Inefficient and unlit natural gas flares both emit large quantities of methane

Technological Maturity of Aircraft-Based Methane Sensing for Greenhouse Gas Mitigation

Methane is a major contributor to anthropogenic greenhouse gas emissions. Identifying large sources of methane, particularly from the oil and gas sectors, will be essential for mitigating climate change. Aircraft-based methane sensing platforms can rapidly detect and quantify methane point-source emissions across large geographic regions, and play an increasingly important role in industrial methane management and greenhouse gas inventory. We independently evaluate the performance of five major methane-sensing aircraft platforms: Carbon Mapper, GHGSat-AV, Insight M, MethaneAIR, and Scientific Aviation. Over a 6 week period, we released metered gas for over 700 single-blind measurements across all five platforms to evaluate their ability to detect and quantify emissions that range from 1 to over 1,500 kg(CH4)/h. Aircraft consistently quantified releases above 10 kg(CH4)/h, and GHGSat-AV and Insight M detected emissions below 5 kg(CH4)/h. Fully blinded quantification estimates for platforms using downward-facing imaging spectrometers have parity slopes ranging from 0.76 to 1.13, with R2 values of 0.61 to 0.93; the platform using continuous air sampling has a parity slope of 0.5 (R2 = 0.93). Results demonstrate that aircraft-based methane sensing has matured since previous studies and is ready for an increasingly important role in environmental policy and regulation.

Quantifying flare combustion efficiency using an imaging Fourier transform spectrometer

Mid-wavelength infrared (MWIR) imaging Fourier transform spectrometers (IFTSs) are a promising technology for measuring flare combustion efficiency (CE) and destruction removal efficiency (DRE). These devices generate spectrally resolved intensity images of the flare plume, which may then be used to infer column densities of relevant species along each pixel line-of-sight. In parallel, a 2D projected velocity field may be inferred from the apparent motion of flow features between successive images. Finally, the column densities and velocity field are combined to estimate the mass flow rates for the species needed to calculate the CE or DRE. Since the MWIR IFTS can measure key carbon-containing species in the flare plume, it is possible to measure CE without knowing the fuel flow rate, which is important for fenceline measurements. This work demonstrates this approach on a laboratory heated vent, and then deploys the technique on two working flares: a combustor burning natural gas at a known rate, and a steam-assisted flare at a petrochemical refinery. Analysis of the IFTS data highlights the potential of this approach, but also areas for future development to transform this approach into a reliable technique for quantifying flare emissions.Implications: Our research is motivated by the need to assess hydrocarbon emissions from flaring, which is a critical problem of global significance. For example, recent studies have shown that methane destruction efficiency of flaring from upstream oil may be significantly lower than the commonly assumed figure of 98%; work by Plant et al. , in particular, suggest that this discrepancy amounts to CO2 emissions from 2 to 8 million automobiles annually, considering the US alone. Similarly, the international energy agency (IEA) estimates a global flare efficiency of 92%, which translates in 8 million tons of CH4 emitted by flares in 2020. Highlighted by these studies and supported by the World Bank initiatives toward zero routine flaring emissions, there is an urgent need for oil and gas industry to assess their flare methane emission, and overall hydrocarbon emissions. At the very least, it is critical to identify problematic flare operating conditions and means to mitigate flare emissions. Focusing on remote quantification of plume species, the measurement technique and quantification method presented in this paper is a considerable step forward in that direction by computing combustion efficiency and key components for destruction efficiency.

Unaddressed Uncertainties When Scaling Regional Aircraft Emission Surveys to Basin Emission Estimates

Wide-area aerial methods provide comprehensive screening of methane emissions from oil and gas (O & G) facilities in production basins. Emission detections ("plumes") from these studies are also frequently scaled to the basin level, but little is known regarding the uncertainties during scaling. This study analyzed an aircraft field study in the Denver-Julesburg basin to quantify how often plumes identified maintenance events, using a geospatial inventory of 12,629 O & G facilities. Study partners (7 midstream and production operators) provided the timing and location of 5910 maintenance events during the 6 week study period. Results indicated three substantial uncertainties with potential bias that were unaddressed in prior studies. First, plumes often detect maintenance events, which are large, short-duration, and poorly estimated by aircraft methods: 9.2 to 46% (38 to 52%) of plumes on production were likely known maintenance events. Second, plumes on midstream facilities were both infrequent and unpredictable, calling into question whether these estimates were representative of midstream emissions. Finally, 4 plumes attributed to O & G (19% of emissions detected by aircraft) were not aligned with any O & G location, indicating that the emissions had drifted downwind of some source. It is unclear how accurately aircraft methods estimate this type of plume; in this study, it had material impact on emission estimates. While aircraft surveys remain a powerful tool for identifying methane emissions on O & G facilities, this study indicates that additional data inputs, e.g., detailed GIS data, a more nuanced analysis of emission persistence and frequency, and improved sampling strategies are required to accurately scale plume estimates to basin emissions.

