Pipeline Safety: Better Data and Guidance Needed to Improve Pipeline Operator Incident Response
Published: 2013-01-23T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: The nation's 2.5 million mile network of hazardous liquid and natural gas pipelines includes more than 400,000 miles of "transmission" pipelines, which transport products from processing facilities to communities and large-volume users. To minimize the risk of leaks and ruptures, PHMSA requires pipeline operators to develop incident response plans. Pipeline operators with pipelines in highly populated and environmentally sensitive areas ("high-consequence areas") are also required to consider installing automated valves.
The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 directed GAO to examine the ability of transmission pipeline operators to respond to a product release. Accordingly, GAO examined (1) opportunities to improve the ability of transmission pipeline operators to respond to incidents and (2) the advantages and disadvantages of installing automated valves in high-consequence areas and ways that PHMSA can assist operators in deciding whether to install valves in these areas. GAO examined incident data; conducted a literature review; and interviewed selected operators, industry stakeholders, state pipeline safety offices, and PHMSA officials.
section_title: What GAO Found
paragraphs: The Department of Transportation's (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) has an opportunity to improve the ability of pipeline operators to respond to incidents by developing a performance-based approach for incident response times. The ability of transmission pipeline operators to respond to incidents--such as leaks and ruptures--is affected by numerous variables, some of which are under operators' control. For example, the use of different valve types (manual valves or "automated" valves that can be closed automatically or remotely) and the location of response personnel can affect the amount of time it takes for operators to respond to incidents. Variables outside of operators' control, such as weather conditions, can also influence incident response time, which can range from minutes to days. GAO has previously reported that a performance-based approach--including goals and associated performance measures and targets--can allow those being regulated to determine the most appropriate way to achieve desired outcomes. In addition, several organizations in the pipeline industry have developed methods for quantitatively evaluating response times to incidents, including setting specific, measurable performance goals. 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). However, PHMSA must first improve the data it collects on incident response times. These data are not reliable both 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. Reliable data would improve PHMSA's ability to measure incident response and assist the agency in exploring the feasibility of developing a performance-based approach for improving operator response to pipeline incidents.
The primary advantage of installing automated valves is that operators can respond quickly to isolate the affected pipeline segment and reduce the amount of product released; however, automated valves can have disadvantages, including the potential for accidental closures--which can lead to loss of service to customers or even cause a rupture--and monetary costs. Because the advantages and disadvantages of installing an automated valve are closely related to the specifics of the valve's location, it is appropriate to 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. For example, some operators of hazardous liquid pipelines use spill-modeling software to estimate the amount of product release and extent of damage that would occur in the event of an incident. 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. Furthermore, not all operators we spoke with were aware of existing PHMSA guidance designed to assist operators in making these decisions. PHMSA could assist operators in making this decision by formally collecting and sharing evaluation approaches and ensuring operators are aware of existing guidance.
section_title: What GAO Recommends
paragraphs: DOT should (1) improve incident response data and use these data to evaluate whether to implement a performance-based framework for incident response times and (2) share guidance and information on evaluation approaches to inform operators decisions. DOT agreed to consider these recommendations.

section_title: Letter
paragraphs: The United States has over 2.5 million miles of hazardous liquid and  natural gas pipelines that transport approximately 65 percent of the  energy we consume. These pipelines, which are largely regulated by the  Department of Transportation’s (DOT) Pipeline and Hazardous Materials  Safety Administration (PHMSA), are relatively safe when compared with  other modes of transporting hazardous goods (e.g., highway and rail).  However, when pipelines leak or rupture the results can be devastating,  including fatalities, injuries, and extensive property or environmental  damage. Such an “incident” occurred in September 2010 in San Bruno,  California, killing 8 people and damaging or destroying over 100 homes.  To minimize the risk of a pipeline incident, pipeline operators are required  to develop leak detection methods and emergency response plans.  Operators with pipelines in highly populated or environmentally sensitive  areas (called “high-consequence areas”) are subject to supplemental risk- based regulations under PHMSA’s integrity management program.  Through this program, PHMSA requires that operators conduct a risk  assessment to determine what additional measures to take to mitigate the  consequences of pipeline failures. One mitigation measure operators can  take based on the results of the risk assessment is to install automated  valves, which in the event of an incident, close automatically or are closed  remotely by operators in a control room. Since 1971, the National  Transportation Safety Board (NTSB) has made recommendations that  DOT develop standards and requirements for automated valves.  Following the San Bruno incident, NTSB recommended that DOT require  natural gas pipeline operators install automated valves in all high- consequence areas.
The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011  mandated that GAO examine the ability of transmission pipeline  operators to respond to a hazardous liquid or natural gas release from an  existing pipeline segment. Accordingly, this report contains information  on: (1) opportunities to improve the ability of transmission pipeline  operators to respond to incidents, and (2) the advantages and  disadvantages of installing automated valves in high-consequence areas  and ways that PHMSA can assist operators in deciding whether to install  valves in these areas.
To determine what opportunities exist to improve the ability of  transmission pipeline operators to respond to incidents, we identified the  variables that influence operators’ incident response capabilities. To do  so, we spoke with selected operators about their prior incidents and  variables that influenced their ability to respond. Operators were selected  based on criteria, including amount and types of pipeline owned in high- consequence areas and geographic diversity. We also discussed prior  incidents, incident response times, and federal oversight of the pipeline  industry with officials from PHMSA, state pipeline safety offices, industry  associations, and safety groups. Based on our discussions and review of  prior incidents, we identified variables that influence operators’ ability to  respond to incidents. We also examined 2007 to 2011 PHMSA incident  data, including data on:  total number of incidents;  type of incident (leak or rupture);  type of pipeline where the incident occurred; and  the dates and times when an incident occurred, the operator identified  the incident, the operator’s resources (personnel and equipment)  arrived on site, and the operator shut down a pipeline or facility.
We assessed the reliability of data through discussions with PHMSA  officials and select operators and determined that data elements related  to numbers of incidents, types of releases, and types of pipeline where  incidents occurred were reliable for the purpose of providing context.  However, we determined that data elements related to response time  were not sufficiently reliable for the purpose of conducting a detailed  analysis of relationships between response time and other factors.  Finally, we reviewed federal requirements, and industry and government  performance standards related to emergency response within the pipeline  industry.
