Frequently Asked Questions:

Q: This pipeline is almost 40 years old, how much longer can it safely operate?

A: Our analysis indicates a pipeline using line pipe of proper design and construction, withstanding a successful hydrostatic pressure test, maintaining adequate cathodic protection, and protected from outside force damage is capable of performing safely for well over 100 years and possibly indefinitely. Some of the causes of pipeline failure and preventive actions by the Office of Pipeline Safety (OPS) are listed below.

In-service pipeline failures, such as the Olympic June 10, 1999, failure, occur predominantly due to excavation damage resulting in mechanical damage, such as dents and gouges, in the pipe body. Mechanical damage can result in additional stresses weakening the pipeline and if significant cause it to fail. External corrosion resulting from inadequate cathodic protection can also cause in-service pipeline failures. Many hazardous liquid pipeline operators, with pipeline systems constructed prior to 1970 with low frequency electric resistance welded (ERW) pipe seams, experienced longitudinal seam failures attributed to cold weld (inadequate bond) and low fracture toughness.

An initial defect, such as those previously mentioned, must be present in a pipeline for it to fail due to cyclic fatigue. In many cases the initial defect is, or results in, a crack or crack like surface defect prone to growth due to pressure fluctuations. A fracture mechanics analysis for metal fatigue estimating the reliable safe life for a pipeline depends on a number of factors including the stress field surrounding a given defect. The stresses at a given defect can be higher than normal pipeline stresses and the magnitudes of stress are different within defects such as a dent, a gouge, and severely corroded region. Stable crack growth caused by pressure fluctuations, depend upon the pipe toughness, the pipe wall stress, crack size, and a fixed relation between the crack growth rate per each pressure cycle and the stress intensity factor related to a high stress field near the crack tip. Estimating pipeline life under normal operating conditions consists of determining the number of pressure cycles for an initial crack to grow to a critical crack size resulting in eventual pipeline failure. Estimating pipeline life in a pipeline with one or more cracks is a problem since the maximum size sub-critical crack under the highest stress may not be known. As previously mentioned, a pipeline such as Olympic given a defect without a significant stress concentration factor could operate safely well over a 100 years.

The Office of Pipeline Safety (OPS) Corrective Action Order requires the use of the best technology available for identifying and repairing the types of defects which could possibly grow over time due to cyclic fatigue and cause pipeline failure. Additionally, the OPS is a strong supporter of programs designed to prevent damage to pipelines during excavation activities resulting in the prevention of excavation imposed defects which can result in a pipeline failures. External corrosion related pipeline failures are less frequent because of pipeline safety regulations requiring the monitoring of cathodic protection systems identifying potential problems and taking remedial actions preventing metal loss which could eventually result in pipeline failure. The pipeline safety regulations require pressure testing of existing hazardous liquid pipelines with low frequency welded ERW seams that were constructed before the regulations went into effect demonstrating their integrity. If they are not pressure tested, the maximum operating pressure must be reduced to 80 percent of their previous test pressure or operating pressure, to provide an equivalent level of safety as a code based pressure test. Additionally, the OPS recently issued a Pipeline Integrity Management rule (Federal Register December 1, 2000, Volume 65, Number 232) requiring hazardous liquid pipeline operators to routinely assess and evaluate their pipelines for integrity threatening defects and repair all critical defects that, in the event of a leak or failure, could affect populated areas, areas unusually sensitive to environmental damage and commercially navigable waterways. You can preview this new rule at: http://ops.dot.gov/finalrule/491060p.htm

Q: The Olympic Pipeline has required excavation below the existing pipe in order to enact federally mandated repairs particularly where welders must access the bottom of the pipe. Since the soil can not be compacted directly below the pipe, is there a hazard posed by possible soil settlement?

A: The Olympic repairs to the pipeline typically are completed in short length "bell-holes" extending below the pipe to facilitate welding on the bottom of the pipe. Occasionally, longer length repairs are required and potential pipe settlement becomes a concern. To prevent undue stresses from being imposed on a pipeline during excavation it is necessary to provide support for free pipe spans based on engineering analysis. For the Olympic pipeline repair project additional support is provided for unsupported spans of 40 feet or greater by cradling the unsupported pipeline with sandbags. This is very conservative as calculations indicate Olympic's pipeline filled with water, heaviest commodity to be transported, could free span approximately 60 feet until additional support would be necessary. Correctly providing support for free spanning pipeline sections address concerns regarding soil compaction beneath free pipe spans such as the repaired pipeline sections. Soil compaction techniques are another method of providing support to the excavated portion of pipeline. Compaction techniques would require consideration for the soil beneath the pipeline if other measures for providing support to the pipeline free spans were not considered.

Q: What was the pressure in the pipeline at the rupture site at the time of failure?

