Pipeline Safety: Better Data and Guidance Could Improve Operators' Responses to Incidents
Published: 2013-01-28T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: Pipelines are a relatively safe means of transporting natural gas and hazardous liquids; however, catastrophic incidents can and do occur. Such an incident occurred on December 11, 2012, near Sissonville, West Virginia, when a rupture of a natural gas transmission pipeline destroyed or damaged 9 homes and badly damaged a section of Interstate 77. Large-diameter transmission pipelines such as these that carry products over long distances from processing facilities to communities and large-volume users make up more than 400,000 miles of the 2.5 million mile natural gas and hazardous liquid pipeline network in the United States. The Department of Transportation's (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA), working in conjunction with state pipeline safety offices, oversees this network, which transports about 65 percent of the energy we consume.
The best way to ensure the safety of pipelines, and their surrounding communities, is to minimize the possibility of an incident occurring. PHMSA's regulations require pipeline operators to take appropriate preventive measures such as corrosion control and periodic assessments of pipeline integrity. To mitigate the consequences if an incident occurs, operators are also required to develop leak detection and emergency response plans. One mitigation measure operators can take is to install automated valves that, in the event of an incident, close automatically or can be closed remotely by operators in a control room. Such valves have been the topic of several National Transportation Safety Board (NTSB) recommendations since 1971 and a PHMSA report issued in October 2012.
As mandated in the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, we issued a January 2013 report on the ability of transmission pipeline operators to respond to a hazardous liquid or natural gas release from an existing pipeline segment. This statement is based on this report and addresses (1) variables that influence the ability of transmission pipeline operators to respond to incidents and (2) opportunities to improve these operators' responses to incidents. This statement also provides information from two other recent GAO reports on pipeline safety.
section_title: What GAO Found
paragraphs: Numerous variables--some of which are under operators' control--influence the ability of transmission pipeline operators to respond to incidents. For example, the location of response personnel and the use of manual or automated valves can affect the amount of time it takes for operators to respond to incidents. However, because the advantages and disadvantages of installing an automated valve are closely related to the specifics of the valve's location, it is appropriate that operators decide whether to install automated valves on a case-by-case basis. Several operators we spoke with have developed approaches to evaluate the advantages and disadvantages of installing automated valves, such as using spill-modeling software to estimate the potential amount of product released and extent of damage that would occur in the event of an incident.
One method PHMSA could use to improve operator response to incidents is to develop a performance-based approach for incident response times. While defining performance measures and targets for incident response can be challenging, PHMSA could move toward a performance-based approach by evaluating nationwide data to determine response times for different types of pipeline (based on location, operating pressure, and pipeline diameter, among other factors). First, though, PHMSA must improve the data it collects on incident response times. These data are not reliable because operators are not required to fill out certain time-related fields in the reporting form and because operators told us they interpret these data fields in different ways. Furthermore, while PHMSA conducts a variety of information-sharing activities, the agency does not formally collect or share evaluation approaches used by operators to decide whether to install automated valves, and not all operators we spoke with were aware of existing PHMSA guidance designed to assist operators in making these decisions. We recommended that PHMSA should: (1) improve incident response data and use those data to explore the feasibility of developing a performance-based approach for improving operators' responses to pipeline incidents and (2) assist operators in deciding whether to install automated valves by formally collecting and sharing evaluation approaches and ensuring operators are aware of existing guidance. PHMSA agreed to consider these recommendations.

section_title: Letter
paragraphs: Thank you for the opportunity to participate in this hearing on pipeline  safety. As you know, pipelines are a relatively safe means of transporting  natural gas and hazardous liquids; however, catastrophic incidents can  and do occur. We are here today because such an incident occurred on  December 11, 2012, near Sissonville, West Virginia, when a rupture of a  natural gas transmission pipeline destroyed or damaged 9 homes and  badly damaged a section of Interstate 77. Large-diameter transmission  pipelines such as these that carry products over long distances from  processing facilities to communities and large-volume users make up  more than 400,000 miles of the 2.5 million mile natural gas and  hazardous liquid pipeline network in the United States. The Department  of Transportation’s (DOT) Pipeline and Hazardous Materials Safety  Administration (PHMSA), working in conjunction with state pipeline safety  offices, oversees this network, which transports about 65 percent of the  energy we consume.
