Roughly two-thirds of domestic energy supplies are transported through over 2.6 million miles of pipelines throughout the United States. These pipelines carry hazardous liquids and natural gas from producing wells to end users (residences and businesses). Natural gas, which is combustible, accounts for 99.8 percent of all gas distributed in the United States. Other combustible gases transported by pipeline include hydrogen, landfill gas, synthetic gas, and propane. Within this nationwide system, three main types of pipelines serve different purposes and users (see fig. 1): Gathering pipelines. The estimated 11,500 miles of onshore gas gathering pipelines subject to PHMSA regulation collect natural gas from wells in production areas. These pipelines then typically transport the gas to processing facilities, which in turn refine it and send the gas to transmission pipelines. Gathering pipelines range in diameter from about 2 to 12 inches and operate at pressures that range from about 5 to 1,400 pounds per square inch (psi). These pipelines tend to be located in rural areas but can also be located in urban areas. PHMSA estimates that another 230,000 miles of gas gathering pipelines are not subject to federal regulation based on their generally rural location and low operating pressures. Transmission pipelines. The estimated 298,000 miles of onshore transmission pipelines carry natural gas, sometimes over hundreds of miles, to communities and large-volume users (e.g., factories). Transmission pipelines tend to have the largest diameters and pressures of any type of pipeline, generally ranging from 12 inches to 42 inches in diameter and operating at higher pressures ranging from 400 to 1,440 psi. Distribution pipelines. The estimated 2,170,000 miles of natural gas distribution and service pipelines transport natural gas from transmission pipelines to residential, commercial, and industrial customers. These pipelines tend to be smaller, sometimes less than 1 inch in diameter, and operate at lower pressures, from 0.25 to 100 psi. A specific pipeline only carries one type of gas. These gases may be colorless and odorless, which is why odorizing them may be necessary to safely alert people of a leak. All odorants used in the United States contain sulfur. According to PHMSA officials, there are nine primary sulfur-based odorants used domestically for transporting combustible gas, all but one contain mercaptan—a type of chemical with a distinctive sulfur smell—which is blended with other chemicals for stability. Pipeline operators select the odorant blend that works best for their pipeline network. Distribution pipeline operators add the odorant to their gas, usually at the “city gate”, or the place where transmission pipelines connect to a distribution pipeline network. The odorant is transported and stored in a concentrated liquid form that has a strong smell, is flammable, and is toxic. The odorant is injected into the gas stream at the “city gate” odorization station and vaporizes into the gas. In its diluted form, the odorants are nontoxic. PHMSA, within the Department of Transportation (DOT), administers DOT’s national regulatory program to ensure the safe transportation of natural gas by pipeline. PHMSA oversees and enforces pipeline operators’ compliance with federal odorization requirements for interstate pipelines, which are primarily transmission pipelines. Most states have agreements with PHMSA to oversee and enforce pipeline operators’ compliance with federal requirements—including odorization requirements—for intrastate pipelines, which are primarily distribution pipelines. These states may also impose safety requirements that are more stringent than federal requirements. Under the current regulatory system, most gathering pipelines are not subject to federal safety requirements, based on their location. Only gathering pipelines close to populated areas or waterways are currently subject to federal requirements. In March 2012, we reported that land use changes have resulted in development encroaching on existing gathering pipelines and the increased extraction of oil and natural gas from shale deposits has resulted in the development of new gathering pipelines, some of which are larger in diameter and operate at higher pressure than older pipelines. Therefore, we recommended that PHMSA collect data on gathering pipelines to help determine whether to expand regulation of these pipelines. In April, 2016, PHMSA issued the Gas Transmission and Gathering Notice of Proposed Rulemaking that would: 1) require all gas gathering pipeline operators to submit operating and accident data to PHMSA, 2) more clearly define “gathering pipeline” to better identify pipelines subject to PHMSA’s requirements, and 3) increase the number of gathering pipeline miles under PHMSA’s jurisdiction. PHMSA estimates that the new rule would increase the number of gathering pipeline miles with reporting requirements by 344,000 and the number of gathering pipeline miles subject to additional safety measures by almost 70,000. The overall framework for federal gas pipeline regulations—including odorization requirements—is designed to mitigate risk. All pipelines regulated by