Repository for Oil and Gas Energy Research (ROGER)

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Environmental and economic impacts of methane escaping from the natural gas supply chain remain uncertain. Flowback emissions from hydraulically fractured natural gas wells are a key component of emissions from unconventional gas wells. While reduced emission completions in the United States are required by regulation, Canada’s proposed regulation will only be implemented in 2020 with the two highest producing provinces under exemption. To understand potential benefits of regulations, we use predictive modelling of well-level production data of 1633 hydraulically fractured shale gas wells in five plays to estimate pre-production emissions. The mean estimate for flowback emissions (2,346±95% confidence interval of 91 Mg CO2e/completion) fall within the 95% confidence limits of measured potential emissions (2,566±777 Mg CO2e/completion). Our results indicate that in 2015, the average emissions per shale gas well undergoing flowback was 2,347 Mg CO2e/completion in the U.S. and 1,859 Mg CO2e/completion in Canada. Mean potential profits from controlling methane emissions using reduced emission completions were US$17,200/well in the U.S. and US$11,200/well in Canada.

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The proliferation of unconventional natural gas drilling has brought considerable recent attention to the possible impacts that this new technology may have on greenhouse gas emissions. In Pennsylvania, estimates of these possible impacts are very difficult to accurately assess in large part due to the highly uncertain contribution from legacy abandoned and orphaned gas (AOG) wells. This paper outlines our work in establishing a methodology for measuring the methane leak rate from AOG wells in Western Pennsylvania. The theory and methodology of an enclosure method for measuring the methane mass leak rate from one AOG natural gas well is described. Summary data for four other measurements and three other wells is presented. The goal of this work is to take the first steps towards an accurate determination of the contribution of AOWs to anthropogenic methane emissions in Pennsylvania.

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Shale gas production is a water and energy-intensive process that has expanded rapidly in the United States in recent years. This study compared the life cycle water consumption and greenhouse gas emissions from hydraulic fracturing in the Barnett region of Texas, located in one of the most drought prone regions of the United States. Four wastewater treatment scenarios were compared for produced water management in the Barnett region. For each scenario, the cradle-to-gate life cycle global warming potential and water scarcity footprint was estimated per mega joule of gas produced. The results show a trade-off between water and carbon impacts, because energy is required for treatment of water. A reduction of 49 percent in total water consumed or a 28 percent reduction in the water scarcity footprint in the shale gas production process can be achieved at a cost of a 38 percent increase in global warming potential, if the wastewater management shifted from business as usual to complete desalination and reuse of produced water. The results are discussed in the context of wastewater management options available in Texas.

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We collected data focusing on in-use emissions and efficiency of engines servicing the unconventional well development industry to elucidate real world impacts from current and newly applied engine technologies. The engines examined during the campaigns were diesel only (DO) and dual fuel (DF) diesel/natural gas, compression-ignition (CI) engines and dedicated natural gas, spark-ignition (SI) engines. These included two CI drilling engines outfitted with two different DF kits, two SI drilling engines, and two CI well stimulation engines. Our data were gathered under the load and speed requirements in the field, and the engines were not under our direct control. Greenhouse gas (GHG) emissions were measured from all engines and fueling types and included both exhaust and crankcase emissions. Fuel consumption and engine data were collected to determine fuel efficiency. During steady-state operation, fuel efficiency was 38%, 26%, and 20% for DO, DF, and SI engines, respectively. The loss of efficiency during DF operation was due in part to uncombusted methane (CH4) slip in the exhaust, which accounted for 18% of the fuel supplied. GHG emissions (carbon dioxide and CH4) from CI engines were 2.25 times higher during DF compared to DO operation. During DF operation, substitution ratio varied depending on engine load and DF kit, ranging from 9% to 74%. GHG emissions from the SI engines were 1.33 times higher than DO due to lower efficiencies of throttled and rich operation as compared to unthrottled and lean operation for CI engines.

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North American leaders recently committed to reducing methane emissions from the oil and gas sector, but information on current emissions from upstream oil and gas developments in Canada are lacking. This study examined the occurrence of methane plumes in an area of unconventional natural gas development in northwestern Canada. In August to September 2015 we completed almost 8000 km of vehicle-based survey campaigns on public roads dissecting oil and gas infrastructure, such as well pads and processing facilities. We surveyed six routes 3-6 times each, which brought us past over 1600 unique well pads and facilities managed by more than 50 different operators. To attribute on-oad plumes to oil-and gas-related sources we used gas signatures of residual excess concentrations (anomalies above background) less than 500m downwind from potential oil and gas emission sources. All results represent emissions greater than our minimum detection limit of 0.59 g s(-1) at our average detection distance (319 m). Unlike many other oil and gas developments in the US for which methane measurements have been reported recently, the methane concentrations we measured were close to normal atmospheric levels, except inside natural gas plumes. Roughly 47% of active wells emitted methane-rich plumes above our minimum detection limit. Multiple sites that pre-date the recent unconventional natural gas development were found to be emitting, and we observed that the majority of these older wells were associated with emissions on all survey repeats. We also observed emissions from gas processing facilities that were highly repeatable. Emission patterns in this area were best explained by infrastructure age and type. Extrapolating our results across all oil and gas infrastructure in the Montney area, we estimate that the emission sources we located (emitting at a rate >0.59 g s(-1)) contribute more than 111 800 t of methane annually to the atmosphere. This value exceeds reported bottom-up estimates of 78 000 t of methane for all oil and gas sector sources in British Columbia. Current bottom-up methods for estimating methane emissions do not normally calculate the fraction of emitting oil and gas infrastructure with thorough on-ground measurements. However, this study demonstrates that mobile surveys could provide a more accurate representation of the number of emission sources in an oil and gas development. This study presents the first mobile collection of methane emissions from oil and gas infrastructure in British Columbia, and these results can be used to inform policy development in an era of methane emission reduction efforts.