To determine the advantages and disadvantages of installing automated  valves in high-consequence areas and ways that PHMSA can assist  operators in deciding whether to install these valves, we identified the key  factors that should be used in deciding whether to install automated  valves in high-consequence areas. To do so, we conducted a literature  review of previous research dating back to 1995 and interviewed officials  from industry associations and pipeline safety groups. In addition, we  collected information from selected operators on their methods for  deciding whether to install automated valves, as well as specific pipeline  segments and valve locations on which they made such decisions. We  also discussed the regulations with officials from PHMSA, state pipeline  safety offices, and pipeline operators to determine what, if any, additional  guidance would help operators apply the current regulations on installing  automated valves. For further details on our scope and methodology, see  appendix I.
We conducted this performance audit from March 2012 to January 2013  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 carry hazardous liquid and natural gas  from producing wells to end users (residences and businesses) and are  managed by about 2,500 operators:
Gathering pipelines collect hazardous liquid and natural gas from  production areas and transport the products to processing facilities,  which in turn refine and send the products to transmission pipelines.  These pipelines tend to be located in rural areas but can also be  located in urban areas. PHMSA estimates there are 200,000 miles of  natural gas gathering pipelines and 30,000 to 40,000 miles of  hazardous liquid gathering pipelines.
Transmission pipelines carry hazardous liquid or natural gas,  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. (See fig. 1.)
Distribution pipelines then split off from transmission pipelines to  transport natural gas to end users—residential, commercial, and  industrial customers. There are no hazardous liquid distribution  pipelines. PHMSA has estimated there are roughly 2 million miles of  natural gas distribution pipelines, most of which are intrastate  pipelines.
PHMSA administers the national regulatory program to ensure the safe  transportation of hazardous liquid and natural gas by pipeline, including  developing safety requirements that all pipeline operators regulated by  PHMSA must meet. In 2012, the agency’s budget was $201 million,  which was used, in part, to employ over 200 staff in its pipeline safety  program. About half of the pipeline safety program staff inspects  hazardous liquid and gas pipelines for compliance with safety regulations.  Besides PHMSA, over 300 state inspectors help oversee pipelines and  ensure safety. State and federal officials may also investigate specific  pipeline incidents to determine the reason for the pipeline failure and to  take enforcement actions, when necessary.
PHMSA enforces two general sets of pipeline safety requirements. The  first are minimum safety standards that cover specifications for the  design, construction, testing, inspection, operation, and maintenance of  pipelines. The second set of safety requirements are 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—discrete sections of the pipeline system  separated by valves that can stop the flow of product—that are located in  high-consequence areas where an incident would have greater  consequences for public safety or the environment. To ensure operators  comply with minimum safety standards and integrity management  requirements, PHMSA conducts inspections in partnership with state  pipeline safety agencies. Inspections may focus on specific pipeline  segments or aspects of an operator’s safety program, or both. According  to PHMSA, officials conduct an inspection for each operator at least once  every 5 to 7 years, but may conduct additional inspections based on  safety risk or at the discretion of PHMSA or state officials. PHMSA is  authorized to take enforcement actions against operators, including  issuing warning letters, notices of probable violation, notices of  amendment, notices of proposed safety order, corrective action orders,  and imposing civil penalties.
Transporting hazardous liquids and natural gas by pipelines is associated  with far fewer fatalities and injuries than other modes of transportation.  From 2007 to 2011, there was an average of about 14 fatalities per year  for all pipeline incidents reported to PHMSA, including an average of  about 2 fatalities per year resulting from incidents on hazardous liquid and  natural gas transmission pipelines. In comparison, in 2010, 3,675  fatalities resulted from incidents involving large trucks and 730 additional  fatalities resulted from railroad incidents. Yet risks to pipelines exist, such  as corrosion and third party excavation, which can damage a pipeline’s  integrity and result in leaks and ruptures. A leak is a slow release of a  product over a relatively small area. A rupture is a breach in the pipeline  that may occur suddenly; the product may then ignite resulting in an  explosion. According to pipeline operators we met with, of the two types  of pipeline incidents, leaks are more common but generally cause less  damage. Ruptures are relatively rare but can have much higher  consequences because of the damage that can be caused by an  associated explosion.
According to PHMSA, industry, and state officials, responding to either a  hazardous liquid or natural gas pipeline incident typically includes steps  such as detecting that an incident has occurred, coordinating with  emergency responders, and shutting down the affected pipeline segment.  (See fig. 2.) 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. Following an  incident, 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, as well as conduct an investigation to  identify the root cause and lessons learned. Federal and state authorities  may also use their discretion to investigate some incidents, which can  involve working with operators to determine the cause of the incident. If  necessary, authorities will take steps to correct deficiencies in operator  safety programs, including taking enforcement actions.
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 located at the valve location (referred  to as “automated valves”) include both 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. (See fig. 3.) 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 high- consequence areas that includes the consideration of automated  valves.
section_title: Performance-Based Approach Offers Opportunity to Improve Incident Response, but Better Data Are Needed
paragraphs: The ability of transmission pipeline operators to respond to incidents,  such as leaks and ruptures, is affected by a number of variables—some  of which are under operators’ control—resulting in variances in response  time; for a given incident, that time can range from minutes to days.  Several states and industry organizations have developed performance- based requirements for operators to meet in responding to incidents.  PHMSA has some performance-based requirements, but its current  performance goal related to incident response is not well defined. More  precise performance measures and targets could lead to improved  response times and less damage from incidents in some cases. However,  PHMSA would need better data on incidents to determine the feasibility of  such an approach.
subsections: section_title: Incident Response Time Depends on Multiple Variables, Some of Which Operators Can Control
paragraphs: According to PHMSA officials, pipeline safety officials, and industry  stakeholders and operators, multiple variables—some controllable by  transmission pipeline operators—can influence the ability of operators to  respond quickly to an incident. 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 also  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  that are within an operator’s control:
Leak detection capabilities. How quickly a leak is detected affects how  soon an operator can initiate a response. Pipeline operators must  perform a variety of leak detection activities to monitor their systems  and identify leaks. These activities commonly include periodic  external monitoring, such as aerial patrols of the pipeline, as well as  continuous internal monitoring, such as measuring the intake and  outtake volumes or pressure flows on the pipeline. In addition,  pipeline operators must conduct public awareness programs for those  living near pipeline facilities about how to recognize, respond to, and  report pipeline emergencies; these programs can influence how  quickly an operator becomes aware of an incident. Attempting to  confirm an incident can also affect response time. Pipeline operators  may prefer to have two sources of information to confirm an incident,  such as data from a pipeline sensor and a visual confirmation,  especially if shutting down the system is a likely response to the  incident. Natural gas pipeline operators in particular generally seek to  confirm an incident before a shutdown, as shutdowns interrupt the gas  flow and can cut off service to their customers.