Point Sensor Networks Struggle to Detect and Quantify Short Controlled Releases at Oil and Gas Sites

This study evaluated multiple commercially available continuous monitoring (CM) point sensor network (PSN) solutions under single-blind controlled release testing conducted at operational upstream and midstream oil and natural gas (O&G) sites. During releases, PSNs reported site-level emission rate estimates of 0 kg/h between 38 and 86% of the time. When non-zero site-level emission rate estimates were provided, no linear correlation between the release rate and the reported emission rate estimate was observed. The average, aggregated across all PSN solutions during releases, shows 5% of the mixing ratio readings at downwind sensors were greater than the site's baseline plus two standard deviations. Four of seven total PSN solutions tested during this field campaign provided site-level emission rate estimates with the site average relative error ranging from -100% to 24% for solution D, -100% to -43% for solution E, -25% for solution F (solution F was only at one site), and -99% to 430% for solution G, with an overall average of -29% across all sites and solutions. Of all the individual site-level emission rate estimates, only 11% were within ±2.5 kg/h of the study team's best estimate of site-level emissions at the time of the releases.

Air Quality and Health Impacts of Onshore Oil and Gas Flaring and Venting Activities Estimated Using Refined Satellite-Based Emissions

Emissions from flaring and venting (FV) in oil and gas (O&G) production are difficult to quantify due to their intermittent activities and lack of adequate monitoring and reporting. Given their potentially significant contribution to total emissions from the O&G sector in the United States, we estimate emissions from FV using Visible Infrared Imaging Radiometer Suite satellite observations and state/local reported data on flared gas volume. These refined estimates are higher than those reported in the National Emission Inventory: by up to 15 times for fine particulate matter (PM2.5), two times for sulfur dioxides, and 22% higher for nitrogen oxides (NOx). Annual average contributions of FV to ozone (O3), NO2, and PM2.5 in the conterminous U.S. (CONUS) are less than 0.15%, but significant contributions of up to 60% are found in O&G fields with FV. FV contributions are higher in winter than in summer months for O3 and PM2.5; an inverse behavior is found for NO2. Nitrate aerosol contributions to PM2.5 are highest in the Denver basin whereas in the Permian and Bakken basins, sulfate and elemental carbon aerosols are the major contributors. Over four simulated months in 2016 for the entire CONUS, FV contributes 210 additional instances of exceedances to the daily maximum 8-hr average O3 and has negligible contributions to exceedance of NO2 and PM2.5, given the current form of the national ambient air quality standards. FV emissions are found to cause over $7.4 billion in health damages, 710 premature deaths, and 73,000 asthma exacerbations among children annually.

In Situ Sampling of NOx Emissions from United States Natural Gas Flares Reveals Heavy-Tail Emission Characteristic

Natural gas flaring is a common practice employed in many United States (U.S.) oil and gas regions to dispose of gas associated with oil production. Combustion of predominantly hydrocarbon gas results in the production of nitrogen oxides (NOx). Here, we present a large field data set of in situ sampling of real world flares, quantifying flaring NOx production in major U.S. oil production regions: the Bakken, Eagle Ford, and Permian. We find that a single emission factor does not capture the range of the observed NOx emission factors within these regions. For all three regions, the median emission factors fall within the range of four emission factors used by the Texas Commission for Environmental Quality. In the Bakken and Permian, the distribution of emission factors exhibits a heavy tail such that basin-average emission factors are 2-3 times larger than the value employed by the U.S. Environmental Protection Agency. Extrapolation to basin scale emissions using auxiliary satellite assessments of flare volumes indicates that NOx emissions from flares are skewed, with 20%-30% of the flares responsible for 80% of basin-wide flaring NOx emissions. Efforts to reduce flaring volume through alternative gas capture methods would have a larger impact on the NOx oil and gas budget than current inventories indicate.