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The Eagle Ford Shale in southern Texas is home to a booming unconventional oil and gas industry, the climate and air quality impacts of which remain poorly quantified due to uncertain emission estimates. We used the atmospheric enhancement of alkanes from Texas Commission on Environmental Quality volatile organic compound monitors across the shale, in combination with back trajectory and dispersion modeling, to quantify C-2-C-4 alkane emissions for a region in southern Texas, including the core of the Eagle Ford, for a set of 68 days from July 2013 to December 2015. Emissions were partitioned into raw natural gas and liquid storage tank sources using gas and headspace composition data, respectively, and observed enhancement ratios. We also estimate methane emissions based on typical ethane-to-methane ratios in gaseous emissions. The median emission rate from raw natural gas sources in the shale, calculated as a percentage of the total produced natural gas in the upwind region, was 0.7% with an interquartile range (IQR) of 0.5-1.3 %, below the US Environmental Protection Agency's (EPA) current estimates. However, storage tanks contributed 17% of methane emissions, 55% of ethane, 82% percent of propane, 90% of n-butane, and 83% of isobutane emissions. The inclusion of liquid storage tank emissions results in a median emission rate of 1.0% (IQR of 0.7-1.6 %) relative to produced natural gas, overlapping the current EPA estimate of roughly 1.6 %. We conclude that emissions from liquid storage tanks are likely a major source for the observed non-methane hydrocarbon enhancements in the Northern Hemisphere.

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Methane emissions from oil and gas facilities can exhibit operation-dependent temporal variability; however, this variability has yet to be fully characterized. A field campaign was conducted in June 2014 in the Eagle Ford basin, Texas, to examine spatiotemporal variability of methane emissions using four methods. Clusters of methane-emitting sources were estimated from 14 aerial surveys of two (“East” or “West”) 35 × 35 km grids, two aircraft-based mass balance methods measured emissions repeatedly at five gathering facilities and three flares, and emitting equipment source-types were identified via helicopter-based infrared camera at 13 production and gathering facilities. Significant daily variability was observed in the location, number (East: 44 ± 20% relative standard deviation (RSD), N = 7; West: 37 ± 30% RSD, N = 7), and emission rates (36% of repeat measurements deviate from mean emissions by at least ±50%) of clusters of emitting sources. Emission rates of high emitters varied from 150–250 to 880–1470 kg/h and regional aggregate emissions of large sources (>15 kg/h) varied up to a factor of ∼3 between surveys. The aircraft-based mass balance results revealed comparable variability. Equipment source-type changed between surveys and alterations in operational-mode significantly influenced emissions. Results indicate that understanding temporal emission variability will promote improved mitigation strategies and additional analysis is needed to fully characterize its causes.

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Leakage of natural gas (mainly methane) along oil and gas wells contributes to fugitive greenhouse gas emissions. Natural gas leakage occurring outside the well casing and cement sheath and reaching the surface, hence the atmosphere, is known as Gas Migration (GM). In this paper an analysis of the occurrence of gas (methane) migration along wellbores in Alberta, Canada, is presented based on data obtained from the Alberta Energy Regulator. Gas migration (GM) has been reported in 3276 wells, i.e., in 0.73% of all the wells in the province. Most of these wells (2745) are located in the eastern, shallower part of the province, particularly in the Lloydminster – Cold Lake area. The wells are mostly shallow, with 2800 wells being shallower than 1000 m depth. About half of the wells are cemented to the top, showing that lack of cementing to the top or at least above the surface casing shoe is not a major factor in the occurrence of GM. Similarly, well orientation is not a strong indicator of GM potential or occurrence A slight majority (54.1%) of the wells with GM are conventional wells, with the balance (45.9%) being thermal wells, of which the great majority is in the Cold Lake oil sands area where cyclic steam injection is used for bitumen production. The analysis indicates that the production type, conventional for oil and gas, or thermal for heavy oil and bitumen, is a strong indicator of the potential for, or occurrence for GM. The depth of the gas source is provided in the database for 559 wells. When related to the well depth, the relative depth of the gas source has an average of 0.42, indicating that the origin of the gas source is, by and large, above the producing reservoirs. Isotopic studies of reservoir and migrating gas in Alberta, reviewed in this paper, indicate that in the great majority of cases the migrating gas is immature thermogenic gas originating in overlying shales, as well as coal gas originating from the various overlying coal beds. In a number of cases the migrating gas is of shallow, biogenic origin, likely sourced from shallow groundwater aquifers. Biogenic methanogenesis is enhanced by the high temperatures associated with thermal wells, which may explain the large number of GM cases associated with thermal wells.

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Natural gas production in the U.S. has increased rapidly over the past decade, along with concerns about methane (CH4) leakage (total fugitive emissions), and climate impacts. Quantification of CH4 emissions from oil and natural gas (O&NG) operations is important for establishing scientifically sound, cost-effective policies for mitigating greenhouse gases. We use aircraft measurements and a mass balance approach for three flight experiments in August and September 2015 to estimate CH4 emissions from O&NG operations in the southwestern Marcellus Shale region. We estimate the mean1 sigma CH4 emission rate as 36.71.9kgCH(4)s(-1) (or 1.160.06TgCH(4)yr(-1)) with 59% coming from O&NG operations. We estimate the mean1 sigma CH4 leak rate from O&NG operations as 3.9 +/- 0.4% with a lower limit of 1.5% and an upper limit of 6.3%. This leak rate is broadly consistent with the results from several recent top-down studies but higher than the results from a few other observational studies as well as in the U.S. Environmental Protection Agency CH4 emission inventory. However, a substantial source of CH4 was found to contain little ethane (C2H6), possibly due to coalbed CH4 emitted either directly from coalmines or from wells drilled through coalbed layers. Although recent regulations requiring capture of gas from the completion venting step of the hydraulic fracturing appear to have reduced losses, our study suggests that for a 20year time scale, energy derived from the combustion of natural gas extracted from this region will require further controls before it can exert a net climate benefit compared to coal.

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Methane (CH4) is a potent greenhouse gas and the primary component of natural gas. The San Juan Basin (SJB) is one of the largest coal-bed methane producing regions in North America and, including gas production from conventional and shale sources, contributes ~2% of U.S. natural gas production in 2015. In this work, we quantify the CH4 flux from the SJB using continuous atmospheric sampling from aircraft collected during the TOPDOWN2015 field campaign in April 2015. Using five independent days of measurements and the aircraft-based mass balance method, we calculate an average CH4 flux of 0.54 ± 0.20 Tg yr-1 (1σ), in close agreement with the previous space-based estimate made for 2003-2009. These results agree within error with the US EPA gridded inventory for 2012. These flights combined with the previous satellite study suggests CH4 emissions have not changed. While there have been significant declines in natural gas production between measurements, recent increases in oil production in the SJB may explain why emission of CH4 has not declined. Airborne quantification of outcrops where seepage occurs are consistent with ground-based studies that indicate these geological sources are a small fraction of the basin total (0.02-0.12 Tg yr-1) and cannot explain basin-wide consistent emissions from 2003-2015.