Location of qualified operator response personnel. The proximity of  the operator’s response personnel to a facility or shutoff valve can  affect the response time. Response personnel who have a greater  distance to travel to the facility or valve site can take longer to  establish an incident command center or to close manual valves.  Along with proximity, incident response time depends on whether  qualified operator response personnel—those who are trained and are  authorized to take necessary action, such as closing manual valves— are dispatched.
Type of valves. The type of valve an operator has installed on a  pipeline segment can affect how quickly the segment can be isolated.  Automated valves, which can be closed automatically or remotely, can  shorten incident response time compared to manual valves, which  require that personnel travel to the valve site and turn a wheel crank  or activate a push-button actuator to close the valve. However, if  affected valves happen to be located at or close to facilities where  personnel are permanently stationed, the type of valve could be less  critical in influencing incident response time.
Control room management. Clear operating policies and shutdown  protocols for control room personnel can influence response time to  incidents. For example, incident response time might be reduced if  control room personnel have the authority to shut down a pipeline or  facility if a leak is suspected, and are encouraged to do so. A few of  the operators we met with told us that while in the past it was a  common practice in the industry to avoid shutdowns unless absolutely  necessary, the practice now for these operators is to shut down the  line if there is any doubt about safety. An official from one natural gas  pipeline operator told us that his company instructs control room  personnel that they will not suffer repercussions from shutting down a  line for safety reasons. Another official from a hazardous liquid  pipeline operator told us that the authority to shut down is at the  control room level and that even personnel in the field can make the  call to shut down a line.
Relationships with local first responders. Operators that have already  established effective communications with local first responders— such as fire and police departments—may respond more quickly  during emergencies. For example, one natural gas pipeline operator  told us that during one incident, the local first responders had turned  to the operator personnel for direction on how to respond to a rupture.  As a result, the operator said that one of the lessons learned was that  the company needed to conduct more emergency response  exercises, such as mock drills, with the local first responders so the  responders would know their roles and responsibilities.
We identified four other variables that influence a pipeline operator’s  ability to respond to an incident, but are beyond an operator’s control:
Type of release. The type of release—leak or rupture—can influence  how quickly an operator responds to an incident. Leaks are generally  a slow release of product over a small area, which can go undetected  for long periods. Once a leak is detected, it can take additional time to  confirm the exact location. Ruptures, which usually produce more  significant changes in the external or internal conditions of the  pipeline, are typically easier to detect and locate.
Time of day. The time of day when an incident occurs can affect  incident response time. The operator’s response personnel may be  delayed in reaching facilities in urban or suburban areas during peak  traffic times. Conversely, if an incident occurs during the evening or  on a weekend, the operator’s response personnel could be able to  reach the facility more quickly, because of lighter traffic. For example,  one natural gas pipeline operator told us about an incident that  occurred on a Saturday afternoon, which meant that traffic did not  delay response personnel traveling to the scene.
Weather conditions. Weather conditions can affect how quickly an  operator can respond to an incident. For example, one natural gas  pipeline operator described an incident caused by a hurricane’s storm  surge that pushed debris into the pipeline at a facility, and flooding  prevented the response personnel from reaching the site for several  days, during which time the pipe continued to leak gas. Winter  conditions can also make it more difficult for the operator’s response  personnel to reach a facility or to access valve sites in remote areas.  As another example, windy conditions can disperse natural gas and  make it hard to detect a leak.
Other operators’ pipeline in the same area. If two or more operators  own pipeline in a shared right of way, determining whose system is  affected can increase incident response time. Operators may delay  responding if they have not confirmed that the incident is on their  pipeline. For example, one natural gas pipeline operator told us about  an incident that took 2 days to repair because when their personnel  first detected a leak, the personnel initially contacted another  operator, whose line crossed over theirs, to make sure the leak was  not the other operator’s.
Operators we spoke with stated that the amount of time it takes to  respond to an incident can depend on all of the variables listed above and  can range from several minutes to days (see table 1).
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. For example, Executive Order 13563 calls for  improvements to the nation’s regulatory system, including the use of the  best, most innovative and least burdensome tools for achieving regulatory  ends. We have also previously reported on the benefits of a  performance-based framework, which helps agencies focus on  achieving outcomes. 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 towards goals.
PHMSA has included these three elements of a performance-based  framework in some aspects of its pipeline safety program, but not for  incident response times. For example, PHMSA has set national goals  intended to reduce the number of pipeline incidents involving fatality or  major injury and the number of hazardous liquid pipeline spills with  environmental consequences. Each of these national goals has  associated performance measures (i.e., the number of such incidents)  and specific targets (such as reducing the number of incidents involving a  fatality or major injury from 39 to less than 28 per year by 2016) that allow  PHMSA to track its progress toward the goals. However, 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. PHMSA  officials told us that because each incident presents unique  circumstances, its inspectors must determine whether an operator’s  incident response was prompt and effective on a case-by-case basis.  According to PHMSA, in making this determination, inspectors must use  their professional judgment to balance any challenges the operator faced  in responding with the operator’s obligation to the public’s safety.
Other organizations in the pipeline industry, including some state  regulatory agencies, have developed methods for measuring the  performance of operators responding to incidents by using specific  incident response times. According to the National Association of Pipeline  Safety Representatives, several state pipeline safety offices have  initiatives that require natural gas pipeline operators to respond within a  specified time frame to reports of pipeline leaks. For example, the New  Hampshire Public Utilities Commission has established incident response  time standards—ranging from 30 to 60 minutes, with performance  targets—for natural gas distribution companies to meet when responding  to reports of a leak. In addition, members of the Interstate Natural Gas  Association of America have committed to achieving a 1-hour incident  response time for large diameter (greater than 12 inches) natural gas  pipelines in highly populated areas. To meet this goal, operators are  planning changes to their systems, such as relocating response  personnel and automating over 1,800 valves throughout the United  States.