Fence-Line Spectroscopic Measurements Suggest Carry-Over of Salt-Laden Aerosols into Flare Systems Is Common

Pollutant emissions from gas flares in the upstream oil and gas (UOG) industry can be exacerbated by aerosols of coproduced liquid hydrocarbons and formation water that survive separation and enter the flare. Of noteworthy concern is the potential impact of salt-laden aerosols, since the associated chlorine may adversely affect combustion and emissions. Here, we use a novel approach to remotely detect carry-over of salt-laden aerosols into field-operational flares via flame emission spectroscopy targeting two of the most abundant species in produced water samples, sodium and potassium. Ninety-five UOG flares were examined during field campaigns in the Bakken (U.S.A. and Canada) and Amazon (Ecuador) basins. For the first time, carry-over of salt species into flares is definitively detected and further found to be concerningly common, with 74% of studied flares having detectable sodium and/or potassium signatures. Additional analysis reveals that carry-over strongly correlates with reported flared gas volume (positive) and well age (negative), but carry-over was also observed in flares linked to older wells and those flaring relatively little gas. Given the scale of global UOG flaring and the risk of salt-laden aerosols affecting emissions, these findings emphasize the need to review separation standards and re-evaluate pollutant emissions from flares experiencing carry-over.

Fundamental Limitation in Electrochemical Methane Oxidation to Alcohol: A Review and Theoretical Perspective on Overcoming It

The direct conversion of gaseous methane to energy-dense liquid derivatives such as methanol and ethanol is of profound importance for the more efficient utilization of natural gas. However, the thermo-catalytic partial oxidation of this simple alkane has been a significant challenge due to the high C-H bond energy. Exploiting electrocatalysis for methane activation via active oxygen species generated on the catalyst surface through electrochemical water oxidation is generally considered as economically viable and environmentally benign compared to energy-intensive thermo-catalysis. Despite recent progress in electrochemical methane oxidation to alcohol, the competing oxygen evolution reaction (OER) still impedes achieving high faradaic efficiency and product selectivity. In this review, an overview of current progress in electrochemical methane oxidation, focusing on mechanistic insights on methane activation, catalyst design principles based on descriptors, and the effect of reaction conditions on catalytic performance are provided. Mechanistic requirements for high methanol selectivity, and limitations of using water as the oxidant are discussed, and present the perspective on how to overcome these limitations by employing carbonate ions as the oxidant.

Assessing the Productivity of the Direct Conversion of Methane-to-Methanol over Copper-Exchanged Zeolite Omega (MAZ) via Oxygen Looping

The methane-to-methanol (MtM) conversion via the oxygen looping approach using copper-exchanged zeolites has been extensively studied over the last decade. While a lot of research has focussed on maximizing yield and selectivity, little has been directed toward productivity-a metric far more meaningful for evaluating industrial potential. Using copper-exchanged zeolite omega (Cu-omega), a material highly active and selective for the MtM conversion using the isothermal oxygen looping approach, we show that this material exhibits unprecedented potential for industrial valorization. In doing so, we also present a novel methodology combining operando XAS and mass spectrometry for the screening of materials for the MtM conversion in oxygen looping mode.

Greenhouse gas emissions from U.S. crude oil pipeline accidents: 1968 to 2020

Crude oil pipelines are considered as the lifelines of energy industry. However, accidents of the pipelines can lead to severe public health and environmental concerns, in which greenhouse gas (GHG) emissions, primarily methane, are frequently overlooked. While previous studies examined fugitive emissions in normal operation of crude oil pipelines, emissions resulting from accidents were typically managed separately and were therefore not included in the emission account of oil systems. To bridge this knowledge gap, we employed a bottom-up approach to conducted the first-ever inventory of GHG emissions resulting from crude oil pipeline accidents in the United States at the state level from 1968 to 2020, and leveraged Monte Carlo simulation to estimate the associated uncertainties. Our results reveal that GHG emissions from accidents in gathering pipelines (~720,000 tCO2e) exceed those from transmission pipelines (~290,000 tCO2e), although significantly more accidents have occurred in transmission pipelines (6883 cases) than gathering pipelines (773 cases). Texas accounted for over 40% of total accident-related GHG emissions nationwide. Our study contributes to enhanced accuracy of the GHG account associated with crude oil transport and implementing the data-driven climate mitigation strategies.

Quantification of Gas Flaring from Satellite Imagery: A Comparison of Two Methods for SLSTR and BIROS Imagery

Gas flaring is an environmental problem of local, regional and global concerns. Gas flares emit pollutants and greenhouse gases, yet knowledge about the source strength is limited due to disparate reporting approaches in different geographies, whenever and wherever those are considered. Remote sensing has bridged the gap but uncertainties remain. There are numerous sensors which provide measurements over flaring-active regions in wavelengths that are suitable for the observation of gas flares and the retrieval of flaring activity. However, their use for operational monitoring has been limited. Besides several potential sensors, there are also different approaches to conduct the retrievals. In the current paper, we compare two retrieval approaches over an offshore flaring area during an extended period of time. Our results show that retrieved activities are consistent between methods although discrepancies may originate for individual flares at the highly temporal scale, which are traced back to the variable nature of flaring. The presented results are helpful for the estimation of flaring activity from different sources and will be useful in a future integration of diverse sensors and methodologies into a single monitoring scheme.