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Incomplete combustion during flaring can lead to production of black carbon (BC) and loss of methane and other pollutants to the atmosphere, impacting climate and air quality. However, few studies have measured flare efficiency in a real-world setting. We use airborne data of plume samples from 37 unique flares in the Bakken region of North Dakota in May 2014 to calculate emission factors for BC, methane, ethane, and combustion efficiency for methane and ethane. We find no clear relationship between emission factors and aircraft-level wind speed, nor between methane and BC emission factors. Observed median combustion efficiencies for methane and ethane are close to expected values for typical flares according to the US EPA (98%). However, we find that the efficiency distribution is skewed, exhibiting lognormal behavior. This suggests incomplete combustion from flares contributes almost 1/5 of the total field emissions of methane and ethane measured in the Bakken shale, more than double the expected value if 98\% efficiency was representative. BC emission factors also have a skewed distribution, but we find lower emission values than previous studies. The direct observation for the first time of a heavy-tail emissions distribution from flares suggests the need to consider skewed distributions when assessing flare impacts globally.

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This study develops a multi-level programming model from a life cycle perspective for performing shale-gas supply chain system. A set of leader-follower-interactive objectives with emphases of environmental, economic and energy concerns are incorporated into the synergistic optimization process, named MGU-MEM-MWL model. The upper-level model quantitatively investigates the life-cycle greenhouse gas (GHG) emissions as controlled by the environmental sector. The middle-level one focuses exclusively on system benefits as determined by the energy sector. The lower-level one aims to recycle water to minimize the life-cycle water supply as required by the enterprises. The capabilities and effectiveness of the developed model are illustrated through real-world case studies of the Barnett, Marcellus, Fayetteville, and Haynesville Shales in the US. An improved multi-level interactive solution algorithm based on satisfactory degree is then presented to improve computational efficiency. Results indicate that: (a) the end-use phase (i.e., gas utilization for electricity generation) would not only dominate the life-cycle GHG emissions, but also account for 76.1% of the life-cycle system profits; (b) operations associated with well hydraulic fracturing would be the largest contributor to the life-cycle freshwater consumption when gas use is not considered, and a majority of freshwater withdrawal would be supplied by surface water; (c) nearly 95% of flowback water would be recycled for hydraulic fracturing activities and only about 5% of flowback water would be treated via CWT facilities in the Marcellus, while most of the wastewater generated from the drilling, fracturing and production operations would be treated via underground injection control wells in the other shale plays. Moreover, the performance of the MGU-MEM-MWL model is enhanced by comparing with the three bi-level programs and the multi-objective approach. Results demonstrate that the MGU-MEM-MWL decisions would provide much comprehensive and systematic policies when considering the hierarchical structure within the shale-gas system.

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This paper assesses tradeoffs between system-wide and superemitter policy options for reducing methane emissions from compressor stations in the U.S. transmission and storage system. Leveraging recently collected national emissions and activity datasets, we developed a new processed-based emissions model implemented in a Monte Carlo simulation framework to estimate emissions for each component and facility in the system. We find that approximately 83% of emissions, given the existing suite of technologies, have the potential to be abated, with only a few emission categories comprising a majority of emissions. We then formulate optimization models to determine optimal abatement strategies. Most emissions across the system (approximately 80%) are efficient to abate, resulting in net benefits ranging from $160M to $1.2B annually across the system. The private cost burden is minimal under standard and tax instruments, and if firms market the abated natural gas, private net benefits may be generated. Superemitter policies, namely those that target the highest emitting facilities, may reduce the private cost burden and achieve high emission reductions, especially if emissions across facilities are highly skewed. However, detection across all facilities is necessary regardless of the policy option and there are nontrivial net benefits resulting from abatement of relatively low-emitting sources.

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Article: Analysis of local-scale background concentrations of methane and other gas-phase species in the Marcellus Shale

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To increase energy security and reduce emissions of air pollutants and CO2 from coal use, China is attempting to duplicate the rapid development of shale gas that has taken place in the United States. This work builds a framework to estimate the lifecycle greenhouse gas (GHG) emissions from China’s shale gas system and compares them with GHG emissions from coal used in the power, residential, and industrial sectors. We find the mean lifecycle carbon footprint of shale gas is about 30%-50% lower than that of coal in all sectors under both 20-year and 100-year Global Warming Potentials (GWP20 and GWP100). However, primarily due to large uncertainties in methane leakage, the upper bound estimate of the lifecycle carbon footprint of shale gas in China could be approximately 15%-60% higher than that of coal across sectors under GWP20. To ensure net GHG emission reductions when switching from coal to shale gas, we estimate the breakeven methane leakage rates to be approximately 6.0%, 7.7%, and 4.2% in the power, residential, and industrial sectors, respectively, under GWP20. We find shale gas in China has a good chance of delivering air quality and climate co-benefits, particularly when used in the residential sector, with proper methane leakage control.

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There exists considerable uncertainty over both shale and conventional gas resource availability and extraction costs, as well as the fugitive methane emissions associated with shale gas extraction and its possible role in mitigating climate change. This study uses a multi-region energy system model, TIAM (TIMES integrated assessment model), to consider the impact of a range of conventional and shale gas cost and availability assessments on mitigation scenarios aimed at achieving a limit to global warming of below 2 °C in 2100, with a 50% likelihood. When adding shale gas to the global energy mix, the reduction to the global energy system cost is relatively small (up to 0.4%), and the mitigation cost increases by 1%–3% under all cost assumptions. The impact of a “dash for shale gas”, of unavailability of carbon capture and storage, of increased barriers to investment in low carbon technologies, and of higher than expected leakage rates, are also considered; and are each found to have the potential to increase the cost and reduce feasibility of meeting global temperature goals. We conclude that the extraction of shale gas is not likely to significantly reduce the effort required to mitigate climate change under globally coordinated action, but could increase required mitigation effort if not handled sufficiently carefully.

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A large proportion of methane emissions from natural gas production sites are released by a fraction of high-emitting sources. Here, using Monte Carlo simulations, the authors reveal that super-emitters occur due to abnormal process conditions, explaining component and site-based inventory discrepancies.

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Concerns over mitigating methane leakage from the natural gas system have become ever more prominent in recent years. Recently, the U.S. Environmental Protection Agency proposed regulations requiring use of optical gas imaging (OGI) technologies to identify and repair leaks. In this work, we develop an open-source predictive model to accurately simulate the most common OGI technology, passive infrared (IR) imaging. The model accurately reproduces IR images of controlled methane release field experiments as well as reported minimum detection limits. We show that imaging distance is the most important parameter affecting IR detection effectiveness. In a simulated well-site, over 80% of emissions can be detected from an imaging distance of 10 m. Also, the presence of “superemitters” greatly enhance the effectiveness of IR leak detection. The minimum detectable limits of this technology can be used to selectively target “superemitters”, thereby providing a method for approximate leak-rate quantification. In addition, model results show that imaging backdrop controls IR imaging effectiveness: land-based detection against sky or low-emissivity backgrounds have higher detection efficiency compared to aerial measurements. Finally, we show that minimum IR detection thresholds can be significantly lower for gas compositions that include a significant fraction nonmethane hydrocarbons.