According to PHMSA officials, pipeline incidents often have unique  characteristics, so developing a performance measure and associated  target for incident response time similar to those used by other pipeline  organizations 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. Officials stated that the intention behind requiring operators to  respond promptly and effectively is to make the area safe as quickly as  possible. In some instances, an operator can accomplish this outcome in  the time it takes to close valves and isolate pipeline segments, while in  other instances, an operator might need to completely vent or drain the  product from the pipeline. Likewise, it would be difficult to identify a  specific target for incident response time, as pipeline operators likely  should respond to some incidents more quickly than others. For example,  industry officials noted that while most fatalities and injuries caused by a  pipeline explosion occur in the initial blast, a faster incident response time  could help reduce fatalities and injuries in cases where there are sites  nearby whose occupants have limited mobility (e.g., prisons, hospitals). In  these situations, operators told us they want to ensure their incident  response time is faster than for more remote locations where an  explosion would have less of an impact on people, property, and the  environment.
Although defining performance measures and targets for incident  response can be challenging, one 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.  Furthermore, as part of this analysis of response times for various types  of pipelines, PHMSA could explore the feasibility of integrating incident  response performance measures and targets for individual pipelines into  its integrity management program. For example, PHMSA might identify  performance measures that are appropriate for various types of pipelines  and allow operators to determine which measures and targets best apply  to their individual pipeline segments, based on the characteristics of those  segments. Such an approach would be consistent with our prior work on  performance measurement, as it would allow operators the flexibility to  meet response time targets in several ways, including changes to their  leak detection methods, moving personnel closer to the valve location, or  installing automated valves. PHMSA would then review an operator’s  selection of measures and targets as part of ongoing integrity  management inspections; this process is similar to how inspectors review  other provisions in the integrity management program.
section_title: PHMSA Data on Incident Response Time Are Limited
paragraphs: PHMSA would need reliable national data to implement a performance- based framework for incident response times to ensure operators are  responding in a prompt and effective manner. However, the data  currently collected by PHMSA do not enable them to accurately  determine incident response times for all recent incidents 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. Specifically, PHMSA requires operators to report the date  and time when the incident occurred. Operators are not required to report  the dates and times when:  the operator identified the incident;  the operator’s resources (personnel or equipment) arrived on site; and  the operator shut down and restarted a pipeline or facility.
As a result, our analysis determined that hazardous liquid pipeline  operators did not report the date and time for two of these variables— when the incident was identified and when operator resources arrived on  site—for 26 percent (178 out of 674) of incidents that occurred in 2010  and 2011. Also, these operators did not identify whether a shutdown took  place in 16 percent (108 out 674) of incidents over the same time  period. In comparison, natural gas pipeline operators reported more  complete data; these operators did not report data for when the operator  identified the incident and resources arrived on site in only 3 percent (6  out of 191) of incidents that occurred in 2010 and 2011. Also, these  operators did not identify whether a shutdown took place in only about 2  percent (3 out of 191) of incidents over the same period. PHMSA officials  told us that because they have not used the time-related data to identify  safety trends, the omissions have not been a problem for them, although  in the future they may decide to make some of these data fields  mandatory.
In addition to omitting certain incident data fields, several officials from  pipeline operators told us that they interpret what to include in the time- related, incident data fields differently. For example, according to one  official from a natural gas operator, some operators interpret the time  when an operator identified the incident as the time when operator  personnel first received a call about a potential leak, while others may  interpret the time when an operator identified an incident as the time  when operator personnel received an on-site confirmation of a leak.  These differing interpretations occur even though guidance on PHMSA’s  website instructs operators how to complete the reporting forms, including  the time-related data fields.
section_title: Improved Information Sharing about Evaluating Automated Valve Advantages and Disadvantages Could Inform Operators’ Decisions
paragraphs: The primary advantage of installing automated valves is reducing the time  to shut down and isolate a pipeline segment after a leak or rupture  occurs, while disadvantages include the potential for accidental closures  and monetary cost. Because these advantages and disadvantages vary  among valve locations, operators should make decisions about whether  to install automated valves—as opposed to other safety measures—on a  case-by-case basis. PHMSA has several opportunities to assist operators  in making these evaluations, including communicating guidance and  sharing information on some methods operators use to make these  decisions.
subsections: section_title: Improved Response Times, Potential for Accidental Closures, and Costs Should be Evaluated on a Case-by-Case Basis
paragraphs: Research and industry stakeholders indicate that the primary advantage  of installing automated valves 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 the initial blast, quickly isolating the  pipeline segment through automated valves can significantly reduce  subsequent damage by reducing the amount of hazardous liquid and  natural gas released. For example, NTSB found that automated valves  would have reduced the amount of time taken to stop the flow of natural  gas in the San Bruno incident and, therefore, reduced the severity of  property damage and life-threatening risks to residents and emergency  responders. According to research and industry stakeholders,  automated valves will only decrease the number of fatalities and injuries  in those cases when people cannot easily evacuate the area, such as  cases involving hospital patients or prison inmates.
Research and industry stakeholders identified several 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.  For example, according to a pipeline operator, an accidental closure on a  natural gas pipeline in New Jersey resulted in significant disruption and  downstream curtailments to customers in New York City during high  winter demand. In addition, 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. (See  table 2.)
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 location, the likelihood of an ignition, type of  product being transported, operating pressure, topography and pipeline  diameter, among others, all play a role in determining the extent to which  an automated valve would be advantageous.
section_title: Operators Have Developed Approaches to Evaluate Advantages and Disadvantages of Installing Automated Valves
paragraphs: Operators we met with are using a variety of methods for determining  whether to install automated valves. One of the eight operators we met  with had decided to install automatic-shutoff valves across its pipeline  system, regardless of risk, to eliminate the need for control room staff to  make judgment calls on whether or not to close valves to isolate pipeline  segments. However, seven of the eight operators we met with developed  their own risk-based approach for considering potential advantages and  disadvantages when making these decisions on a case-by-case basis.  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 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. These seven  operators told us that their approaches for making decisions about  whether to install automated valves considered the advantages and the  disadvantages we identified above.
Improved response time. Most operators we spoke with considered  whether automated valves would lead to a faster response time. For  example, the primary criterion used by two of the natural gas pipeline  operators was the amount of time it would take to shut down the  pipeline and isolate the segment and population along the segment. In  one instance, an operator decided to install a remote-control valve in  a location that would take pipeline personnel 2.5 hours to reach and  30 minutes more to close the valve. Installing the automated valve is  expected to reduce the total response time to under an hour, including  detecting the incident and making the decision to isolate the pipeline  segment. In addition, several hazardous liquid pipeline operators used  spill modeling to determine whether an automated valve would result  in a reduced amount of damage from product release at individual  locations. This spill modeling typically considered topography,  operating pressure, and placement of existing valves. For example,  one hazardous liquid pipeline operator used spill modeling to make  the decision to install a remote-control valve on a pipeline segment  with a large elevation change after evaluating the spill volume  reduction.