PHMSA are required to meet uniform, minimum safety standards. Regarding odorization, these minimum standards prescribe that a combustible gas must be odorized so that at a concentration in air of one-fifth of the lower explosive limit, the gas is readily detectable by a person with a normal sense of smell. The proximity of pipelines to populated areas, where leaks present the greatest risk, determines whether or not the gas needs to be odorized. Since 1970, PHMSA has categorized pipelines into four classes based on their proximity to populated areas to determine the odorization requirements for gas transported by distribution and transmission pipeline. Class 1 locations are in rural areas and Class 4 locations are in densely populated areas (see table 1.). All combustible gases transported by distribution pipelines are required to be odorized because these pipelines are primarily in populated areas. Some transmission pipelines in highly populated—Class 3 and 4—areas are also required to be odorized. In addition, PHMSA has a supplemental risk-based regulatory program termed “integrity management” for pipelines in “high-consequence areas” where an incident would have greater consequences for public safety or the environment. Integrity management has been a part of PHMSA’s risk- based regulatory approach for natural gas transmission pipelines since 2004, and for natural gas distribution pipelines since 2011. The risk- based integrity management programs for natural gas transmission pipelines require operators to systematically identify and mitigate risks to pipeline segments located in high-consequence areas. For example, in these areas operators must monitor their pipelines for signs of corrosion and repair corroded lines within a specified period of time. High- consequence areas for natural gas pipelines include highly populated or frequently used areas, such as parks. These areas may overlap with Class 3 or Class 4 locations. The integrity management program for distribution pipelines applies to all distribution pipelines due to their proximity to populated areas. Almost all officials and stakeholders we interviewed and the state pipeline safety officials we surveyed told us that the advantage of using sulfur- based odorants to odorize combustible gas transported by pipeline is public safety. Sulfur-based odorants have a low-odor threshold, so are easily detected at low concentrations. With a smell similar to that of rotten eggs, this odor is particularly advantageous when used in distribution pipelines that are located in areas where people congregate (e.g., homes, businesses and hospitals). If individuals smell an odorant, they can call emergency services and alert those nearby of a potential gas leak, possibly helping to prevent an explosion that could result in the loss of life and property. According to federal regulations, all local distribution companies must conduct outreach to educate the public and others on what to do when they smell a gas leak. To this end, the 2017 American Gas Association Odorization Manual (manual) states that some local distribution companies have gone beyond placing the traditional scratch-and-sniff insert in customers’ billing statements—to inform them about gas leaks and odor—to implementing “Smell Gas Act Fast!” campaigns. According to the manual, these campaigns are designed to better educate the public on the smell and nature of natural gas, along with the need to quickly take action if the odor is detected. Responding immediately to the smell of natural gas can help to prevent possible accidents. For example, when authorities were reportedly called to a Rockville, Maryland home in November 2017 to investigate an odor from a natural gas leak, authorities evacuated several nearby homes as a safety precaution in the event of an explosion, until the source of the leak could be identified and addressed. While nearly all stakeholders we interviewed said that public safety was the key advantage associated with odorizing combustible gases (in particular, combustible gases transported by distribution pipeline), some experts expressed differing opinions on the use of handheld electronic combustible gas detection devices as an alternative to detect gas leaks. According to one expert, these devices are better suited to detect gas at levels much lower than an individual’s sense of smell would allow. This expert also noted that odor does not wake a sleeping individual so a gas leak could go undetected for hours. However, a second expert noted that during his experience with pipeline accident investigations over the past 40 years, he was aware of about 10 cases in which deceased individuals were found after a gas leak accident holding a portable combustible gas detector because (1) the device may not have indicated the presence of gas in one location while a nearby location may have been explosive due to a gas leak; or (2) the user may not have been properly trained on the instrument’s limitations to identify a safe area. Accordingly, that expert stated that odorization is the most effective safety method for alerting the public of a possible gas leak. Additionally, a third expert noted that (1) electronic detectors can be