Why is this study important?
The motivation for the study comes from people who make energy policy and who develop climate change policies in the U.S. and around the world. They want to know how switching to natural gas from coal and fuel oils will impact overall greenhouse gas emissions.
Because of significant technological advancements, the natural gas industry is growing dramatically. Natural gas, which is mostly methane, produces less carbon dioxide than oil or coal. But when unburned methane is released into the atmosphere, it is a potent greenhouse gas with a warming potential 28 to 34 times greater than carbon dioxide over a 100-year timeframe (and up to 84 times more potent over a 20 year timeframe). Depending on how much is emitted from the natural gas supply chain, methane could offset the benefit of using natural gas to reduce carbon dioxide emissions.
Why are methane emissions from our natural gas system a concern?
The reason for this is the good news/bad news associated with methane. The good news is when you burn natural gas, which is mostly methane, you reduce carbon dioxide emissions by a significant amount — by nearly half compared to coal and more than a quarter compared to fuel oil.
The bad news is, if you leak too much methane in the process of using natural gas to reduce carbon dioxide (CO2) emissions, you lose some of the benefit from reduced CO2 emissions. And since methane is about 84 times more potent than CO2 in the atmosphere over 20 years, it doesn’t take very much methane lost from the natural gas supply chain to cause an offset of some of the CO2 reductions.
Why are the measurements lower now than they were based on earlier estimates?
The improvements are the result of both regulatory changes and increased investment in leak prevention by utilities. However, the study also found significant variation by region, with some areas showing higher than average emissions. The researchers found that upgrades in metering and regulating stations, changes in pipeline materials, and better instruments for detecting pipeline leaks have led to methane emissions that are from 36% to 70% lower than current Environmental Protection Agency estimates when the data gathered for this study is combined with current pipeline miles and the numbers of facilities.
What’s the reason for regional variation?
It is reasonable to expect that the age of the infrastructure and climatic differences can explain the regional differences. This study did not look at those mechanisms specifically. Older systems tend to have pipes made from older materials, which are more prone to leakage. Temperature changes in colder climates also cause more wear and tear on gas distribution infrastructure. In addition, legal frameworks, regulatory support and utility investment programs can vary from place to place, influencing the extent to which older pipes and other infrastructure are replaced.
Are the methane leaks in my city a safety concern?
For safety reasons, the natural gas companies have a required leak survey program, where they survey their entire pipeline system on a multi-year basis. So, they are continually identifying and repairing leaks. They are looking for leaks, specifically, in order to continually improve the safety of the system.
They categorize the leaks as Class 1, 2 or 3. Class 1 leaks are hazardous. It doesn’t mean they’re the biggest leaks. It just means they may be next to a building or in a public place that is more of a hazard than if the same leak was in a more remote location. The companies grade the leaks and fix the Class 1 leaks immediately.
The Class 2 and 3 non-hazardous leaks are put on a schedule for timely repair and periodic review of their classification depending on the situation. We used the natural gas company’s current leak survey data to randomly pick out a set of leaks in the Class 2 and 3 categories to do our sampling.
What are EPA estimates for the amount of methane leaking from distribution pipelines in the United States?
The most recent EPA 2011 inventory estimates that there is approximately 1329 gigagrams per year of methane from distribution systems that is lost to the atmosphere. According to the EPA, methane emissions from the U.S. natural gas supply chain account for about 30% of total U.S. methane emissions. The EPA greenhouse gas (GHG) inventory uses current activity data (pipeline miles, number of services, etc), but uses emission factors largely unchanged from the 1992 GRI/EPA national sampling study.
EPA has issued and updated the GHG inventory for 2012 and also has a draft inventory for 2013. If you used data from this study how (if at all) would overall leakage change in these other two inventories?
EPA issues its inventory of greenhouse gas emissions every year and in addition to providing a new year of data, updates emission estimates from previous years using improved data and methods. For example, in April of 2015, EPA will issue a final inventory with the first emission estimates for 2013, as well as revised emissions from every year since 1990.
Since this study estimated emissions specifically for 2011, it should only be compared directly to 2011 estimates from the 2012, 2013 (or beyond) inventories. This study found 393 Gigagrams (upper bound = 854 Gg) of methane from local distribution, which is 36%-70% lower than the EPA 2011 emission estimate of 1,329 Gg from the inventory published in 2013.
EPA updated their estimate of 2011 emissions to 1,311 Gg in the 2012 inventory and 1,315 Gg in the draft 2013 inventory. Using these updated values, this study’s estimates are 36-70% lower than the inventory 2011 estimate.
It is possible to use the data from this study to estimate emissions from years after 2011. To do that requires combining emission factors from this study with EPA activity factors (e g., pipeline miles) specific to the target year. For 2012, emissions using this study’s data are 373 Gg (upper bound = 814 Gg), which is 36% to 70% lower than the EPA estimate. For 2013, emissions using this study’s data are 392 Gg (upper bound = 834 Gg), which is 37% to 71% lower than the EPA estimate.
How do your methods differ from previous efforts to take these measurements?
Previous emission estimates are based on measurements taken in the early 1990s (a nationwide study in which Washington State University participated). In the 1990s, different methods were used compared to today’s methods. Different locations were sampled, and only about half as many samples were collected compared to our current study.
In the 1990s, the method involved digging down, isolating pipe, and measuring the gas flow rate required to keep the pipe pressurized; this flow rate was then taken as the leak rate from the buried pipe. This rate was next corrected to account for loss of methane to soil microbes. In the current study, we measured the methane loss to the atmosphere directly using a surface enclosure approach.