Accidental closures. Operators indicated that installing automated  valves, especially automatic-shutoff valves, could have unintended  consequences, which they considered as part of their decisions to  install automated valves. For example, two natural gas pipeline  operators considered whether there is the potential for accidentally  cutting off service when assessing individual locations for the possible  installation of an automatic-shutoff valve. As noted, one natural gas  pipeline operator has made the decision to install automatic-shutoff  valves across its pipeline system. The operator stated that in the past,  there were concerns with relying on automatic-shutoff valves because  of the possibility for accidental closures, but the operator believes it  has developed a process that effectively adapts to pressure and flow  change and minimizes or eliminates the risk of the valve accidentally  closing. Other natural gas pipeline operators stated that relying on  pressure sensing systems can be dangerous because “tuning” the  pressure activation in an effort to avoid accidental closures can result  in situations where the valve will not automatically close during an  actual emergency. For hazardous liquid, all operators we spoke with  stated that they either do not consider or do not typically install  automatic-shutoff valves because an accidental closure has the  potential to lead to an incident. Specifically, operators stated that an  unexpected valve closure can result in decompression waves in the  pipeline system, which might cause the pipeline to rupture if operators  cannot reduce the flow of product promptly.
Monetary costs. 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  stated that it generally supports the idea that pipeline operators  should be given flexibility to target compliance dollars where they will  have the most safety benefit when it is possible to do so. Operators  we spoke with stated that they considered costs associated with  purchasing and installing equipment. For example, four operators  indicated that they will consider the costs related to communications  equipment when determining whether to install automated valves. In  addition, three operators stated that decisions to install automated  valves are affected by whether the operator has or can gain access to  the pipeline right of way. Other cost considerations mentioned by at  least one operator included local construction costs and possible  changes to leak detection systems. Finally, two natural gas pipeline  operators stated that monetary cost plays a role in determining what  steps they plan to take to meet a one-hour response time goal for  pipelines in highly populated areas. For example, the operator might  choose to move personnel closer to valves rather than installing  automated valves, if that is the more cost-effective option.
section_title: Opportunities Exist for PHMSA to Better Communicate Guidance and Share Best Practices Operators Use to Determine Whether to Install Automated Valves
paragraphs: PHMSA has developed guidance to help operators understand current  regulations on what operators must consider when deciding to install  automated valves, but not all operators are aware of the guidance.  PHMSA includes on its primary website two types of guidance that can be  useful for operators in determining whether to install automated valves on  transmission pipelines. First, PHMSA has developed inspection protocols  for both the hazardous liquid and natural gas integrity management  program. Second, PHMSA has developed guidance on the enforcement  actions inspectors will take—such as a notice of proposed violation and  warning letter, among others—should PHMSA discover a violation. Both  of these pieces of guidance provide additional detail—not included in  regulation—on the steps operators might take in considering whether to  install automated valves. For example, PHMSA’s inspection protocol for  natural gas operators describes several studies on the generic costs and  benefits of automated valves and indicates that operators may use this  research as long as they document the reasons why the study is  applicable to the specific pipeline segment. However, operators we spoke  with were unaware of existing guidance to varying degrees. Specifically,  of the eight operators we met with, three were unaware of both the  inspection and enforcement guidance, and the remaining five operators  were unaware of the enforcement guidance. Operators we spoke with,  including those that were unaware of the guidance, told us that having  this information would be helpful in making decisions to install automated  valves. According to PHMSA, the agency provides this guidance to  operators to ensure operators follow it as they make decisions on whether  to install automated valves, but does not re-distribute the guidance at  regular intervals (e.g., annually).
According to PHMSA, inspectors see examples of how operators make  decisions to install automated valves during integrity management  inspections, but the inspectors do not formally collect this information or  share it with other operators. Current regulations give operators a large  degree of flexibility in making decisions in deciding to install automated  valves. As mentioned earlier, we spoke with operators that are using a  variety of risk-based methods for making decisions about automated  valves. For example, some used basic yes-or-no criteria, while others  applied commercially available computer software to model potential  incident outcomes. According to PHMSA, officials do not formally share  what they view as good methods for determining whether to install  automated valves. Officials stated they do not believe it is appropriate for  PHMSA to publicly share decision-making approaches from a single  operator, as doing so might be seen as an endorsement of that approach.  However, according to PHMSA, its inspectors may informally discuss  methods used by operators for making decisions to install automated  valves and suggest these approaches to other operators during  inspections. While the operators we spoke with represent roughly 18  percent of the overall hazardous liquid and natural gas transmission  pipelines in high-consequence areas in 2010, there are over 650  additional pipeline operators we did not speak with that may be using  other methods for determining whether to install automated valves. As  such, we believe that both operators and inspectors could benefit from  exposure to some of the methods used by other operators to make  decisions on whether to install automated valves.
We have previously reported on the value of organizations reporting and  sharing information and recommended that PHMSA develop methods to  share information on practices that can help ensure pipeline safety.  PHMSA already conducts a variety of information-sharing activities that  could be used to ensure operators are aware of both existing guidance  and of approaches used by other operators for making decisions to install  valves. While, according to PHMSA officials, the agency will not endorse  a particular operator’s approach or practice, it can and does facilitate the  exchange of information among operators and other stakeholders. For  example, PHMSA issues advisory alerts in the Federal Register on  emerging safety issues, including identified mechanical defects on  pipelines, incidents that occurred under special circumstances, and  reminders to correctly implement safety programs (e.g., drug and alcohol  screening). In addition, PHMSA administers a website different from its  primary website that, according to officials, is intended to ensure  communication with pipeline safety stakeholders, including the public,  emergency officials, pipeline safety advocates, regulators, and pipeline  operators. PHMSA also periodically conducts public workshops with  pipeline stakeholders on a wide variety of topics, including one in March  2012 on automated valves.
section_title: Conclusions
paragraphs: While PHMSA currently requires operators to respond to incidents in a  “prompt and effective manner,” the agency does not define these terms or  collect reliable data on incident response times to evaluate an operator’s  ability to respond to incidents. A more specific response time goal may  not be appropriate for all pipelines. However, some organizations in the  pipeline industry believe that such a performance-based goal can allow  operators to identify actions that could improve their ability to respond to  incidents in a timelier manner, and are taking steps to implement a  performance-based approach. A performance-based goal that is more  specific than “prompt and effective” could allow operators to examine the  numerous variables under their control within the context of an  established time frame to understand their current ability to respond and  identify the most effective changes to improve response times, if needed,  on individual pipeline segments. Reliable data would improve PHMSA’s  ability to measure incident response and assist the agency in exploring  the feasibility of developing a performance-based approach for improving  operator response to pipeline incidents.