A: To understand the pressure in the pipeline at the time of the accident, a series of hydraulic analyses were performed by Stoner Associates. These hydraulic analyses allow engineers to determine the pressure at different places along a pipeline system under various operating conditions. By re-creating the worst-case scenario of system pumps and valve closures that could have occurred during the June 10, 1999, incident at Bellingham, the hydraulic analyses indicate that the maximum pressure at the rupture site would have been 1,424 pounds per square inch gauge (psig).

Q: What was the maximum operating pressure for section of the pipeline that ruptured?

A: Title 49 Code of Federal Regulations §195.406 establishes the maximum operating pressure for each hazardous liquid pipeline. The pipeline safety regulations permit a maximum operating pressure of 1,456 psig at the rupture site. During a pressure surge like the one experienced on June 10, 1999, the regulations allow the pressure to reach 110 percent of the maximum operating pressure. For the pipe at the rupture site, this figure is 1,602 psig.

Therefore, the pipeline failure occurred at 32 psig below the pipe's maximum operating pressure and 178 psig below the maximum allowable surge pressure for the rupture site. The preliminary investigation indicates this is due to the mechanical damage in the ruptured pipe. The Office of Pipeline Safety is awaiting the NTSB metallurgical and incident reports to identify the official cause of failure.

Q: We understand that Olympic had run "smart pigs" before, yet their action did not prevent the accident at Bellingham. What are the measures that OPS is requiring Olympic to take to ensure that the smart pigs don't miss another weakened section of pipe?

A: Olympic ran the first "smart pig"--a low- resolution, conventional, first-generation, metal-loss internal inspection device- in its pipeline in 1981 and discovered that there were several external corrosion problems which Olympic corrected. This success caused Olympic to use the same device again in 1991. As a result, other problems were identified and repaired. Olympic used the same device again in 1996 to make sure that the company had repaired all of the corrosion. In 1997, using a low-resolution deformation smart pig, Olympic was able to identify and eliminate some areas of deformation.

These successes gave Olympic a false sense of security with respect to the overall integrity of the pipeline. Low-resolution deformation smart pigs are not reliable for identifying areas of mechanical damage and metal loss like those found at the failure site in Bellingham.

After the accident, OPS required Olympic to run the highest-resolution smart pig available to identify and quantify areas of deformation along the pipeline. This device, which detects and locates deformation as small as one tenth of an inch, has proven more than adequate. In addition, OPS required Olympic to run the highest-resolution smart pig available to identify and quantify areas of internal and external metal loss.

Q: Considering everything that has been or will be done to improve Olympic's pipeline, the public has more confidence that this system can be operated safely. However, what is OPS doing about the other pipelines that have not been so thoroughly examined?

A: As a result of the lessons learned from accidents like the Bellingham tragedy, OPS believes that the regulations should be strengthened to validate the integrity of hazardous liquid pipelines in high- consequence areas (defined as populated areas, commercially navigable waterways, and areas unusually sensitive to environmental damage). On April 24, 2000, OPS issued a Notice of Proposed Rulemaking (NPRM) that identifies specific regulatory requirements for operators to develop and implement integrity management programs, including direct evaluation of a pipeline's condition, to provide additional protection for these critical locations. Public comments on the proposed rule are currently being evaluated, and a final rule is expected to be issued later this year. A copy of this notice is available on the OPS web page at http://ops.dot.gov.

The proposed rule will require operators to perform a baseline integrity assessment within seven years after the effective date of the final rule for all pipelines in high-consequence areas; 50 percent of this pipeline mileage is to be assessed within three and one-half years. Operators who have performed and documented integrity assessments in the past five years may use these assessments to validate line integrity if their assessment approach and documentation are consistent with the provisions of the proposed rule. The acceptable methods for conducting the baseline integrity assessment are pressure testing, instrumented internal inspection (i.e., "smart pigging"), or a new technology that the operator demonstrates can provide an equivalent level of integrity assurance. Within one year after the effective date of the final rule, each operator must prepare a plan specifying the inspection or testing method selected for pipeline segment that could affect a high-consequence area, the schedule by which these initial integrity assessments will be performed, and the rationale and risk factors considered in establishing this schedule.

In evaluating the results of the integrity assessment, operators must integrate information from other relevant sources with the inspection or testing results to fully identify and characterize the potential threats to pipeline integrity. These sources might include cathodic protection system data, close interval surveys, results of previous internal inspections, operating and leak history, patrolling reports, and exposed-pipe reports. From this evaluation, the operator should identify the location, nature, and relative severity of anomalies and defects that could threaten pipeline integrity. Operators will be expected to deal with the important threats by repairing defects in the pipe. Operators must use a risk-based approach in prioritizing repair activities, in which any severe defects or damage that have the potential to result in a near-term leak or failure are dealt with immediately.