The best way to ensure the safety of pipelines, and their surrounding  communities, is to minimize the possibility of an incident occurring.  PHMSA’s regulations require pipeline operators to take appropriate  preventive measures such as corrosion control and periodic assessments  of pipeline integrity. To mitigate the consequences if an incident occurs,  operators are also required to develop leak detection and emergency  response plans. One mitigation measure operators can take is to install  automated valves that, in the event of an incident, close automatically or  can be closed remotely by operators in a control room. Such valves have  been the topic of several National Transportation Safety Board (NTSB)  recommendations since 1971 and a PHMSA report issued in October  2012.
As mandated in the Pipeline Safety, Regulatory Certainty, and Job  Creation Act of 2011, we issued a January 2013 report on the ability of  transmission pipeline operators to respond to a hazardous liquid or  natural gas release from an existing pipeline segment. today is based on this report and addresses (1) variables that influence  the ability of transmission pipeline operators to respond to incidents and  (2) opportunities to improve these operators’ responses to incidents. My  statement also provides information from two other recent GAO reports  on pipeline safety (see app. I). For our January 2013 report, we examined  incident data, conducted a literature review, and interviewed selected  operators, industry stakeholders, state pipeline safety offices, and  PHMSA officials. Our work on each pipeline safety report was conducted  in accordance with generally accepted government auditing standards.  Those standards require that we plan and perform the audit to obtain  sufficient, appropriate evidence to provide a reasonable basis for our  findings and conclusions based on our audit objectives. We believe that  the evidence obtained provides a reasonable basis for our findings and  conclusions based on our audit objectives.
subsections: section_title: Background
paragraphs: Three main types of pipelines—gathering, transmission, and  distribution—carry hazardous liquid and natural gas from producing wells  to end users (residences and businesses) and are managed by about  3,000 operators. Transmission pipelines carry these products, sometimes  over hundreds of miles, to communities and large-volume users, such as  factories. Transmission pipelines tend to have the largest diameters and  operate at the highest pressures of any type of pipeline. PHMSA has  estimated there are more than 400,000 miles of hazardous liquid and  natural gas transmission pipelines across the United States.
PHMSA administers two general sets of pipeline safety requirements and  works with state pipeline safety offices to inspect pipelines and enforce  the requirements. The first set of requirements is minimum safety  standards that cover specifications for the design, construction, testing,  inspection, operation, and maintenance of pipelines. The second set is  part of a supplemental risk-based regulatory program termed “integrity  management.” Under transmission pipeline integrity management  programs, operators are required to systematically identify and mitigate  risks to pipeline segments that are located in highly populated or  environmentally sensitive areas (called “high-consequence areas”).
According to PHMSA, industry, and state officials, responding to either a  hazardous liquid or natural gas pipeline incident typically includes  detecting that an incident has occurred, coordinating with emergency  responders, and shutting down the affected pipeline segment. Under  PHMSA’s minimum safety standards, operators are required to have a  plan that covers these steps for all of their pipeline segments and to  follow that plan during an incident. Officials from PHMSA and state  pipeline safety offices perform relatively minor roles during an incident, as  they rely on operators and emergency responders to take actions to  mitigate the consequences of such events. Operators must report  incidents that meet certain thresholds—including incidents that involve a  fatality or injury, excessive property damage or product release, or an  emergency shutdown—to the federal National Response Center.  Operators must also conduct an investigation to identify the root cause  and lessons learned, and report to PHMSA. Federal and state authorities  may use their discretion to investigate some incidents, which can involve  working with operators to determine the cause of the incident.
While prior research shows that most of the fatalities and damage from an  incident occur in the first few minutes following a pipeline rupture,  operators can reduce some of the consequences by taking actions that  include closing valves that are spaced along the pipeline to isolate  segments. The amount of time it takes to close a valve depends upon the  equipment installed on the pipeline. For example, valves with manual  controls (referred to as “manual valves”) require a person to arrive on site  and either turn a wheel crank or activate a push-button actuator. Valves  that can be closed without a person at the valve’s location (referred to as  “automated valves”) include remote-control valves, which can be closed  via a command from a control room, and automatic-shutoff valves, which  can close without human intervention based on sensor readings.  Automated valves generally take less time to close than manual valves.  PHMSA’s minimum safety standards dictate the spacing of all valves,  regardless of type of equipment installed to close them, while integrity  management regulations require that transmission pipeline operators  conduct a risk assessment for pipelines in high-consequence areas that  includes the consideration of automated valves.