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Natural gas is typically considered to be the cleaner-burning fossil fuel that could play an important role within a restricted carbon budget. While natural gas emits less CO2 when burned than other fossil fuels, its main constituent is methane, which has a much stronger climate forcing impact than CO2 in the short term. Estimates of methane emissions in the natural gas supply chain have been the subject of much controversy, due to uncertainties associated with estimation methods, data quality, and assumptions used. This Perspective presents a comprehensive compilation of estimated CO2 and methane emissions across the global natural gas supply chain, with the aim of providing a balanced insight for academia, industry, and policy makers by summarizing the reported data, locating the areas of major uncertainty, and identifying where further work is needed to reduce or remove this uncertainty. Overall, the range of documented estimates of methane emissions across the supply chain is vast among an aggregation of different geological formations, technologies, plant age, gas composition, and regional regulation, not to mention differences in estimation methods. Estimates of combined methane and CO2 emissions ranged from 2 to 42 g CO2 eq/MJ HHV, while methane-only emissions ranged from 0.2% to 10% of produced methane. The methane emissions at the extraction stage are the most contentious issue, with limited data available but potentially large impacts associated with well completions for unconventional gas, liquids unloading, and also the transmission stage. From the range of literature estimates, a constrained range of emissions was estimated that reflects the most recent and reliable estimates: total supply chain GHG emissions were estimated to be between 3.6 and 42.4 g CO2 eq/MJ HHV, with a central estimate of 10.5. The presence of “super emitters”, a small number of facilities or equipment that cause extremely high emissions, is found across all supply chain stages creating a highly skewed emissions distribution. However, various new technologies, mitigation and maintenance approaches, and legislation are driving significant reductions in methane leakage across the natural gas supply chain.

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Natural gas used for power generation will be increasingly sourced from more geographically diverse sites, and unconventional sources such as shale and biomethane, as natural gas reserves diminish. A consequential life cycle approach was employed to examine the implications of an evolving gas supply on the greenhouse gas (GHG) performance of a future United Kingdom (UK) electricity system. Three gas supply mixes were developed based on supply trends, from present day to the year 2050. The contribution of upstream gas emissions - such as extraction, processing/refining, - is not fully reported or covered by UK government legislation. However, upstream gas emissions were seen to be very influential on the future electricity systems analysed; with upstream gas emissions per MJ rising between 2.7 and 3.4 times those of the current supply. Increased biomethane in the gas supply led to a substantial reduction in direct fossil emissions, which was found to be critical in offsetting rising upstream emissions. Accordingly, the modelled high shale gas scenario, with the lowest biomethane adoption; resulted in the highest GHG emissions on a life cycle basis. The long-term dynamics of upstream processes are explored in this work to help guide future decarbonisation policies.

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Western Australia has globally significant onshore gas resources, with over 280 trillion cubic feet of economically recoverable gas located in five shale basins. The Western Australian Government and gas industry have promoted the development of these resources as a “clean energy source” that would “help to reduce global carbon emissions” and provide a “transition fuel” to a low carbon economy. This research examines those claims by reviewing existing literature and published data to estimate the life cycle greenhouse gas (GHG) pollution that would result from the development of Western Australia’s onshore gas basins using hydraulic fracking. Estimates of carbon pollution from each stage in gas development, processing, transport and end-use are considered in order to establish total life-cycle emissions in tonnes of carbon-dioxide equivalent (CO_{2e). The emissions estimates draw from published research on emissions from shale gas development in other jurisdictions as well as industry or government reported emissions from current technology for gas processing and end-use as applicable. The current policy and regulatory environment for carbon pollution and likely resulting GHG mitigation measures has also been considered, as well as the potential for the gas to displace or substitute for other energy sources. In areas where there is uncertainty, conservative emissions estimates have been used. Modelling of GHG emissions has been undertaken for two comparison resource development and utilisation scenarios; Australian domestic and 100% export i.e. no domestic use. Each scenario corresponds to a different proportionate allocation of emissions accounted for domestic emissions in Australia and emissions accounted for in other jurisdictions. Emissions estimates for the two scenarios are 245–502 MTCO2e/year respectively over a resource development timeframe of 20 years. This is roughly the same as Australia’s total GHG emissions in 2014 which were 525 MTCO2e/year. This research concludes that GHG emissions resulting from the development of Western Australia’s five onshore gas basins would be equivalent to all other Australian emissions sources combined at 2014 levels each year for 20 years which is the general lifetime of a well.}

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The process of hydraulic fracturing for recovery of oil and natural gas uses large amounts of fresh water and produces a comparable amount of wastewater, much of which is typically transported by truck. Truck transport of water is an expensive and energy-intensive process with significant external costs including roads damages, and pollution. The integrated development plan (IDP) is the industry nomenclature for an integrated oil and gas infrastructure system incorporating pipeline-based transport of water and wastewater, centralized water treatment, and high rates of wastewater recycling. These IDP have been proposed as an alternative to truck transport systems so as to mitigate many of the economic and environmental problems associated with natural gas production, but the economic and environmental performance of these systems have not been analyzed to date. This study presents a quantification of lifecycle greenhouse gas (GHG) emissions and road damages of a generic oil and gas field, and of an oil and gas development sited in the Denver-Julesburg basin in the northern Colorado region of the US. Results demonstrate that a reduction in economic and environmental externalities can be derived from the development of these IDP-based pipeline water transportation systems. IDPs have marginal utility in reducing GHG emissions and road damage when they are used to replace in-field water transport, but can reduce GHG emissions and road damage by factors of as much as 6 and 7 respectively, when used to replace fresh water transport and waste-disposal routes for exemplar Northern Colorado oil and gas fields.

