Re-evaluating Lifecycle Greenhouse Gas Emissions of Natural Gas Production

Natural gas is widely regarded as a transitional or bridge fuel: though still a fossil fuel, it is believed to have less global warming potential<!–[if supportFields]> XE “global warming potential (GWP)” <![endif]–><!–[if supportFields]><![endif]–> (GWP) than oil or coal<!–[if supportFields]> XE “coal” <![endif]–><!–[if supportFields]><![endif]–>. In this paper Howarth et al. (2011) re-examine that assumption by calculating fugitive methane<!–[if supportFields]> XE “methane (CH4)” <![endif]–><!–[if supportFields]><![endif]–> emissions from both conventional and unconventional gas resources, namely shale gas from high-volume hydraulic fracturing<!–[if supportFields]> XE “hydraulic fracturing” <![endif]–><!–[if supportFields]><![endif]–>. Shale gas production has boomed in recent years, exceeding conventional production in 2009, and is expected to constitute a large part of the gas used to transition from fossil fuels to renewable energy. However, few scientists have evaluated the greenhouse gas footprint of unconventional gas, and in light of recent findings that methane has an even greater GWP than previously believed, it is imperative to re-assess the GWP of natural gas production from conventional and unconventional sources. Howarth et al. calculated that 3.6­–7.9% of methane from shale gas production escapes through fugitive emissions and venting, a percentage 1.3–2.1 times higher than from conventional gas production. They found shale gas to have a larger GWP than oil and coal on a 20-year timescale, and to have a larger GWP than oil and comparable GWP to coal on a 100-year timescale.—Lucinda Block
Howarth, R. W., Santoro, R., Ingraffea, A., 2011. Methane and the greenhouse-gas footprint of natural gas from shale formations. Climate Change Letters, forthcoming.