difficult to place in certain areas and (2) odorants allow the public to quickly detect gas leaks without acquiring or maintaining external equipment. The most common disadvantage of sulfur-based odorants cited by officials and stakeholders we contacted is the need to remove the odorant for some industrial processes. Officials from both federal safety regulatory agencies we interviewed (PHMSA and NTSB); approximately half of state pipeline safety officials surveyed; and about half of the stakeholders interviewed reported that sulfur-based odorants used in transmission pipelines can cause an adverse chemical reaction during processing for some industries. For example, sulfur in natural gas can be detrimental in the production of electricity, fertilizer, and glass because it interferes with the catalyst used during production. PHMSA and NTSB officials and about half of the stakeholders said that before these items are produced, operators must remove any added (or naturally occurring) sulfur from their combustible gas, adding another step to production. One expert and three stakeholders told us that removing the odorant also resulted in added cost for some operators. However, because most transmission pipelines are in less populated areas and not odorized, many manufacturers currently receive unodorized gas from transmission pipelines and do not need to remove odorant, according to the industry associations we interviewed. In addition, some stakeholders warned that accidental spills of concentrated odorant, using more odorant than needed, or releasing excessive amounts of odorant during operators’ maintenance activities can lead to false alarm calls. One pipeline operator told us that an employee spilled odorant on a glove and the public made several false alarm calls due to the odorant’s potent smell as the employee drove through town with the glove on the back of a truck. Officials from PHMSA, an official from a pipeline safety organization and representatives from two pipeline industry associations told us that the public could get accustomed to these types of odorant leaks and begin to ignore them or have a false sense of security when a real gas leak does occur. For example, the official from the pipeline safety organization told us that he has heard of at least one location where odorant leaks frequently occurred, and the public began to ignore the smell. Additionally, under certain conditions, sulfur-based odorants can be hazardous to human health and the environment. A few stakeholders told us that odorants released in excessive amounts may cause health concerns. For example, during a presentation before the Pipeline Safety Trust, a Los Angeles County public health official stated that it appears a sulfur-based odorant was related to public health complaints made in 2015 after a 4-month long natural gas leak from a natural gas storage facility in California’s Aliso Canyon. Many of the reported symptoms matched those made after a 2008 natural gas storage tank leak in Alabama, which included respiratory problems; eye, nose, and throat irritation; headache; nausea; and dizziness. While at least one study has been conducted and another is planned on the long-term effects of sulfur- based odorants on human health, no direct cause and effect relationships have been established. Finally, a few stakeholders noted potential environmental hazards regarding the use of odorants. For example, one stakeholder told us that odorants can become a hazardous waste depending on the quantity used and the amount of time the chemical remains in one location prior to use; one expert and another stakeholder noted that sulfur-based odorants when spilled may contaminate waterways; and four experts and two stakeholders warned that when combusted, sulfur-based odorants can produce acid rain. Also, according to PHMSA officials, these odorants are both toxic and flammable in their concentrated state. However, none of the stakeholders provided specific examples of when an odorant caused environmental damage. General consensus exists among those we spoke with (including federal regulatory and safety officials, experts identified by the National Academies, and industry stakeholders) that federal requirements to odorize all gases in distribution pipelines are sufficient as written and do not need to be modified. PHMSA and NTSB officials we interviewed and many commenting stakeholders articulated this view. In addition, state pipeline officials we surveyed generally did not indicate a need to change federal regulations for odorizing distribution pipelines. Due to the proximity of distribution pipelines to areas where people live and work, officials, experts, and stakeholders we interviewed emphasized the importance of odorizing gas in distribution pipelines to reduce the safety risk to the public. As we have previously reported, the operating characteristics of distribution pipelines make odorant a key factor in reducing safety risk. In 2012 we reported that distribution pipelines operate at lower pressures, so pipeline failures are more likely to involve slow leaks rather than explosive ruptures. Leaking gas can accumulate in confined spaces, or migrate away from the pipeline