Furthermore, the proposed rule will require operators to develop and implement an integrity management program that establishes processes for:

• Performing analyses that integrate all available information about the integrity of the pipeline, including the all integrity assessment results, and the consequences of a failure;
• Reviewing integrity assessment results and data analysis using a person qualified to evaluate the results and data;
• Scheduling repair actions to deal with integrity issues raised by the assessment method and data analysis;
• Identifying and evaluating additional preventive and mitigative measures to protect high- consequence areas; and
• Measuring performance to validate the integrity plan's effectiveness.

In addition to the initial, baseline integrity assessment, the proposed rule requires that operators periodically reconfirm pipeline integrity in high-consequence areas through subsequent testing or inspection.

Besides the integrity assessment provisions of the proposed rule, operators will also be required to conduct an integrated evaluation of line segments that could affect high-consequence areas, in order to understand the greatest risks to these locations. This evaluation will include the results of the integrity assessments along with other information necessary to obtain a complete understanding of the risk contributors to a particular pipe segment. As part of this evaluation, the operator is expected to critically evaluate the effectiveness of existing preventive measures, and to consider whether additional preventive actions can improve protection for these areas. The need for additional preventive and mitigative measures in high-consequence areas must be periodically re-assessed in light of new information, such as changes in the pipeline condition, in operating parameters, or in the nearby population density or environment.

The proposed rule will apply to pipeline operators operating more than 500 miles of pipeline. This comprises approximately 87 percent of the hazardous liquid pipeline mileage in the United States. Shortly after this rule is promulgated, OPS plans to issue a similar requirement for the remaining pipeline operators.

Q: We understand that Olympic Pipe Line Company has had numerous leaks since it began operation in 1965. How many leaks has Olympic had, how big were they, and what is Federal Office of Pipeline Safety doing to prevent leaks in the future?

A: The Office of Pipeline Safety compiled a list of all known leaks, including the type and volume of commodity spilled, since Olympic Pipe Line Company began operation. Our evidence indicates a total of 48 spills on the pipeline system. All of the spills involved diesel, gasoline, or turbine jet fuel. Thirty-three of the spills occurred on Olympic Pipe Line facilities, but some of these discharges did affect state waters or groundwater. Another 15 of the spills occurred on the mainline pipeline that traverses public and private lands. (See Table 1 for details.)

Eight of the 15 mainline leaks were due to outside force damage by excavators; in one case, August 23, 1988, however, the excavation damage was caused by the pipeline operator themselves. Four leaks were on underground valve-sensing lines, one due to corrosion, one due to a landslide. The remaining leak was caused by a crack in the pipe wall that manifested itself in a buckle 31 years after original construction.

The Office of Pipeline Safety is first focusing its safety efforts on any existing damage to the mainline pipe. The recently completed internal inspections will locate areas of outside force damage that may have weakened the pipe but have not resulted in a leak. All of the damaged pipe areas will be removed or repaired. The internal inspection devices will also locate any damaging corrosion, and all buckles or wrinkles that may be left over from original construction. Finally, the inspection devices will identify any ovalities in the pipe that may indicate extensive bending of the pipe caused by excessive landslides or earth subsidence.

OPS has also required extensive valve improvements to minimize petroleum discharges in the event of a catastrophic mainline rupture. OPS mandated a valve-effectiveness study for the entire pipeline system. After undergoing our review and approval process, Olympic is now implementing the valve improvements. Numerous check valves and remotely operated valves will be added to the entire pipeline system to mitigate spill discharges after rupture, particularly in populated areas and near waterways. Improvements to the Ferndale to Allen segment have been completed.

Product release from sensing lines on underground valves are being mitigated through federally mandated valve inspections. These valve inspections have been greatly enhanced since Olympic instituted a program to provide vaults around all of its mainline valves. We are unaware of any uncontained petroleum discharges associated with mainline valves since 1986. OPS is investigating and evaluating new leak detection technologies to more rapidly identify small petroleum leaks that may occur in valve vaults.

OPS is greatly concerned with petroleum discharges that have occurred on Olympic Pipe Line facility grounds. The majority of these leaks were associated with faulty seals and flange gaskets on above ground pipe components. Although most of the facility leaks are relatively small, they can potentially go offsite and contaminate nearby surface water and groundwater. Olympic is now providing collection aprons and alarm-equipped sumps around most of its above ground piping to minimize the effects of any such leaks. It appears these measures have been partially successful and Olympic has continued to make improvements, particularly since the August 29, 1999, spill at its Renton station. Nevertheless, OPS will continue to monitor Olympic's efforts to reduce leaks from flanges and gaskets and take appropriate action if needed.

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LAST UPDATE 07/25/2001