Why is WSU leading this project?
At WSU, we’ve developed various ways of taking atmospheric measurements, and our methods are directly applicable to the questions that were asked with this project. Additionally, WSU was asked to join the study team because of our involvement in the 1990s study of natural gas emissions across the U.S. In the 1990s study, the WSU research team was involved in helping to measure emissions from M&R stations. At that time, pipeline leaks were measured by individual companies using a standard method on pipeline sections scheduled for repair. The method involved digging down to a pipeline, isolating a leaking section, measuring the emissions, and then subtracting the methane emissions that would have been lost in the soil via soil oxidation.
How does WSU fit into the Environmental Defense Fund (EDF) project?
Our particular project is one of 16 projects that are sponsored by the EDF, in collaboration with a number of other universities as well as natural gas companies. In the overall picture for EDF, they are looking at each of the different sectors of the natural gas supply chain, starting with production from gas wells, moving to gas processing, then to the natural gas transmission system that spans the United States, and then finally to the natural gas distribution system in cities and towns where the gas is distributed to all of the customers. EDF is also investigating methane emissions from natural gas fueled vehicles and fueling stations. The focus of this study is a national view of the local distribution systems in cities and towns across the U.S. Another study partially funded by EDF was published earlier this year and estimated that methane leakage rates in Boston, which includes downstream components of the natural gas system, including transmission, distribution, and end use are 145% higher than data from the most closely comparable emission inventory for the Boston area.
Why do some studies show that local pipelines and infrastructure are emitting more methane than national estimates while your study is one that shows less?
The locations and methods involved in recent methane emission studies vary. Generally, one can classify most of the methods as either top-down or bottom-up approaches. Top-down methods measure methane concentrations in the air and try to determine how much methane must be emitted to produce this concentration.
These top-down studies are typically focused on a given area where the sources of methane can be quite varied. Some top-down studies have focused on gas and oil production basins, while others have been in large urban areas, such as Boston or Los Angeles. In urban areas, methane sources include the natural gas system, landfills, wastewater treatment plants, vehicles, and losses from furnaces, stoves, and other combustion sources.
Our method is a bottom-up approach that involves measuring emissions directly from the source and then combining these Emission Factors with the number of pipeline miles and metering stations to get an approximation of national emissions. Both methods are valid and provide valuable information, and both methods have drawbacks.
Top down emissions estimates do not use direct source measurements and typically result in larger emissions estimates than bottom-up approaches. Bottom-up approaches may not capture all emissions or appropriately account for “super-emitters.” Further study is needed to address sources that are not included in our direct source measurements and to reconcile the two methods.
Using both top-down and bottom-up approaches, work is currently underway with the Environmental Defense Fund, several universities, and industry participants on several methane emissions studies to try to get the most accurate picture as possible of nationwide emissions.
Since you worked with gas companies, could your measurements be biased in their favor?
- We worked with 13 local distribution companies who volunteered to participate in this study. While those companies represent less than one percent of 1400 such companies in the U.S., they hold 19% of the distribution pipeline mileage and deliver 16% of the gas to customers in the U.S. in 2011, so they do represent a significant portion of U.S. natural gas distribution activity.
- Our partner companies have pipeline replacement programs that are very similar to the national rates for pipeline replacement. For example, U.S. Department of Transportation data show that the miles of older pipeline types have been reduced by approximately 20% from 2005 through 2013 and our partner companies have essentially the same rate of replacement.
- For the study, our measurements were randomly and independently selected in a careful manner. Using leak survey data and facility lists provided by the companies, we used a random selection process, so that measurements were obtained within targeted, representative areas within each company’s distribution system.
- This study is the most comprehensive of any that has been done to date with the most number of direct measurements of local distribution emissions. We made a total of 230 measurements of underground pipeline leaks and 229 measurements at metering and regulating facilities, which is twice as many direct measurements as previous studies.
- As is often the case when these types of studies are done, our samples were asymmetric, so that a very few leaks accounted for a large fraction of our measured emissions. We therefore used eight different statistical models for each data set to come up with the most accurate estimate possible of the leak rate.
To assure objectivity, a Scientific Advisory Panel made up of independent academic experts reviewed our methods and findings and co-authored the paper. In addition, the paper went through the normal, anonymous peer review process that is typical of science journals such as Environmental Science & Technology. WSU had lead authorship and final authority on the paper.
How does this compare to the recent Boston Study, which was partially funded by EDF?
The Boston Urban Regional Study found that average loss rate of natural gas to the atmosphere from all users of the natural gas system, including transmission, distribution, and end use, was 2.7 ± 0.6% in the Boston urban region, which is notably higher than the 1.1% implied by existing emission inventories.
However, the Boston study measured all fugitive methane emissions in the region, including transmission pipelines, compression stations, storage facilities, and vehicles, as well as those associated with commercial, industrial, and home end-users which are not well understood, not just those from natural gas distribution pipelines.
This multi-city study just focused on distribution systems and did not look at midstream or end-user emissions or other sources of emissions which were captured in the Boston study.
Additionally, the national data from this study confirms there are regional differences across the country in local distribution systems, so it is not surprising to see some places with higher emissions than other places. For example, this study shows leaks from cast iron and unprotected steel pipe account for 70% of the eastern emissions and almost half of total U.S. emissions and the Boston area has a very high percentage of these pipes.