 90 to 99% of the SMYS and held for a period of not less than 8 hours.

Other – interviews, etc.
The final method found to be very valuable in MDU’s IMP process is direct interviews with employees. Often, information available to field personnel is not reported or is not effectively recorded. Generally, the senior employees will identify many of the same indications as determined by the above assessment techniques.

D. Develop Integrity Management Plan
The integrity management plan is developed after gathering the data and completing the risk assessment for each threat and for each pipeline segment or system. There are two plan approaches a company can use for its integrity management plan. These two approaches are the Prescriptive-Based and Performance-Based. As previously discussed, MDU plans to use both depending on availability of data. However, the Company is currently focusing its IMP program on the Performance-Based approach, subject to the Office of Pipeline Safety final integrity management requirements.

Development of cost effective techniques to prioritize pipeline segment integrity concerns, ascertained from the knowledge acquired through the performance approach, can be achieved through risk models.

MDU is using a derivative of the index model that involves identifying critical factors and ranking the relative importance of these factors. This index modeling process includes interjection of subjective assessment, engineering knowledge, statistical analysis, and mathematical modeling.

Once the segments are prioritized according to perceived risk, mitigation action will be implemented for each pipeline segment. Cost estimates for responsive and effective mitigation techniques are predicated on four major categories: monitoring; inspection and investigation; remediation; and education.

After MDU collects, analyzes, assesses risks, prioritizes and takes mitgative actions, periodic evaluations will be performed to determine the success of the integrity assessment techniques, pipeline repair activities, and mitigate risk control activities. Mandatory reassessment intervals will be prescribed depending on the compliance method used and intervals allowed under the regulations. Proposed interval periods range from five years for direct assessment to 15 years for pressure testing and in-line inspection. Due to the existing configuration of MDU’s transmission system, MDU is using direct assessment as its primary compliance method. Therefore, a five-year interval period is contemplated. However, MDU’s IMP will be modified as new assessment technologies, such as the three-in-one pig or GIS data, i.e. more refined ortho-digital photography, assessment software become available.

E. Mitigation Strategy



MDU’s goal is to match mitigation techniques to pipeline segments in ways that optimize available resources (money, time and personnel) to enhance system-wide pipeline integrity. This is accomplished by matching mitigation tools and techniques to threats of the individual pipeline segment. No one tool or approach is appropriate for all applications. Mitigation techniques include four categories:
  1. Monitoring – Examples of mitigation tool are patrols that are more frequent, leak surveys, and pipe-to-soil potential surveys.
  2. Inspection and investigation – Mitigation tool examples are close-interval surveys, bellhole examinations, radiographic examination, ultrasonic examination, pressure testing, geometry pigs, and in-line inspection (corrosion detection or metal loss pigs).
  3. Remediation – Examples of mitigation tool are re-coating (reconditioning), additional cathodic protection, anomaly repair, pipe replacement, change in alignment, reduction in operating pressure, and erosion control measures.
  4. Education – Mitigation tool examples are notices sent to landowners along the pipeline's rights-of-way, public education efforts, damage prevention programs, and coordination efforts with public officials.
It is our integrity teams responsibility to take current practices and tools and maximize their efficient use, while searching for other tools that will reduce cost. As we work through the integrity management requirements set forth by OPS, we will examine and integrate technological advances combined with life cycle cost analysis to determine which scenario provides the greatest value to MDU while ensuring regulatory compliance.

F. Continuing Assessment
MDU’s IMP process includes provisions for continuing review of each pipeline segment in terms of threats, risk factors, mitigation techniques, and prevention methods combined with monitoring of legislative and regulatory activities.

MDU’s IMP entails keeping abreast of additional information, new developments and commercially available mitigation techniques through participation in industry associations, such as AGA, ASME, GITA and other means. In July 2002, MDU conducted a pipeline integrity survey, with the assistance of AGA to determine current integrity activities of pipeline operators. Ninety-four (94%) of the respondents indicated they are monitoring legislative activity and 81% performing some level of a integrity pre-planning phase.


Conculsion
These new pipeline integrity regulations will require responsive action by transmission pipeline operators, like MDU, that include the requirement to develop and operate under an Integrity Management Program (IMP). MDU is using the Performance Based process as its primary approach, comprised of these steps:
  • Identify Pipeline Integrity Threats
  • Data Identification, Collection and Integration
  • Develop Integrity Management Plan
  • Risk Assessment
  • Mitigation Strategy
  • Continuing Assessment
Because of the diverse nature of the MDU Companies, it is essential for our corporation’s pipeline companies to communicate with one another thereby creating efficiencies and maximizing synergies including intellectual knowledge and corporate assets across corporate lines. We accomplished this by assembling a team with subject area experts from within the respective companies. We also recognize that it would be more efficient to use additional assistance for non- core functions, such as we are using James W. Sewall Company for data management, to allow us to focus on our core business of being energy providers. We believe our Integrity Management Program approach will produce benefits for our corporation in four ways.
  • Improved capital asset management
  • Sharing labor expenses
  • Reduced mobilization expenses and volume discounting
  • Reduced risk of litigation
MDU is committed to providing value-added natural resource products and related services that exceed customer expectations. To achieve this expectation we are guided by commitments to our customers, stockholders, community, environment, ethics and employees. Further, MDU’s strives to operate and maintain a safe and reliable pipeline system in accordance with all applicable codes and regulations.

Rererences
  • American Gas Association, November 18, 2001, Review of Integrity Management for Natural Gas Transmission Pipelines, An ANSI Technical Report by the ASC GPTC Z380.
  • Gas Research Institute, GRI-00/0189, December 2001, A model for Sizing High Consequence Areas Associated with Natural Gas Pipelines, prepared by C-FER Technologies.
  • American Society of Mechanical Engineers, 2002, Supplement to B31.8 on Managing System Integrity of Gas Pipelines. James W. Sewall Company, 2002, Alignment Sheet Generator™ and other reference materials.
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