until it finds an ignition source and potentially causes injury, death, and/or property damage. These slow leaks are difficult to see or hear, so odorants provide a critical warning to call emergency services and inform those nearby of a potential gas leak before it ignites. Of those we interviewed or surveyed, about half of stakeholders and a third of state pipeline safety officials did not indicate a need to modify existing regulations for odorizing gas in gathering pipelines. Further, a few commenting experts said odorizing those pipelines would be technically challenging. According to the experts, technological challenges stem from the fact that gas contains natural sulfur at many of the wells where gathering pipelines collect the raw gas. The natural sulfur in the raw gas could counteract the added chemical sulfur odorant, masking the smell of each and lowering the effectiveness of the odorant. Further, one stakeholder said that odorizing gathering pipelines would be logistically difficult and expensive given the number of wells that would each need an odorization station. For example, according to this stakeholder, there are roughly 500,000 gas wells nationwide and each odorizer would cost $2,000 as a capital investment. In addition, this stakeholder said that any safety benefit of adding odorant would be limited because most gas wellheads and gathering pipelines are located in sparsely populated rural areas. While the majority of stakeholders and state survey respondents did not see a need to odorize gas in gathering pipelines, a third of the state safety officials and three other stakeholders said all gathering pipelines should be odorized for additional safety regardless of any technical challenge. However, requiring all gathering pipelines to be odorized at the federal level would have to be consistent with federal pipeline safety regulations. According to the safety regulations, a risk assessment, including an assessment of the benefits and costs of proposed regulatory standards, is required to be considered in any decision on whether to impose a new safety standard. According to PHMSA officials, they do not have the data to report on any incidents on gathering pipelines where odorant may have made a difference. Moreover, PHMSA officials stated that they do not have the data to formulate an educated opinion or viewpoint as to the need to odorize gathering pipelines. To address this lack of data, the Pipeline Safety -Safety of Gas Gathering Pipelines rulemaking, if approved, will provide PHMSA with more data on gas gathering pipeline infrastructure and incident data. According to PHMSA officials, the data collected will inform PHMSA on the best path forward regarding further regulation of gas gathering pipelines, including the need for odorization. Officials anticipate publishing the final rule in summer 2019. Officials, stakeholders and survey respondents generally disagreed about the need to odorize all transmission pipelines. Officials from NTSB as well as about half of the stakeholders we contacted said the current regulations for odorizing gas in certain transmission pipelines in populated areas were sufficient. Additionally, NTSB officials said they were not aware of incidents where odorants in a transmission pipeline would have alerted the public in time to prevent the incident. These officials and stakeholders generally said that odorizing gas in transmission pipelines is not an effective means of reducing the risk of an incident. For example, one stakeholder said that at the typically high pressure at which most transmission pipelines operate, even a relatively small hole in the pipeline would cause a rupture that would excavate the earth around it so people would hear and see the evidence of the leak. Some experts also said that odorizing gas in all transmission pipelines could have increased costs and other challenges for pipeline operators or gas end users. For example, one expert said that odorizing all gas transported in the transmission pipeline system would require tens of thousands of odorization facilities. This expert also said that if gas is odorized in transmission pipelines, some industries currently receiving unodorized gas will be affected negatively because they either must incur the additional processing and cost of removing the odorant or find new ways to receive gas that is not odorized. Further, PHMSA officials and representatives from the Interstate Natural Gas Association of America said that the integrity management program for transmission pipelines provides more preventative, risk-based safety management than odorants, which rely on reducing risk through early detection of a leak that has already occurred. The integrity management program requires operators to assess the integrity of their pipelines within high consequence areas—which, by definition, encompass Class 3 and 4 locations—on a regular basis using any of three approved methods: (1) running an in-line inspection tool, or “smart pig”, through the pipeline to detect anomalies, such as corrosion, that can cause leaks (2) conducting a direct assessment using data and direct examination of the pipeline from aboveground to identify problem