An inventory of greenhouse gas emissions due to natural gas pipeline incidents in the United States and Canada from 1980s to 2021

Natural gas is believed to be a critical transitional energy source. However, natural gas pipelines, once failed, will contribute to a large amount of greenhouse gas (GHG) emissions, including methane from uncontrolled natural gas venting and carbon dioxide from flared natural gas. However, the GHG emissions caused by pipeline incidents are not included in the regular inventories, making the counted GHG amount deviate from the reality. This study, for the first time, establishes an inventory framework for GHG emissions including all natural gas pipeline incidents in the two of the largest gas producers and consumers in North America (United States and Canada) from 1980s to 2021. The inventory comprises GHG emissions resulting from gathering and transmission pipeline incidents in a total of 24 states or regions in the United States between 1970 and 2021, local distribution pipeline incidents in 22 states or regions between 1970 and 2021, as well as natural gas pipeline incidents in a total of 7 provinces or regions in Canada between 1979 and 2021. These datasets can improve the accuracy of regular emission inventories by covering more emission sources in the United States and Canada and provide essential information for climate-oriented pipeline integrity management.

Direct Catalytic Oxidation of Low-Concentration Methane to Methanol in One Step on Ni-Promoted BiOCl Catalysts

The direct oxidation of low-concentration methane (CH₄) to methanol (CH₃OH) is often regarded as the "holy grail". However, it still is very difficult and challenging to oxidize methane to methanol in one step. In this work, we present a new approach to directly oxidize CH₄ to generate CH₃OH in one step by doping non-noble metal Ni sites on bismuth oxychloride (BiOCl) equipped with high oxygen vacancies. Thereinto, the conversion rate of CH₃OH can reach 39.07 μmol/(g_cat·h) under 420 °C and flow conditions on the basis of O₂ and H₂O. The crystal morphology structure, physicochemical properties, metal dispersion, and surface adsorption capacity of Ni-BiOCl were explored, and the positive effect on the oxygen vacancy of the catalyst was proved, thus improving the catalytic performance. Furthermore, in situ diffuse reflectance infrared Fourier transform spectroscopy (DRIFTS) was also performed to study the surface adsorption and reaction process of methane to methanol in one step. Results demonstrate that the key to keep good activity lies in the oxygen vacancies of unsaturated Bi atoms, which can adsorb and active CH₄ and to produce methyl groups and adsorbing hydroxyl groups in methane oxidation process. This study broadens the application of oxygen-deficient catalysts in the catalytic conversion of CH₄ to CH₃OH in one step, which provides a new perspective on the role of oxygen vacancies in improving the catalytic performance of methane oxidation.

Functionalized GO Membranes for Efficient Separation of Acid Gases from Natural Gas: A Computational Mechanistic Understanding

Membrane separation technology is applied in natural gas processing, while a high-performance membrane is highly in demand. This paper considers the bright future of functionalized graphene oxide (GO) membranes in acid gas removal from natural gas. By molecular simulations, the adsorption and diffusion behaviors of several unary gases (N₂, CH₄, CO₂, H₂S, and SO₂) are explored in the 1,4-phenylenediamine-2-sulfonate (PDASA)-doped GO channels. Molecular insights show that the multilayer adsorption of acid gases evaluates well by the Redlich-Peterson model. A tiny amount of PDASA promotes the solubility coefficient of CO₂ and H₂S, respectively, up to 4.5 and 5.3 mmol·g^-1·kPa^-1, nearly 2.5 times higher than those of a pure GO membrane, which is due to the improved binding affinity, great isosteric heat, and hydrogen bonds, while N₂ and CH₄ only show single-layer adsorption with solubility coefficients lower than 0.002 mmol·g^-1·kPa^-1, and their weak adsorption is insusceptible to PDASA. Although acid gas diffusivity in GO channels is inhibited below 20 × 10^-6 cm²·s^-1 by PDASA, the solubility coefficient of acid gases is certainly high enough to ensure their separation efficiency. As a result, the permeabilities (P) of acid gases and their selectivities (α) over CH₄ are simultaneously improved (P_CO2 = 7265.5 Barrer, α_CO2/CH4 = 95.7; P_(H2S+CO2) = 42075.1 Barrer, α_H2S/CH4 = 243.8), which outperforms most of the ever-reported membranes. This theoretical study gives a mechanistic understanding of acid gas separation and provides a unique design strategy to develop high-performance GO membranes toward efficient natural gas processing.

Tackling unlit and inefficient gas flaring

Emissions from flaring threaten the global climate and the health of local communities.