One of the methods operators could choose to meet a performance- based approach to incident response is installing automated valves, a  measure some operators are already taking to reduce risk. Given the  different characteristics among valve locations, it is important for  operators to carefully weigh the potential for improved incident response  times against any disadvantages, such as the potential for accidental  closure and monetary costs, in deciding whether to install automated  valves as opposed to other safety measures. However, not all operators  we spoke with were aware of existing PHMSA guidance and PHMSA  does not formally collect or share evaluation approaches used by other  operators to make decisions about whether to install automated valves.  Such information could assist operators in evaluating the advantages and  disadvantages of these valves and help them determine whether  automated valves are the best option for meeting a performance-based  incident response goal.
section_title: Recommendations for Executive Action
paragraphs: We recommend that the Secretary of Transportation direct the PHMSA  Administrator to take the following two actions:
To improve operators’ incident response times, improve the reliability  of incident response data and use these data to evaluate whether to  implement a performance-based framework for incident response  times.
To assist operators in determining whether to install automated  valves, use PHMSA’s existing information-sharing mechanisms to  alert all pipeline operators of inspection and enforcement guidance  that provides additional information on how to interpret regulations on  automated valves, and to share approaches used by operators for  making decisions on whether to install automated valves.
section_title: Agency Comments
paragraphs: We provided the Department of Transportation with a draft of this report  for review and comment. The department had no comments and agreed  to consider our recommendations.
We are sending copies of this report to relevant congressional  committees, the Secretary of Transportation, and other interested parties.  In addition, this report will also be available at no charge on GAO’s  website at http://www.gao.gov.
If you or your staff have any questions about this report, please contact  me at (202) 512-3824 or flemings@gao.gov. Contact points for our  Offices of Congressional Relations and Public Affairs may be found on  the last page of this report. GAO staff who made key contributions to this  report are listed in appendix IV.
section_title: Appendix I: Objectives, Scope, and Methodology
paragraphs: The objectives of our review were to determine (1) the opportunities that  exist to improve the ability of transmission pipeline operators to respond  to incidents and (2) the advantages and disadvantages of installing  automated valves in high-consequence areas and ways that the Pipeline  and Hazardous Materials and Safety Administration (PHMSA) can assist  operators in deciding whether to install valves in these areas.
To address our objectives, we reviewed regulations, National  Transportation Safety Board (NTSB) incident reports, and PHMSA  guidance and data on enforcement actions, pipeline operators, and  incidents, related to onshore natural gas transmission and hazardous  liquid pipelines. We also attended industry conferences and interviewed  officials at PHMSA headquarters and regional offices (Eastern,  Southwestern, and Western), state pipeline safety agencies, pipeline  safety groups, and industry associations. Specifically, we interviewed  officials from the American Gas Association, American Petroleum  Institute, Arizona Office of Pipeline Safety, Association of Oil Pipelines,  Interstate Natural Gas Association of America, National Association of  Pipeline Safety Representatives, NTSB, Pipeline Research Council  International, Public Utilities Commission of Ohio, and West Virginia  Public Service Commission.
To address both objectives, we also conducted case studies on eight  hazardous liquid and natural gas pipeline operators. We selected these  operators based on our review of PHMSA data on the operators’ onshore  pipeline mileage, product type and prior incidents, recommendations from  industry associations and PHMSA, and to ensure geographic diversity.  We selected six hazardous liquid and natural gas pipeline operators with  a large amount of pipeline miles in high-consequence areas that also  reported recent incidents (i.e., one or more incident(s) reported from 2007  through 2011) with a range of characteristics, such as: affected a high- consequence area; resulted in an ignition/explosion; or involved an  automated valve. We also selected one natural gas pipeline operator and  one hazardous liquid pipeline operator with a small number of pipeline  miles in high-consequence areas, to obtain the perspective of smaller  pipeline operators. Specifically, we interviewed officials from:
Belle Fourche Pipelines (Casper, Wyoming)—Hazardous Liquids;
Buckeye Partners (Breinigsville, Pennsylvania)—Hazardous Liquids;
Enterprise Products (Houston, Texas)—Hazardous Liquids and
Granite State Gas Transmission (Portsmouth, New Hampshire)—
Kinder Morgan-Natural Gas Pipeline Company (Houston, Texas)—
Phillips 66 (Houston, Texas)—Hazardous Liquids;
Northwest Pipeline GP (Salt Lake City, Utah)—Natural Gas; and
Williams-Transco (Houston, Texas)—Natural Gas.
To determine what opportunities exist to improve the ability of  transmission pipeline operators to respond to incidents, we identified  several factors that influence pipeline operators’ incident response  capabilities. To do so, we discussed prior incidents, incident response  times, and federal oversight of the pipeline industry with officials from  PHMSA, state pipeline safety offices, industry associations, and safety  groups. We also spoke with operators about their prior incidents and the  factors that influenced their ability to respond. We also examined 2007 to  2011 PHMSA incident data, including data on total number of incidents,  type of incident (leak or rupture), type of pipeline where the incident  occurred, and the date and time when: an incident occurred; an operator  identified the incident; operator resources (personnel and equipment)  arrived on site; and an operator shut down a pipeline or facility. We  assessed the reliability of these data through discussions with PHMSA  officials and selected operators. We determined that data elements  related to numbers of incidents, types of releases, and types of pipeline  where incidents occurred were reliable for the purpose of providing  context, but that data elements related to response time were not  sufficiently reliable for the purpose of conducting a detailed analysis of  relationships between response time and other factors. We also reviewed  federal requirements, prior GAO reports, and industry and government  performance standards related to emergency response within the pipeline  industry.
To determine the advantages and disadvantages of installing automated  valves in high-consequence areas and the ways that PHMSA can assist  operators in deciding whether to install these valves, we identified the key  factors that should be used in deciding whether to install automated  valves in high-consequence areas. We used two categories of sources to  identify the key factors:  (1)  Literature review. We conducted a literature review of previous  research on pipeline incidents. Specifically, we used online  research software to search through databases of scholarly and  peer-reviewed materials—including articles, journals, reports,  studies, and conferences dating back to 1995—which identified  over 200 sources.  (2)  Interviews with industry stakeholders. During our interviews with  officials from industry associations and pipeline safety groups, we  discussed the advantages and disadvantages of installing these  valves.