section_title: Incident Response Time Depends on Multiple Variables, Including the Use of Automated Valves
paragraphs: Multiple variables—some controllable by transmission pipeline  operators—can influence the ability of operators to respond quickly to an  incident, according to PHMSA officials, pipeline safety officials, and  industry stakeholders and operators. Ensuring a quick response is  important because according to pipeline operators and industry  stakeholders, reducing the amount of time it takes to respond to an  incident can reduce the amount of property and environmental damage  stemming from an incident and, in some cases, the number of fatalities  and injuries. For example, several natural gas pipeline operators noted  that a faster incident response time could reduce the amount of property  damage from secondary fires (after an initial pipeline rupture) by allowing  fire departments to extinguish the fires sooner. In addition, hazardous  liquid pipeline operators told us that a faster incident response time could  result in lower costs for environmental remediation efforts and less  product lost. We identified five variables that can influence incident  response time and are within an operator’s control, and four other  variables that influence a pipeline operator’s ability to respond to an  incident but are beyond an operator’s control. The effect a given variable  has on a particular incident response will vary according to the specifics  of the situation. The five variables within an operator’s control are:  location of qualified operator response personnel,  control room management, and  relationships with local first responders.
The four factors beyond an operator’s control are: weather conditions, and other operators’ pipelines in the same area.  (See table 1 for further detail.) Appendix II provides several examples of  response time in past incidents; response time varied from several  minutes to days depending on the presence and interaction of the  variables just mentioned.
As noted, one variable that influences operators’ response times to  incidents is the type of valve installed on the pipeline. Research and  industry stakeholders indicate that the primary advantage of installing  automated valves—as opposed to other safety measures—is related to  the time it takes to respond to an incident. Although automated valves  cannot mitigate the fatalities, injuries, and damage that occur in an initial  blast, quickly isolating the pipeline segment through automated valves  can reduce subsequent damage by reducing the amount of hazardous  liquid and natural gas released.
Research and industry stakeholders also identified two disadvantages  operators should consider when determining whether to install automated  valves related to potential accidental closures and the monetary costs of  purchasing and installing the equipment. Specifically, automated valves  can lead to accidental closures, which can have severe, unintended  consequences, including loss of service to residences and businesses. In  addition, according to operators, vendors and contractors, the monetary  costs of installing automated valves can range from tens of thousands to  a million dollars per valve, which may be significant expenditures for  some pipeline operators. According to operators and other industry  stakeholders, considering monetary costs is important when making  decisions to install automated valves because resources spent for this  purpose can take away from other pipeline safety efforts. Specifically,  operators and industry stakeholders told us they often would rather focus  their resources on incident prevention to minimize the risk of an incident  instead of focusing resources on incident response. PHMSA officials  stated that they generally support the idea that pipeline operators be  given some flexibility to target spending where the operator believes it will  have the most safety benefit.
Research and industry stakeholders also indicate the importance of  determining whether to install valves on a case-by-case basis because  the advantages and disadvantages can vary considerably based on  factors specific to a unique valve location. These sources indicated that  the location of the valve, existing shutdown capabilities, proximity of  personnel to the valve’s location, the likelihood of an ignition, type of  product being transported, operating pressure, topography, and pipeline  diameter, among other factors, all play a role in determining the extent to  which an automated valve would be advantageous.
Operators we met with are using a variety of methods for determining  whether to install automated valves that consider—on a case-by-case  basis—whether these valves will improve response time, the potential for  accidental closure, and monetary costs. For example, two natural gas  pipeline operators told us that they applied a decision tree analysis to all  pipeline segments in highly populated and frequented areas. They used  the decision tree to guide a variety of yes-or-no questions on whether  installing an automated valve would improve response time to less than  an hour and provide advantages for locations where people might have  difficulty evacuating quickly in the event of a pipeline incident. Other  hazardous liquid pipeline operators said they used computer-based spill  modeling to determine whether the amount of product release would be  significantly reduced by installing an automated valve.