areas, or (3) hydrostatically testing a portion of the pipeline by removing the gas product, replacing it with water, and increasing the pressure of the water above the maximum allowable operating pressure of the pipeline to test its integrity. These inspection methods are designed to detect issues that could cause a gas leak before the leak occurs. Following the assessments, pipeline operators are required to prioritize and repair anomalies found during assessments. While odorants could be added in addition to integrity management requirements, PHMSA officials said that integrity management more effectively helps assure an acceptable level of safety for transmission pipelines than an odorant could because the risk assessments focus on the potential causes of leaks and ruptures for these types of pipelines and, therefore, are more preventative than odorizing. In a September 2006 report, we found that PHMSA’s gas pipeline integrity management program benefits public safety by incorporating risk-based management principles into pipeline safety oversight, and in June 2013, we reported that transmission pipeline operators were conducting periodic assessments and making repairs to pipelines in high consequence areas. Transmission pipeline operators are also required through the integrity management program to proactively take measures to reduce the risk or potential impact of an accident. Based on inspections of interstate transmission operators’ integrity management programs, PHMSA officials noted that—while transmission pipeline operators could opt to odorize gas in a transmission pipeline—they are not aware of any operator to date that has concluded that odorizing transmission pipelines was necessary to reduce risk. Instead, operators use tools such as electronic leak detection and remotely-controlled valves to detect potential leaks and shut down the pipeline if needed. While the preventative safety practices required under the gas transmission pipeline integrity management program are designed to mitigate risk without requiring the use of odorant, officials from two states and one stakeholder questioned the sufficiency of integrity management practices. However, as part of the ongoing two rulemakings: the Pipeline Safety: Safety of Gas Transmission Pipelines, MAOP Reconfirmation, Expansion of Assessment Requirements and Other Related Amendments and the Pipeline Safety - Safety of Gas Transmission Pipelines, Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments Rulemaking, PHMSA also plans to strengthen and expand requirements for the gas integrity management program for transmission pipelines. For example, PHMSA plans to expand the requirements for periodic assessments and subsequent repairs to additional pipeline mileage beyond that located in high consequence areas. PHMSA plans to publish these rulemaking in March and June, 2019, respectively. The 2016 PIPES Act includes a mandate for GAO to review PHMSA’s gas integrity management program as soon as PHMSA publishes the final rule. In contrast to the opinions expressed above that transmission pipeline odorization requirements are sufficient, 31 of 49 state pipeline safety officials surveyed responded that these requirements are not stringent enough for safety. Of these respondents, several said that exemptions that currently apply to some operators with transmission pipelines in Class 3 and Class 4 locations should not be allowed. There are several exemptions, determined by the overall class location of the pipeline or end use of the gas. For example, one class location exemption is that when at least 50 percent of the length of the pipeline downstream from the more populated Class 3 or Class 4 location is in a less populated Class 1 or Class 2 location, the gas does not need to be odorized (see fig. 2). Eliminating the current regulatory exemptions for certain transmission pipelines and requiring operators to odorize all gas transported by transmission pipeline through Class 3 or Class 4 locations may not be cost-beneficial under federal regulatory risk assessment principles, which direct the agency to assess the benefits and costs of changes in regulatory standards. For example, while four states cited increased public safety as the reason to remove the existing exemption, PHMSA and NTSB officials could not identify any incidents where odorants in a transmission pipeline would have prevented damage. In addition, as described above, some experts told us that removing the exemptions could have increased costs and other challenges for pipeline operators or gas end users. PHMSA officials also said that the definition of a high- consequence area under the gas integrity management program encompasses all Class 3 and Class 4 locations, so the risk-based preventative measures required under that program apply to the areas exempt from odorization requirements. We provided a draft of this product to DOT for review and comment. DOT provided technical comments that were incorporated, as appropriate. We are sending copies of this report to the appropriate congressional committees, the Secretary of the Department of Transportation, and other interested parties. In addition, the report is available at no