To ensure that the literature review included just those documents that  were relevant to our purpose, two analysts independently reviewed  abstracts from the 200 sources identified to determine whether they were  within the scope of our review. Each source had to meet specific criteria,  including mentioning automated valves, pipeline incidents, and operator  emergency response. We excluded sources that were overly technical for  the purposes of our review. To ensure these analysts were making similar  judgments, they separately examined a random sampling of each other’s  sources. The analysts then added sources suggested by industry  stakeholders during our interviews and reviewed them using the same  criteria. After excluding documents that were not publicly available, one  analyst reviewed these sources to identify advantages and disadvantages  operators should consider when making decisions to install automated  valves. A second analyst reviewed the analysis and performed a spot  check on identified advantages and disadvantages. Specifically, the  second analyst picked four of the sources at random to review and  compared the advantages and disadvantages he identified to those of the  first analyst. As part of our case studies, we discussed these advantages  and disadvantages with operators. We also collected information from  operators on their methods for deciding whether to install automated  valves, as well as specific pipeline segments and valve locations where  operators made such decisions (see app. II). We contacted vendors  (manufacturers and installers) of automated valves to identify the range of  costs for purchasing and installing these valves. We also discussed the  regulations with officials from PHMSA headquarters and regional offices,  state pipeline safety offices, and pipeline operators to determine what, if  any, additional guidance would help operators apply the current  regulations on installing automated valves.
We conducted this performance audit from March 2012 to January 2013  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.
section_title: Appendix II: How Select Operators Determined Whether to Install Automated Valves
paragraphs: We conducted site visits to eight hazardous liquid and natural gas  pipeline operators with different amounts of pipeline miles in or affecting  high-consequence areas. Seven of the eight operators we visited told us  they use approaches that consider both the advantages and  disadvantages of installing automated valves on a case-by-case basis as  opposed to other safety measures; the eighth operator stated that it  follows a corporate strategy of installing automated valves in all high- consequence areas. A brief description of the approach used by each of  the eight operators, based on our discussions with them, follows.
Pipeline operator: Belle Fourche  Product type: Hazardous liquid  Number of pipeline miles: 460 (total); 135 (could affect high- consequence areas)
Decision-making approach: The operator assesses each pipeline  segment using spill-modeling software to determine the amount of  product release and extent of damage that would occur in the event of an  incident. The software considers flow rates, pressure, terrain, product  type, and whether the segment is located over land or a waterway.  Monetary costs are considered as part of the decision-making process,  including the cost of installing communications equipment and gaining  access to the valve location when the operator does not own the right of  way. The operator stated that installing a remote-control valve costs  between $100,000 and $500,000. Automatic-shutoff valves are not  considered as the operator believes an accidental closure could lead to  pipeline ruptures.
Results to date: According to Belle Fourche officials, this approach has  not resulted in any decisions to install automated valves because the  advantages have not outweighed the disadvantages on any of the  pipeline segments assessed.
Pipeline operator: Buckeye Partners  Product type: Hazardous liquid  Number of pipeline miles: 6,400 (total); 4,179 (could affect high- consequence areas)
Decision-making approach: The operator assesses each pipeline  segment using spill-modeling software to determine the amount of  product release and extent of damage that would occur in the event of an  incident. The operator considers installation of an automated valve when  this modeling shows such a valve would 1) reduce the size of the incident  by 50 percent or more and 2) significantly reduce the consequences of an  incident. The operator conducts additional analysis to determine the  location where the automated valve would lead to the largest reduction in  spill volume and overall consequences of an incident. Monetary costs are  considered as part of the decision-making process, including costs for  gaining access to pipeline when the operator does already not own the  right of way. The operator stated that installing a remote-control valve  costs between $35,000 and $325,000. Automatic-shutoff valves are  considered, but not typically installed, as the operator believes an  accidental closure could lead to a pipeline rupture.
Results to date: According to Buckeye Partners officials, this approach  has resulted in additional analysis of the possible installation of 25  remote-control valves along 75 pipeline segments assessed.
Pipeline operator: Phillips 66  Product type: Hazardous liquid  Number of pipeline miles: 11,290 (total); 3,851 (could affect high- consequence areas)
Decision-making approach: The operator assesses every 100 feet of  pipeline (which covers all pipeline segments) using spill-modeling  software to determine the amount of product release and extent of  damage that would occur in the event of a complete rupture. The operator  also uses a relative consequence index for individual pipeline segments  that considers the impact to high-consequence areas. Automated valve  projects are further evaluated if 1) the potential drain volume is greater  than 1,000 barrels, 2) the pipeline segment exceeds a certain threshold  on the consequence index, or 3) the existing automated valves are  greater than 7.5 miles apart. Monetary costs are considered as part of the  decision-making process, including the cost of installing communications  equipment, access to power, gaining access to the valve’s location when  the operator does not own the right of way, and local construction costs.  The operator stated that installing an automated valve costs between  $250,000 and $500,000. Automatic-shutoff valves are not considered as  the operator believes an accidental closure could lead to pipeline  ruptures.
Results to date: According to the Phillips 66 officials, this approach has  resulted in decisions to install 71 automated valves in the 508 high- consequence area locations assessed.
Pipeline operator: Enterprise Products  Product type: Hazardous liquid and natural gas  Number of pipeline miles: 23,012 (total); 8,783 (could affect or in high- consequence areas)
Decision-making approach: The operator assesses each pipeline  segment using spill-modeling software to determine the amount of  product release and extent of damage that would occur in the event of an  incident. The software considers factors such as topography and the  placement of existing valves. The operator also uses a risk algorithm to  identify threats to individual pipeline segments. The operator told us that it  does not have specific criteria for guiding decisions to install automated  valves; rather, officials make judgment calls based on the results of spill  modeling and the application of the risk algorithm. Monetary costs are  considered as part of the decision-making process, including the cost of  installing communications equipment and the amount of necessary  infrastructure work. The operator stated that installing a remote-control  valve costs between $250,000 and $500,000. Pipelines carrying gas or  highly volatile liquids—which are in gas form when released into the  atmosphere—are excluded from consideration, according to the operator,  because industry studies have shown that automated valves do not  significantly improve incident outcomes for these product types.