section_title: Performance-Based Approach Offers Opportunity to Measure and Improve Incident Response, but Better Data and Guidance Are Needed
paragraphs: In our report, we note that PHMSA has not developed a performance- based framework for incident response times, although some  organizations in the pipeline industry have done so. We and others have  recommended that the federal government move toward performance- based regulatory approaches to allow those being regulated to determine  the most appropriate way to achieve desired, measurable outcomes.  According to our past work, such a framework should include: (1) national  goals, (2) performance measures that are linked to those national goals,  and (3) appropriate performance targets that promote accountability and  allow organizations to track their progress toward goals. While PHMSA  has established a national goal for incident response times, it has not  linked performance measures or targets to this goal. Specifically, PHMSA  directs operators to respond to certain incidents—emergencies that  require an immediate response—in a “prompt and effective” manner,  but neither PHMSA’s regulations nor its guidance describe ways to  measure progress toward meeting this goal. Without a performance  measure and target for a prompt and effective incident response, PHMSA  cannot quantitatively determine whether an operator meets this goal and  track their performance over time. PHMSA officials told us that because  pipeline incidents often have unique characteristics, developing a  performance measure and associated target for incident response time  would be difficult. In particular, it would be challenging to establish a  performance measure using incident response time in a way that would  always lead to the desired outcome of a prompt and effective response.  In addition, officials stated it would be difficult to identify a single response  time target for all incidents, as pipeline operators likely should respond to  some incidents more quickly than others.
Defining performance measures and targets for incident response can be  challenging, but one possible way for PHMSA to move toward a more  quantifiable, performance-based approach would be to develop strategies  to improve incident response based on nationwide data. For example,  performing an analysis of nationwide incident data—similar to PHMSA’s  current analyses of fatality and injury data—could help PHMSA determine  response times for different types of pipelines (based on characteristics  such as location, operating pressure, and diameter); identify trends; and  develop strategies to improve incident response. However, we found that  PHMSA does not have the reliable nationwide data on incident response  time data it would need to conduct such analyses. Specifically, the  response time data PHMSA currently collects are unreliable for two  reasons: (1) operators are not required to fill out certain time-related fields  in the PHMSA incident-reporting form and (2) when operators do provide  these data, they are interpreting the intended content of the data fields in  different ways. Our report recommended that PHMSA improve incident  response data and use these data to evaluate whether to implement a  performance-based framework for incident response times. PHMSA  agreed to consider this recommendation.
We also found that PHMSA needs to do a better job of sharing  information on ways operators can make decisions to install automated  valves. For example, many of the operators we spoke with were unaware  of existing PHMSA enforcement and inspection guidance that could be  useful for operators in determining whether to install automated valves on  transmission pipelines. In addition, while PHMSA inspectors see  examples of how operators make decisions to install automated valves  during integrity management inspections, they do not formally collect this  information or share it with other operators. Given the variety of risk- based methods for making decisions about automated valves across the  operators we spoke with, we believe that both operators and inspectors  would benefit from exposure to some of the methods used by other  operators to make decisions on whether to install automated valves. Our  report recommended that PHMSA share guidance and information on  operators’ decision-making approaches to assist operators with these  determinations. PHMSA also agreed to consider this recommendation.
Chairman Rockefeller this concludes my prepared remarks. I am happy  to respond to any questions that you or other Members of the Committee  may have at this time.
section_title: GAO Contact and Staff Acknowledgments
paragraphs: For questions about this statement, please contact Susan Fleming,  Director, Physical Infrastructure, at (202) 512-3824 or flemings@gao.gov.  In addition, contact points for our Offices of Congressional Relations and  Public Affairs may be found on the last page of this statement. Individuals  who made key contributions to this statement include Sara Vermillion  (Assistant Director), Sarah Arnett, Melissa Bodeau, Russ Burnett,  Matthew Cook, Colin Fallon, Robert Heilman, David Hooper, and   Josh Ormond.
section_title: Appendix I: Summary of Recent GAO Reports on Gathering Pipelines and Low-stress Transmission Pipelines
paragraphs: GAO recently issued two reports related to the safety of certain types of  pipelines. The first, GAO-12-388, reported on the safety of gathering  pipelines, which currently are largely unregulated by the federal  government. The second, GAO-12-389R, reported on the potential safety  effects of applying less prescriptive requirements, currently levied on  distribution pipelines, to low-stress natural gas transmission pipelines.  Further detail on each report is provided below. For the full report text, go  to www.gao.gov.
Included in the nation’s pipeline network are an estimated 200,000 or  more miles of onshore gathering pipelines, which transport products to  processing facilities and larger pipelines. Many of these pipelines have  not been subject to federal regulation because they are considered less  risky due to their generally rural location and low operating pressures. For  example, out of the more than 200,000 estimated miles of natural gas  gathering pipelines, the Pipeline and Hazardous Materials Safety  Administration (PHMSA) regulates roughly 20,000 miles. Similarly, of the  30,000 to 40,000 estimated miles of hazardous liquid gathering pipelines,  PHMSA regulates about 4,000 miles.