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Methane—a short-lived and potent greenhouse gas—presents a unique challenge: it is emitted from a large number of highly distributed and diffuse sources. In this regard, the United States’ Environmental Protection Agency (EPA) has recommended periodic leak detection and repair surveys at oil and gas facilities using optical gas imaging technology. This regulation requires an operator to fix all detected leaks within a set time period. Whether such ‘find-all-fix-all’ policies are effective depends on significant uncertainties in the character of emissions. In this work, we systematically analyze the effect of facility-related and mitigation-related uncertainties on regulation effectiveness. Drawing from multiple publicly-available datasets, we find that: (1) highly-skewed leak-size distributions strongly influence emissions reduction potential; (2) variations in emissions estimates across facilities leads to large variability in mitigation effectiveness; (3) emissions reductions from optical gas imaging-based leak detection programs can range from 15% to over 70%; and (4) while implementation costs are uniformly lower than EPA estimates, benefits from saved gas are highly variable. Combining empirical evidence with model results, we propose four policy options for effective methane mitigation: performance-oriented targets for accelerated emission reductions, flexible policy mechanisms to account for regional variation, technology-agnostic regulations to encourage adoption of the most cost-effective measures, and coordination with other greenhouse gas mitigation policies to reduce unintended spillover effects.

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A synthesis of new methane (CH4) emission data from a recent series of ground-based field measurements shows that 1.7% of the methane in natural gas is emitted between extraction and delivery (with a 95% confidence interval from 1.3% to 2.2%). This synthesis was made possible by a recent series of methane emission measurement campaigns that focused on the natural gas supply chain, production through distribution. The new data were translated to a standard basis, augmented with other data sources as needed, and simulated using a Monte Carlo-enabled, life cycle model. Gathering facilities and production pneumatics are the top methane emission reduction opportunities for the natural gas sector, but there are knowledge gaps and sources of uncertainty that merit further research. In particular, “unassigned” emissions that were measured at the site level, as opposed to component-level emissions measured directly at the device level, account for 19% of supply chain methane emissions. By definition, unassigned emissions cannot be attributed to specific emission sources, and the current data do not provide insight into how they vary geographically. The inclusion of unassigned emissions makes the bottom-up compilation of emission sources more complete, but is a source of uncertainty that points to opportunities for further research. Further research should include geographically diverse measurement studies that provide a better understanding of regional variability and validate emission measurements by using a combination of component- and site-level measurements.

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The extraction of unconventional oil and natural gas from shale energy reservoirs has raised concerns regarding upstream and midstream activities and their potential impacts on air quality. Here we present in situ measurements of ambient methane concentrations near multiple natural gas compressor stations in New York and Pennsylvania using cavity ring-down laser spectrometry coupled with global positioning system technology. These data reveal discernible methane plumes located proximally to compressor stations, which exhibit high variability in their methane emissions depending on the weather conditions and on-site activities. During atmospheric temperature inversions, when near-ground mixing of the atmosphere is limited or does not occur, residents and properties located within 1 mile of a compressor station can be exposed to rogue methane from these point sources. These data provide important insight into the characterization and potential for optimization of natural gas compressor station operations.

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We present a gridded inventory of US anthropogenic methane emissions with 0.1° × 0.1° spatial resolution, monthly temporal resolution, and detailed scale-dependent error characterization. The inventory is designed to be consistent with the 2016 US Environmental Protection Agency (EPA) Inventory of US Greenhouse Gas Emissions and Sinks (GHGI) for 2012. The EPA inventory is available only as national totals for different source types. We use a wide range of databases at the state, county, local, and point source level to disaggregate the inventory and allocate the spatial and temporal distribution of emissions for individual source types. Results show large differences with the EDGAR v4.2 global gridded inventory commonly used as a priori estimate in inversions of atmospheric methane observations. We derive grid-dependent error statistics for individual source types from comparison with the Environmental Defense Fund (EDF) regional inventory for Northeast Texas. These error statistics are independently verified by comparison with the California Greenhouse Gas Emissions Measurement (CALGEM) grid-resolved emission inventory. Our gridded, time-resolved inventory provides an improved basis for inversion of atmospheric methane observations to estimate US methane emissions and interpret the results in terms of the underlying processes.

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This study considered whether faults bounding hydrocarbon-bearing basins could be conduits for methane release to the atmosphere. Five basin bounding faults in the UK were considered: two which bounded potential shale gas basins; two faults that bounded coal basins; and one that bounded a basin with no known hydrocarbon deposits. In each basin, two mobile methane surveys were conducted, one along the surface expression of the basin bounding fault and one along a line of similar length but not intersecting the fault. All survey data was corrected for wind direction, the ambient CH4 concentration and the distance to the possible source. The survey design allowed for Analysis of Variance and this showed that there was a significant difference between the fault and control survey lines though a significant flux from the fault was not found in all basins and there was no apparent link to the presence, or absence, of hydrocarbons. As such, shale basins did not have a significantly different CH4 flux to non-shale hydrocarbon basins and non-hydrocarbon basins. These results could have implications for CH4 emissions from faults both in the UK and globally. Including all the corrected fault data, we estimate faults have an emissions factor of 11.5 ± 6.3 t CH4/km/yr, while the most conservative estimate of the flux from faults is 0.7 ± 0.3 t CH4/km/yr. The use of isotopes meant that at least one site of thermogenic flux from a fault could be identified. However, the total length of faults that penetrate through-basins and go from the surface to hydrocarbon reservoirs at depth in the UK is not known; as such, the emissions factor could not be multiplied by an activity level to estimate a total UK CH4 flux.

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There is consensus on the importance of upstream methane (CH4) emissions to the life cycle greenhouse gas (GHG) footprint of natural gas systems, but inconsistencies among recent studies explain why some researchers calculate a CH4 emission rate of less than 1% whereas others calculate a CH4 emission rate as high as 10%. These inconsistencies arise from differences in data collection methods, data collection time frames, and system boundaries. This analysis focuses on system boundary inconsistencies. Our results show that the calculated CH4 emission rate can increase nearly fourfold not by changing the magnitude of any particular emission source, but by merely changing the portions of the supply chain that are included within the system boundary. Our calculated CH4 emission rate for extraction through pipeline transmission is 1.2% for current practices. Our model allows us to identify GHG contributors in the upstream supply chain, but also allows us to tie upstream findings to complete life cycle scenarios. If applied to the life cycles of power systems and assessed in terms of cumulative radiative forcing, the upstream CH4 emission rate can be as high as 3.2% before the GHG impacts from natural gas power exceed those from coal power at any point during a 100-year time frame.