          Howarth et al. used two recently available reports for their data, a 2010 Environmental Protection Agency (EPA) document on greenhouse gas emissions from the oil and gas industry and a 2010 Government Accountability Office report on natural gas losses on federal lands. The former document is the first update on oil and gas emissions factors since 1996, when the agency produced a report that served as the basis for the national greenhouse gas inventory for the past decade. Howarth et al. remark that the 1996 study was neither based on random sampling nor comprehensive; instead, data were collected from model facilities through voluntary reporting. The EPA acknowledge in their new report that emissions factors are much higher from some sources than originally thought, and that the first report was published at a time when methane<!–[if supportFields]> XE “methane (CH4)” <![endif]–><!–[if supportFields]><![endif]–> emissions were not a significant concern.
          Because recent studies suggest that methane<!–[if supportFields]> XE “methane (CH4)” <![endif]–><!–[if supportFields]><![endif]–> has a greater GWP<!–[if supportFields]> XE “global warming potential (GWP)” <![endif]–><!–[if supportFields]><![endif]–> than previously thought—having 33 times the GWP of CO2 when examined on a 100 year timescale, whereas previously thought to be 25 (IPCC<!–[if supportFields]> XE “Intergovernmental Panel on Climate Change (IPCC)” <![endif]–><!–[if supportFields]><![endif]–> 2007)—and because of the presumably low methane emissions factors used in recent years to calculate greenhouse gas inventories, Howarth et al. focus in this paper on calculating the fugitive methane emissions and emissions from venting throughout conventional and unconventional natural gas production.
          The main differences the authors find in methane<!–[if supportFields]> XE “methane (CH4)” <![endif]–><!–[if supportFields]><![endif]–> emissions between conventional and unconventional gas production occurs during well completion. The extraction of shale gas requires high-volume hydraulic fracturing<!–[if supportFields]> XE “hydraulic fracturing” <![endif]–><!–[if supportFields]><![endif]–>, a process in which large volumes of water are pumped into wells in order to fracture and re-fracture the otherwise impermeable shale and stimulate gas flow. Much of this water returns to the surface as “flow-back,” carrying with it large quantities of methane. Howarth et al. used fairly uncertain data to calculate the flow-back emissions of five different unconventional formations, with some of it coming from PowerPoint slides of EPA-sponsored workshops. They took the mean of methane losses from flow-back as a percentage of total lifetime production of the well, resulting in a figure of 1.6%.
To calculate the total percentage of gas loss from well completion the authors had to add to this number the methane<!–[if supportFields]> XE “methane (CH4)” <![endif]–><!–[if supportFields]><![endif]–> lost from “drill-out,” the stage of high-volume hydraulic fracturing<!–[if supportFields]> XE “hydraulic fracturing” <![endif]–><!–[if supportFields]><![endif]–> in which producers drill out the plugs used to separate fracturing stages. Because drill-out emissions were not available for individual formations, Howarth et al. used the mean of EPA drill-out emissions estimates (142,000 to 425,000 m3 of methane; mean=280,000 m3) multiplied by the average lifetime production of four of the rock formations used to determine flow-back emissions. Because of the higher lifetime production of these formations compared to others examined in a study of twelve formations, the calculation resulted in a conservative estimate for drill-out methane emissions as a percentage of gross well production of 0.33%. Combined with flow-back emissions, Howarth et al. calculate that 1.9% of gross shale gas production is emitted during well completion as an uncertain but highly conservative estimate. This figure contrasts with an emissions estimate of 0.01% of gross gas production for conventional wells using EPA data.
          Howarth et al. calculate a series of ranges for other potential sources of fugitive methane<!–[if supportFields]> XE “methane (CH4)” <![endif]–><!–[if supportFields]><![endif]–> emissions in conventional and shale gas production. The authors attribute the same methane loss ranges to both conventional and unconventional gas production for equipment leaks and routine venting, since the same technologies are used for both types of gas once they are connected to a pipeline. The low end of 0.3% represents the use of best available technology, and the upper estimate of 1.9% does not include accidents or emergency venting.
Fugitive emissions from transport, storage, and distribution of natural gas can also be assumed to be the same for both types of gas production, as conventional and shale gas are an identical commodity at this point of production. The authors employed the figure of 1.4%, calculated in a 2005 study by Lelieveld et al. as the lower estimate of average gas loss combining transport, storage, and distribution losses. They found the estimate’s upper limit using a bottom-down approach, calculating the disparity between measured gas produced at the wellhead and measured volume of gas purchased and consumed as an end product. The authors calculated an upper limit of 3.6% by taking the mean of the State of Texas’s data for missing and unaccounted gas in the years 2000 and 2007. Howarth et al. believe 3.6% to still be a conservative estimate, given that industry fought a proposed hard cap on missing and unaccounted gas of 5% in the state.
The authors also provided a range of methane<!–[if supportFields]> XE “methane (CH4)” <![endif]–><!–[if supportFields]><![endif]–> losses for “liquid unloading” and gas processing. Liquid unloading is a process often needed for conventional well production and sometimes for unconventional well production, in which liquid is unloaded to mitigate water intrusion as reservoir pressure drops when a well matures. Though methane losses from liquid unloading were estimated at 0.02–0.26% of gross production, because some wells do not require liquid unloading, the authors used the range of 0–0.26%. Surprisingly, they used the same range for both conventional and shale gas, despite acknowledging that liquid unloading is primarily required for conventional wells. Logically, conventional gas should have been given a higher estimate for liquid unloading than shale gas, but the authors do not address this.
Similarly, the authors provided the same range for both conventional and shale gas for emissions from gas processing. Howarth et al. explain that both conventional and shale gas vary in quality when extracted, and thus sometimes require processing that creates more methane<!–[if supportFields]> XE “methane (CH4)” <![endif]–><!–[if supportFields]><![endif]–> emissions. However, they do not address the question of whether one type of gas or the other has a higher average quality when extracted. Instead, the authors provided a methane loss range of 0%, representing no processing, to 0.19% of production for both types of gas. This area of uncertainty goes unaddressed in the study.
Howarth et al. calculated the total fugitive methane<!–[if supportFields]> XE “methane (CH4)” <![endif]–><!–[if supportFields]><![endif]–> loss as a percentage of gross production at 1.7–6.0% for conventional gas, and 3.6–7.9% for shale gas. Compared to coal<!–[if supportFields]> XE “coal” <![endif]–><!–[if supportFields]><![endif]–> (both surface- and deep-mined) and diesel oil on a 20- and 100-year timescale, the authors found the GWP<!–[if supportFields]> XE “global warming potential (GWP)” <![endif]–><!–[if supportFields]><![endif]–> of shale gas to be 1.2–2.1 times greater than coal and 1.5–2.5 times greater than oil on a 20-year timescale. On a 100-year timescale, they found the GWP of shale gas to be comparable to coal and up to 1.4 times greater than oil. The high estimate GWP of conventional gas was also significantly higher than oil and coal on a 20-year timescale and comparable on a 100-year timescale.
Comparing their estimates for conventional gas fugitive methane<!–[if supportFields]> XE “methane (CH4)” <![endif]–><!–[if supportFields]><![endif]–> emissions to other peer-reviewed literature, the authors note that although two of three studies found lower estimates for fugitive emissions, these studies used GWP<!–[if supportFields]> XE “global warming potential (GWP)” <![endif]–><!–[if supportFields]><![endif]–> factors for methane that are now known to be too low and still concluded that in many cases a switch to natural gas from coal<!–[if supportFields]> XE “coal” <![endif]–><!–[if supportFields]><![endif]–> could aggravate rather than mitigate the effects of climate change. Lelieveld et al. concluded that natural gas would be worse than oil if fugitive methane emissions exceeded 3.1% of total production, and worse than coal if they exceeded 5.6%. Adjusting that study’s GWP factor for methane to account for recent findings, Howarth et al. claim that fugitive methane emissions of only 2–3% make natural gas more impactful than oil and coal, well within both their emissions ranges for conventional and shale gas.

          In conclusion, the authors emphasize that rather than promoting continued use of oil and coal<!–[if supportFields]> XE “coal” <![endif]–><!–[if supportFields]><![endif]–>, they warn against policymaking that relies on natural gas as a bridge fuel and assumes that gas implies lower carbon emissions per unit of energy produced compared to other fuels. However, they acknowledge that there is a large amount of uncertainty in fugitive methane<!–[if supportFields]> XE “methane (CH4)” <![endif]–><!–[if supportFields]><![endif]–> estimates and recommend further study, given the importance of the topic.

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