While the safety risks of onshore gathering pipelines that are not  regulated by PHMSA are generally considered to be lower than for other  types of pipelines, PHMSA does not collect comprehensive data to  identify the safety risks of unregulated gathering pipelines. Without data  on potential risk factors—such as information on construction quality,  maintenance practices, location, and pipeline integrity—pipeline safety  officials are unable to assess and manage safety risks associated with  gathering pipelines. Further, some types of changes in pipeline  operational environments could also increase safety risks for federally  unregulated gathering pipelines. Specifically, land-use changes are  resulting in development encroaching on existing pipelines, and the  increased extraction of oil and natural gas from shale deposits is resulting  in the construction of new gathering pipelines, some of which are larger in  diameter and operate at higher pressure than older pipelines. As a result,  PHMSA is considering collecting data on federally unregulated gathering  pipelines. However, the agency’s plans are preliminary, and the extent to  which PHMSA will collect data sufficient to evaluate the potential safety  risks associated with these pipelines is uncertain.
In addition, we found that the amount of sharing of information to ensure  the safety of federally unregulated pipelines among state and federal  pipeline safety agencies appeared limited. For example, some state and  PHMSA officials we interviewed had limited awareness of safety practices  used by other states. Increased communication and information sharing  about pipeline safety practices could boost the use of such practices for  unregulated pipelines.
We recommended that PHMSA should collect data on federally  unregulated onshore hazardous liquid and gas gathering pipelines,  subsequent to an analysis of the benefits and industry burdens  associated with such data collection. Data collected should be  comparable to what PHMSA collects annually from operators of regulated  gathering pipelines (e.g., fatalities, injuries, property damage, location,  mileage, size, operating pressure, maintenance history, and the causes of  incidents and consequences). Also, we recommended that PHMSA  establish an online clearinghouse or other resource for states to share  information on practices that can help ensure the safety of federally  unregulated onshore hazardous liquid and gas gathering pipelines. This  resource could include updates on related PHMSA and industry  initiatives, guidance, related PHMSA rulemakings, and other information  collected or shared by states. PHMSA concurred with our  recommendations and is taking steps to implement them.
Gas transmission pipelines typically move natural gas across state lines  and over long distances, from sources to communities. Transmission  pipelines can generally operate at pressures up to 72 percent of specified  minimum yield strength (SMYS). By contrast, local distribution pipelines  generally operate within state boundaries to receive gas from  transmission pipelines and distribute it to commercial and residential end  users. Distribution pipelines typically operate well below 20 percent of  SMYS. Connecting the long-distance transmission pipelines to the local  distribution pipelines are lower stress transmission pipelines that may  transport natural gas for several miles at pressures between 20 and 30  percent of SMYS.
Applying PHMSA’s distribution integrity management requirements to  low-stress transmission pipelines would result in less prescriptive safety  requirements for these pipelines. Overall, requirements for distribution  pipelines are less prescriptive than requirements for transmission  pipelines in part because the former operate at lower pressure and pose  lower risks in general than the latter. For example, the integrity  management regulations for transmission pipelines allow three types of  in-depth physical inspection. In contrast, distribution pipeline operators  can customize their integrity management programs to the complexity of  their systems, including using a broader range of methods for physical  inspection. While PHMSA officials stated that “less prescriptive” does not  necessarily mean less safe, they also stated that distribution integrity  management requirements for distribution pipelines can be more difficult  to enforce than integrity management requirements for transmission  pipelines.
In general, the effect of changing PHMSA’s requirement for low-stress  transmission pipelines for pipeline safety is unclear. While the  consequences of a low-stress transmission pipeline failure are generally  not severe because these pipelines are more likely to leak than rupture,  the point at which a gas pipeline fails by rupture is uncertain and depends  on a number of factors in addition to pressure, such as the size or type of  defect and the materials used to conduct the pipeline. In addition, the  mileage and location of pipelines that would be affected by such a  regulatory change are currently unknown, although PHMSA recently  changed its reporting requirements to collect such information. The  concern is that because distribution pipelines are located in highly  populated areas, the low-stress transmission pipelines that are connected  to them could also be located in highly populated areas. As a result, we  considered the current regulatory approach of applying more prescriptive  transmission pipeline requirements reasonable.
section_title: Appendix II: Examples of Pipeline Incident Response Times
paragraphs: Operators we spoke with stated that the amount of time it takes to  respond to an incident can vary depending on a number of variables (see  table 2).