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Global atmospheric concentrations of methane (CH4), a powerful greenhouse gas, are increasing, but because there are many natural and anthropogenic sources of CH4, it is difficult to assess which sources may be increasing in magnitude. Here we present a dataset of δ2H-CH4 measurements of individual sources and air in the Colorado Front Range, USA. We show that δ2H-CH4, but not δ13C, signatures are consistent in air sampled downwind of landfills, cattle feedlots, and oil and gas wells in the region. Applying these source signatures to air in ground and aircraft samples indicates that at least 50% of CH4 emitted in the region is biogenic, perhaps because regulatory restrictions on leaking oil and natural gas wells are helping to reduce this source of CH4. Source apportionment tracers such as δ2H may help close the gap between CH4 observations and inventories, which may underestimate biogenic as well as thermogenic sources.

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Future energy systems may rely on natural gas as a low-cost fuel to support variable renewable power. However, leaking natural gas causes climate damage because methane (CH4) has a high global warming potential. In this study, we use extreme-value theory to explore the distribution of natural gas leak sizes. By analyzing ∼15 000 measurements from 18 prior studies, we show that all available natural gas leakage data sets are statistically heavy-tailed, and that gas leaks are more extremely distributed than other natural and social phenomena. A unifying result is that the largest 5% of leaks typically contribute over 50% of the total leakage volume. While prior studies used log-normal model distributions, we show that log-normal functions poorly represent tail behavior. Our results suggest that published uncertainty ranges of CH4 emissions are too narrow, and that larger sample sizes are required in future studies to achieve targeted confidence intervals. Additionally, we find that cross-study aggregation of data sets to increase sample size is not recommended due to apparent deviation between sampled populations. Understanding the nature of leak distributions can improve emission estimates, better illustrate their uncertainty, allow prioritization of source categories, and improve sampling design. Also, these data can be used for more effective design of leak detection technologies.

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Recent measurements of methane emissions from abandoned oil/gas wells show that these wells can be a substantial source of methane to the atmosphere, particularly from a small proportion of high-emitting wells. However, identifying high emitters remains a challenge. We couple 163 well measurements of methane flow rates; ethane, propane, and n-butane concentrations; isotopes of methane; and noble gas concentrations from 88 wells in Pennsylvania with synthesized data from historical documents, field investigations, and state databases. Using our databases, we (i) improve estimates of the number of abandoned wells in Pennsylvania; (ii) characterize key attributes that accompany high emitters, including depth, type, plugging status, and coal area designation; and (iii) estimate attribute-specific and overall methane emissions from abandoned wells. High emitters are best predicted as unplugged gas wells and plugged/vented gas wells in coal areas and appear to be unrelated to the presence of underground natural gas storage areas or unconventional oil/gas production. Repeat measurements over 2 years show that flow rates of high emitters are sustained through time. Our attribute-based methane emission data and our comprehensive estimate of 470,000–750,000 abandoned wells in Pennsylvania result in estimated state-wide emissions of 0.04–0.07 Mt (1012 g) CH4 per year. This estimate represents 5–8% of annual anthropogenic methane emissions in Pennsylvania. Our methodology combining new field measurements with data mining of previously unavailable well attributes and numbers of wells can be used to improve methane emission estimates and prioritize cost-effective mitigation strategies for Pennsylvania and beyond.

Abstract:
Greenhouse Gas (GHG) emissions are a growing problem in the United States (US). Methane (CH4) is a potent GHG produced by several stages of the natural gas sector. Current scrutiny focuses on the natural gas boom associated with unconventional shale gas; however, focus should still be given to conventional wells and outdated equipment. In an attempt to quantify these emissions, researchers modified an off-road utility terrain vehicle (UTV) to include a Full Flow Sampling system (FFS) for methane quantification. GHG emissions were measured from non-producing and remote low throughput natural gas components in the Marcellus region. Site audits were conducted at eleven locations and leaks were identified and quantified at seven locations including at a low throughput conventional gas and oil well, two out-of-service gathering compressors, a conventional natural gas well, a coalbed methane well, and two conventional and operating gathering compressors. No leaks were detected at the four remaining sites, all of which were coal bed methane wells. The total methane emissions rate from all sources measured was 5.3 ± 0.23 kg/hr, at a minimum.

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The widespread use of hydraulic fracturing (HF) has enabled a dramatic expansion of unconventional natural gas extraction in the U.S. While life cycle greenhouse gas (LC-GHG) emissions associated with HF have gained attention in recent years, little focus has been devoted to upstream LC-GHG impacts of HF natural gas (Clark, Burnham, Harto, & Horner, 2013; Verrastro, 2012). Focusing on 1,921 wells in Pennsylvania from 2012 to 2013, we used the Economic Input-Output Life Cycle Assessment model to assess LC-GHG emissions associated with production and transportation of chemicals and sand mining. Ton-miles from the transportation of sand and water were assessed with life cycle transportation emissions factors to generate LC-GHG emissions. LC-GHG emissions from upstream inputs assessed in this study equaled 1,374 tons of CO2e per well, but account for only 0.63% of the total LC-GHG emissions of HF natural gas. LC-GHG emissions from sand, water, and chemicals are quite small when compared with gas combustion, methane leakage, venting, and flaring from the other phases of the HF process.

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This paper analyzes the implications of the natural gas revolution on the US’ ability to achieve deep GHG emissions reductions of 80% below 2005 levels by 2050. It uses a hybrid energy-economy model to test how prevailing low US natural gas prices influence the magnitude of the required carbon price needed to achieve this target. While the paper finds in general that lower gas prices resulting from plentiful gas necessitate a higher carbon price to achieve this target, informing firms and consumers in advance about the magnitude of the future carbon price can lower the necessary level.

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The Bakken formation has contributed to the recent rapid increase in U.S. oil production, reaching a peak production of >1.2 × 106 barrels per day in early 2015. In this study, we estimate the energy intensity and greenhouse gas (GHG) emissions from 7271 Bakken wells drilled from 2006 to 2013. We model energy use and emissions using the Oil Production Greenhouse Gas Emissions Estimator (OPGEE) model, supplemented with an open-source drilling and fracturing model, GHGfrack. Overall well-to-refinery-gate (WTR) consumption of natural gas, diesel, and electricity represent 1.3%, 0.2%, and 0.005% of produced crude energy content, respectively. Fugitive emissions are modeled for a “typical” Bakken well using previously published results of atmospheric measurements. Flaring is a key driver of emissions: wells that flared in 2013 had a mean flaring rate that was ≈500 standard cubic feet per barrel or ≈14% of the energy content of the produced crude oil. Resulting production-weighted mean GHG emissions in 2013 were 10.2 g of CO2 equivalent GHGs per megajoule (henceforth, gCO2eq/MJ) of crude. Between-well variability gives a 5–95% range of 2–28 gCO2eq/MJ. If flaring is completely controlled, Bakken crude compares favorably to conventional U.S. crude oil, with 2013 emissions of 3.5 gCO2eq/MJ for nonflaring wells, compared to the U.S. mean of ≈8 gCO2eq/MJ.