charge on the GAO website at http://www.gao.gov. If you or your staff have any questions about this report, please contact me at (202) 512-2834 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 III. While our report focuses on sulfur-based odorants, which are used in the United States, we also asked experts and stakeholders about the advantages and disadvantages of non-sulfur based odorants. According to a German-based manufacturer of non-sulfur odorants, these odorants are used in some European countries, including Germany and Austria. This manufacturer also told us that the German energy industry has embraced using non-sulfur based odorants, in part, to meet German emissions regulations, as these odorants do not produce sulfur dioxide and contribute to acid rain when burned. Most of the experts and stakeholders that we interviewed were generally unfamiliar with non-sulfur based odorants. Those with some familiarity offered the following advantages and disadvantages. Three experts and stakeholders reported that non-sulfur based odorants: have less adverse impact on the environment; for example, no acid may cost less for some operators because less product may be needed than sulfur-based odorants; and do not adversely impact some operators’ processes. Four experts noted that non-sulfur based odorants: have a smell that the American public does not associate with a gas leak. Two experts commented that non-sulfur based odorants: may be chemically unstable; and can react with other compounds. Two experts noted that non-sulfur based odorants: may have a higher level of toxicity. Susan Fleming, (202) 512-2834 or FlemingS@gao.gov. In addition to the individual named above, other key contributors to this report were Sara Vermillion, Assistant Director; Sarah Jones, Analyst in Charge; Jennifer W. Clayborne; Timothy J. Guinane; David K. Hooper; Delwen A. Jones; Josh Ormond; Rebecca R. Parkhurst; and Kelly L. Rubin.
The nation's gas pipeline network moves about 74 billion cubic feet of combustible gas to homes and businesses daily. To alert the public of a gas leak before an explosion occurs, PHMSA has different requirements for odorizing gas. All gas transported by distribution pipelines throughout communities must be odorized. Gas transported across many miles by transmission pipelines is required to be odorized only in certain populated areas. There are no requirements to odorize gas in gathering pipelines. Congress included a provision in statute for GAO to review odor requirements for all pipelines. This report presents the views of federal and state pipeline safety officials and industry and safety stakeholders on: (1) the advantages and disadvantages of odorizing combustible gases in pipelines; and (2) whether and how federal requirements for odorizing pipelines should be modified. GAO reviewed relevant regulations and reports; surveyed officials in 48 states and the District of Columbia; and interviewed PHMSA and NTSB officials. GAO also interviewed 34 stakeholders, including 14 experts identified by the National Academies, and 20 other industry and safety stakeholders. Pipeline and Hazardous Materials Safety Administration (PHMSA) and National Transportation Safety Board (NTSB) officials, state officials, and stakeholders GAO contacted cited safety as the main advantage to odorizing combustible gases in pipelines, primarily for distribution pipelines in densely populated areas (see figure). Specifically, adding a chemical with a distinctive odor to gas allows the public to generally detect leaks before an explosion can occur. The most frequently cited disadvantage was that commonly used sulfur-based odorants must be removed—primarily from gas in transmission pipelines—before the gas can be used in certain processes, such as producing fertilizer. While federal odorization requirements follow a risk-based approach by focusing on pipelines in populated areas, the officials and stakeholders GAO contacted disagreed on the need to modify these requirements for some pipelines. Specifically, because distribution pipelines run through populated areas, everyone GAO contacted generally agreed that these pipelines should be odorized for safety, as currently required. For gathering pipelines, the majority of officials and stakeholders did not see a need to modify regulations because these pipelines would be technically challenging to odorize and are primarily located in rural areas. However, about two-thirds of state officials and about half of stakeholders said that additional transmission pipelines should be odorized for public safety. Conversely, officials from PHMSA and NTSB and about half of the stakeholders contacted noted that, because transmission pipelines operate at high pressure and generally rupture rather than leak, it is unlikely that odorant could mitigate risk. Instead, other required safety practices—such as internal pipeline inspections—can provide more preventative, risk-based safety management, according to PHMSA officials. In this regard, PHMSA officials said that they plan to strengthen risk-based safety requirements for transmission and gathering pipelines as part of on-going rulemakings. PHMSA anticipates issuing these rules in 2019.