Results to date: According to Enterprise Products officials, this approach  has not resulted in any decisions to install automated valves because the  advantages have not outweighed the disadvantages on any of the  pipeline segments assessed.
Pipeline operator: Granite State Gas Transmission  Product type: Natural gas  Number of pipeline miles: 86 (total); 11 (high-consequence areas)
Decision-making approach: The operator assesses individual pipeline  segments in high-consequence areas using risk analysis software that  considers the operator’s response time to an incident, population in the  area, and pipeline diameter, among other variables. Monetary costs are  considered as part of the decision-making process, including the cost of  installing communications equipment and costs to change or improve the  existing leak detection system. The operator stated that installing an  automated valve costs between $40,000 and $50,000. Automatic-shutoff  valves are not considered, as officials believe that they could lead to  unintended consequences, such as accidental closures.
Results to date: According to Granite State Gas Transmission officials,  this approach has resulted in decisions to install remote-control valves in  30 of the 30 locations assessed.
Pipeline operator: Kinder Morgan-Natural Gas Pipeline Company of  America (NGPL)
Product type: Natural gas  Number of pipeline miles: 9,800 (total); 569 (high-consequence areas)
Decision-making approach: The operator follows a long-term corporate  risk management strategy for NGPL, developed in the 1960s, that calls  for installing automatic-shutoff valves across its pipeline system  regardless of advantages and disadvantages for individual pipeline  segments. The operators told us that automatic-shutoff valves, as  opposed to remote-control valves, were chosen because they reduce the  potential for human error when making decisions to close valves. Officials  stated that the biggest concern of using automatic-shutoff valves is the  potential for accidental closures, but they believe they have developed a  procedure for managing the pressure sensing system that effectively  adapts to pressure and flow change and minimizes or eliminates these  types of closures. Monetary costs are not considered as part of the  decision-making process. The operator stated that installing automatic- shutoff valve on an existing manual valve costs between $48,000 and  $100,000.
Results to date: According to Kinder Morgan officials, this approach has  resulted in the installation of automated valves at 683 out of 832 locations  across the pipeline system. Officials plan to automate the remaining  valves over the next several years.
Pipeline operator: Northwest Pipeline GP  Product type: Natural gas  Number of pipeline miles: 3,900 (total); 170 (high-consequence areas)
Decision-making approach: The operator uses a decision tree to  assess individual pipeline segments based on several criteria, including  the location of the valve (e.g., high-consequence area), diameter of the  pipe, and the amount of time it takes for an operator to respond upon  notification of an incident. The operator will install an automated valve in  any high-consequence, class 3, or class 4 areas on large diameter pipe  (i.e., above 12 inches) where personnel cannot reach and close the valve  in under an hour. Monetary costs are considered as part of the decision- making process for the purposes of determining the most cost-effective  way to ensure the operator can respond within one hour to incidents in  high-consequence areas. The operator stated that installing an  automated valve costs between $37,000 and $240,000. Automatic-shutoff  valves are not installed in areas where an accidental closure could lead to  customers losing service (i.e., in places where there is a single line feed  servicing the entire area) or where pressure fluctuations may  inadvertently activate the valve.
Results to date: According to Northwest Pipeline GP officials, this  approach has resulted in decisions to install automated valves at 59 of  the 730 locations assessed.
Pipeline operator: Williams Gas Pipeline-Transco  Product type: Natural gas  Number of pipeline miles: 11,000 (total); 1,192 (high-consequence  areas)
Description of decision-making method: The operator uses a decision  tree to assess individual pipeline segments based on several criteria,  including the location of the valve (e.g., high-consequence area),  diameter of the pipe, and the amount of time it takes for an operator to  respond upon notification of an incident. The operator will install an  automated valve in any high-consequence, class 3, or class 4 areas on  large diameter pipe (i.e., above 12 inches) where personnel cannot reach  and close the valve in under an hour. Monetary costs are considered as  part of the decision-making process for the purposes of determining the  most cost-effective way to ensure the operator can respond within one  hour to incidents in high-consequence areas. The operator stated that  installing an automated valve costs between $75,000 and $500,000.  Automatic-shutoff valves are not installed in areas where an accidental  closure could lead to customers losing service (i.e., in places where there  is a single line feed servicing the entire area) or where pressure  fluctuations may inadvertently activate the valve.
Results to date: According to Williams Gas Pipeline-Transco officials,  this approach has resulted in decisions to install automated valves at 56  of the 2,461 locations assessed.
section_title: Appendix III: Automated Valve Costs
paragraphs: The eight operators we spoke with provided a range of cost estimates for  installing automated valves—from as low as $35,000 to as high as  $500,000 depending on the location and size of the pipeline, and the type  of equipment being installed, among other things. While both hazardous  liquid and natural gas transmission pipeline operators estimated a similar  cost range from about $35,000 to $500,000, hazardous liquid pipeline  operators tended to estimate higher costs. Specifically, two of the three  operators that exclusively transport hazardous liquids estimated that the  minimum costs of installing an automated valve was $100,000 or higher  and the maximum was $500,000. In contrast, pipeline operators that  exclusively transport natural gas all estimated that the minimum cost was  $75,000 or lower and three of the four operators estimated that maximum  costs would be $240,000 or lower.
We also spoke with five equipment vendors and six contractors that install  valves to gather additional perspective on the cost of purchasing and  installing automated valve equipment. According to estimates provided  by these businesses, the combined equipment and labor costs range  between $40,000 and $380,000. Specifically, equipment costs range from  $10,000 to $75,000 while labor costs range from $30,000 to $315,000.  (See table 3.) Vendors stated that the cost of installing an automated  valve depends primarily on the functionality of the equipment (for  example, additional controls would increase the cost), while contractors  stated that these costs depend on the diameter and location of the  pipeline. Vendors and contractors had varying opinions on whether the  costs were greater to install an automated valve on hazardous liquid or  natural gas pipeline.
section_title: Appendix IV: GAO Contact and Staff Acknowledgments
subsections: section_title: GAO Contact
paragraphs: Susan Fleming, (202) 512-3824 or flemings@gao.gov.
section_title: Staff Acknowledgments
paragraphs: In addition to the contact above, Sara Vermillion (Assistant Director),  Sarah Arnett, Melissa Bodeau, Russ Burnett, Matthew Cook, Colin Fallon,  Robert Heilman, David Hooper, Mary Koenen, Grant Mallie, Josh  Ormond, Daniel Paepke, Anne Stevens, and Adam Yu made key  contributions to this report.