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The increasing number of studies on the determination of natural methane in groundwater of shale gas prospection areas offers a unique opportunity for refining the quantification of natural methane emissions. Here methane emissions, computed from four potential sources, are reported for an area of ca. 16,500 km2 of the St. Lawrence Lowlands, Quebec (Canada), where Utica shales are targeted by the petroleum industry. Methane emissions can be caused by 1) groundwater degassing as a result of groundwater abstraction for domestic and municipal uses; 2) groundwater discharge along rivers; 3) migration to the surface by (macro- and micro-) diffuse seepage; 4) degassing of hydraulic fracturing fluids during first phases of drilling. Methane emissions related to groundwater discharge to rivers (2.47 × 10− 4 to 9.35 × 10− 3 Tg yr− 1) surpass those of diffuse seepage (4.13 × 10− 6 to 7.14 × 10− 5 Tg yr− 1) and groundwater abstraction (6.35 × 10− 6 to 2.49 × 10− 4 Tg yr− 1). The methane emission from the degassing of flowback waters during drilling of the Utica shale over a 10- to 20-year horizon is estimated from 2.55 × 10− 3 to 1.62 × 10− 2 Tg yr− 1. These emissions are from one third to sixty-six times the methane emissions from groundwater discharge to rivers. This study shows that different methane emission sources need to be considered in environmental assessments of methane exploitation projects to better understand their impacts.

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China relies heavily on coal for power generation, and the demand for coal in a country of this size makes China the world's largest carbon dioxide emitter; hence China is pursuing greener pathways for power generation. Importing shale gas in the form of LNG from Canada is one such pathway. It starts with the recovery of shale gas in Canada and its export to China. This paper quantifies well-to-wire (WTW) greenhouse gas (GHG) emissions per kilowatt hour (kWh) of Canadian shale gas-fuelled electricity in China through models. WTW emissions include emissions from recovery, processing, transmission, liquefaction, marine shipping, re-gasification, power plant operations, and electricity transmission and distribution. Four Canadian shale gas reserves – Montney, Horn River, Liard, and Cordova – are considered. The results show that the WTW GHG emissions of Canadian shale gas-fired combined cycle technology range from 567 to 610 gCO2/kWh (57–62% of the GHG emissions from China's present coal-fired electricity), and total well-to-port (WTP) GHG emissions (emissions from recovery, processing, and transmission to a liquefaction facility) range from 7.68 to 13.4 gCO2e/MJ. Sensitivity analysis results show that venting emissions during raw gas processing, flaring rates during well completion, and lifetime productivity of the gas significantly influence WTP emissions.

Abstract:
Methane is a greenhouse gas, and increases in atmospheric methane concentration over the past 250 years have driven increased radiative forcing of the atmosphere. Increases in atmospheric methane concentration since 1750 account for approximately 17% of increases in radiative forcing of the atmosphere, and that percentage increases by approximately a factor of 2 if the effects of the greenhouse gases produced by the atmospheric reactions of methane are included in the assessment. Because of the role of methane emissions in radiative forcing of the atmosphere, the identification and quantification of sources of methane emissions is receiving increased scientific attention. Methane emission sources include biogenic, geogenic, and anthropogenic sources; the largest anthropogenic sources are natural gas and petroleum systems, enteric fermentation (livestock), landfills, coal mining, and manure management. While these source categories are well-known, there is significant uncertainty in the relative magnitudes of methane emissions from the various source categories. Further, the overall magnitude of methane emissions from all anthropogenic sources is actively debated, with estimates based on source sampling extrapolated to regional or national scale ("bottom-up analyses") differing from estimates that infer emissions based on ambient data ("top-down analyses") by 50% or more. To address the important problem of attribution of methane to specific sources, a variety of new analytical methods are being employed, including high time resolution and highly sensitive measurements of methane, methane isotopes, and other chemical species frequently associated with methane emissions, such as ethane. This Account describes the use of some of these emerging measurements, in both top-down and bottom-up methane emission studies. In addition, this Account describes how data from these new analytical methods can be used in conjunction with chemical mass balance (CMB) methods for source attribution. CMB methods have been developed over the past several decades to quantify sources of volatile organic compound (VOC) emissions and atmospheric particulate matter. These emerging capabilities for making measurements of methane and species coemitted with methane, rapidly, precisely, and at relatively low cost, used together with CMB methods of source attribution can lead to a better understanding of methane emission sources. Application of the CMB approach to source attribution in the Barnett Shale oil and gas production region in Texas demonstrates both the importance of extensive and simultaneous source testing in the region being analyzed and the potential of CMB method to quantify the relative strengths of methane emission sources.

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This paper introduces GHGfrack, an open-source engineering-based model that estimates energy consumption and associated GHG emissions from drilling and hydraulic fracturing operations. We describe verification and calibration of GHGfrack against field data for energy and fuel consumption. We run GHGfrack using data from 6927 wells in Eagle Ford and 4431 wells in Bakken oil fields. The average estimated energy consumption in Eagle Ford wells using lateral hole diameters of 8 ¾ and 6 1/8-inch are 2.25 and 2.73 TJ/well, respectively. The average estimated energy consumption in Bakken wells using hole diameters of 6 inches for horizontal section is 2.16 TJ/well. We estimate average greenhouse gas (GHG) emissions of 419 and 510 tCO2eq./well for the two aforementioned assumed geometries in Eagle Ford respectively, and 417 tCO2eq./well for the case of Bakken. These estimates are limited only to GHG emissions from combustion of diesel fuel to supply energy only for rotation of drill string, drilling mud circulation, and fracturing pumps. Sensitivity analysis of the model shows that the top three key variables in driving energy intensity in drilling are the lateral hole diameter, drill pipe diameter, and mud flow rate. In hydraulic fracturing, the top three are lateral casing diameter, fracturing fluid volume, and length of the lateral.

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Sharp rises in the atmospheric abundance of ethane (C 2 H 6 ) have been detected from 2009 onwards in the Northern Hemisphere as a result of the unprecedented growth in the exploitation of shale gas and tight oil reservoirs in North America. Using time series of C 2 H 6 total columns derived from ground-based Fourier transform infrared (FTIR) observations made at five selected Network for the Detection of Atmospheric Composition Change sites, we characterize the recent C 2 H 6 evolution and determine growth rates of ∼5% yr −1 at mid-latitudes and of ∼3% yr −1 at remote sites. Results from CAM-chem simulations with the Hemispheric Transport of Air Pollutants, Phase II bottom-up inventory for anthropogenic emissions are found to greatly underestimate the current C 2 H 6 abundances. Doubling global emissions is required to reconcile the simulations and the observations prior to 2009. We further estimate that North American anthropogenic C 2 H 6 emissions have increased from 1.6 Tg yr −1 in 2008 to 2.8 Tg yr −1 in 2014, i.e. by 75% over these six years. We also completed a second simulation with new top-down emissions of C 2 H 6 from North American oil and gas activities, biofuel consumption and biomass burning, inferred from space-borne observations of methane (CH 4 ) from Greenhouse Gases Observing SATellite. In this simulation, GEOS-Chem is able to reproduce FTIR measurements at the mid-latitudinal sites, underscoring the impact of the North American oil and gas development on the current C 2 H 6 abundance. Finally we estimate that the North American oil and gas emissions of CH 4 , a major greenhouse gas, grew from 20 to 35 Tg yr −1 over the period 2008–2014, in association with the recent C 2 H 6 rise.

Abstract:
Oil and gas (O&G) well pads with high hydrocarbon emission rates may disproportionally contribute to total methane and volatile organic compound (VOC) emissions from the production sector. In turn, these emissions may be missing from most bottom-up emission inventories. We performed helicopter-based infrared camera surveys of more than 8,000 O&G well pads in seven U.S. basins to assess the prevalence and distribution of high-emitting hydrocarbon sources (detection threshold ~1?3 g s-1) . The proportion of sites with such high-emitting sources was 4% nationally but ranged from 1% in the Powder River (Wyoming) to 14% in the Bakken (North Dakota). Emissions were observed three times more frequently at sites in the oil-producing Bakken and oil-producing regions of mixed basins (p<0.0001, ?2 test). However, statistical models using basin and well pad characteristics explained 14% or less of the variance in observed emission patterns, indicating that stochastic processes dominate the occurrence of high emissions at individual sites. Over 90% of almost 500 detected sources were from tank vents and hatches. Although tank emissions may be partially attributable to flash gas, observed frequencies in most basins exceed those expected if emissions were effectively captured and controlled, demonstrating that tank emission control systems commonly underperform. Tanks represent a key mitigation opportunity for reducing methane and VOC emissions.

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Natural gas has been suggested as a “bridge fuel” in the transition from coal to a near-zero emission energy system. However, the expansion of natural gas risks a delay in the introduction of near-zero emission energy systems, possibly offsetting the potential climate benefits of a gas-for-coal substitution. We use a schematic climate model to estimate CO2 and CH4 emissions from integrated energy systems and the resulting changes in global warming over various timeframes. Then we evaluate conditions under which delayed deployment of near-zero emission systems would result in loss of all net climate benefit (if any) from using natural gas as a bridge. Considering only physical climate system effects, we find that there is potential for delays in deployment of near-zero-emission technologies to offset all climate benefits from replacing coal energy systems with natural gas energy systems, especially if natural gas leakage is high, the natural gas energy system is inefficient, and the climate change metric emphasizes decadal time scale changes.

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Recent work indicates that oil and gas methane (CH4) inventories for the United States are underestimated. Here we present results from direct measurements of CH4 emissions from 138 abandoned oil and gas wells, a source currently missing from inventories. Most abandoned wells do not emit CH4, but 6.5% of wells had measurable CH4 emissions. Twenty-five percent of wells we visited that had not been plugged emitted > 5 g CH4 h−1. Stable isotopes indicate that wells emit natural gas and/or coalbed CH4. We estimate that abandoned wells make a small contribution (<1%) to regional CH4 emissions in our study areas. Additional data are needed to accurately determine the contribution of abandoned wells to national CH4 budgets, particularly measurements in other basins and better characterization of the abundance and regional distribution of high emitters.

Abstract:
This study considered the fugitive emissions of methane (CH4) from former oil and gas exploration and production wells drilled to exploit conventional hydrocarbon reservoirs onshore in the UK. This study selected from the 66% of all onshore wells in the UK which appeared to be properly decommissioned (abandoned) that came from 4 different basins and were between 8 and 79 years old. The soil gas above each well was analysed and assessed relative to a nearby control site of similar land use and soil type. The results showed that of the 102 wells considered 30% had soil gas CH4 at the soil surface that was significantly greater than their respective control. Conversely, 39% of well sites had significant lower surface soil gas CH4 concentrations than their respective control. We interpret elevated soil gas CH4 concentrations to be the result of well integrity failure, but do not know the source of the gas nor the route to the surface. Where elevated CH4 was detected it appears to have occurred within a decade of it being drilled. The flux of CH4 from wells was 364 ± 677 kg CO2eq/well/year with a 27% chance that the well would have a negative flux to the atmosphere independent of well age. This flux is low relative to the activity commonly used on decommissioned well sites (e.g. sheep grazing), however, fluxes from wells that have not been appropriately decommissioned would be expected to be higher.

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The global burden of atmospheric methane has been increasing over the past decade, but the causes are not well understood. National inventory estimates from the U.S. Environmental Protection Agency indicate no significant trend in U.S. anthropogenic methane emissions from 2002 to present. Here we use satellite retrievals and surface observations of atmospheric methane to suggest that U.S. methane emissions have increased by more than 30% over the 2002–2014 period. The trend is largest in the central part of the country, but we cannot readily attribute it to any specific source type. This large increase in U.S. methane emissions could account for 30–60% of the global growth of atmospheric methane seen in the past decade.

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This paper addresses the need for surveillance of fugitive methane emissions over broad geographical regions. Most existing techniques suffer from being either extensive (but qualitative) or quantitative (but intensive with poor scalability). A total of two novel advancements are made here. First, a recursive Bayesian method is presented for probabilistically characterizing fugitive point-sources from mobile sensor data. This approach is made possible by a new cross-plume integrated dispersion formulation that overcomes much of the need for time-averaging concentration data. The method is tested here against a limited data set of controlled methane release and shown to perform well. We then present an information-theoretic approach to plan the paths of the sensor-equipped vehicle, where the path is chosen so as to maximize expected reduction in integrated target source rate uncertainty in the region, subject to given starting and ending positions and prevailing meteorological conditions. The information-driven sensor path planning algorithm is tested and shown to provide robust results across a wide range of conditions. An overall system concept is presented for optionally piggybacking of these techniques onto normal industry maintenance operations using sensor-equipped work trucks.