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The Clean Air Task Force criticizes a proposed EPA update to air emissions limits for the oil and natural gas industry, stating that while the rules make progress, they fail to directly regulate methane. The author asserts that the industry is the largest man-made source of methane in the US and that cost-effective measures to stop leaks and dumping could provide climate benefits equivalent to retiring hundreds of coal-fired generators while saving the industry over $30 million annually.

The report finds that beef production accounts for approximately 2.2% of total U.S. global warming emissions. While improving forage quality could reduce methane emissions from pasture beef by 15% to 30%, the overall impact on U.S. emissions would be less than 0.5%. However, well-managed pastures offer significant carbon sequestration potential, potentially offsetting 0.1% to 2% of annual U.S. heat-trapping emissions. The document compares pasture-finishing systems with confined animal feeding operations (CAFOs), noting that while CAFOs often have higher feed efficiency, pastures generally sequester more carbon. The author recommends that the USDA expand research into nutritious pasture crops and provide incentive payments for best management practices.

The report analyzes the climate impact of U.S. beef production, noting that beef cattle and stored manure account for 18 percent of U.S. methane emissions. It argues that while improving forage quality and pasture management can reduce methane emissions by 15 to 30 percent, the overall impact on total U.S. global warming emissions would be less than 0.5 percent. The document compares pasture-raised systems with confined animal feeding operations (CAFOs), highlighting that while CAFOs offer faster weight gain and higher feed efficiency, well-managed pastures sequester more carbon. It recommends that the USDA expand research into nutritious pasture crops and provide incentive payments for practices that curb emissions and boost carbon sequestration.

The statement opposes the PH Barro Blanco hydroelectric project by GENISA in Panama, arguing that the 258.67-hectare reservoir would destroy indigenous Ngöbe Buglé sacred sites, displace local economies based on agriculture and fishing, and increase greenhouse gas emissions through methane release from decomposing organic matter in the reservoir. It further claims the project would cause water shortages by reserving 90% of water for power generation and disrupt aquatic biodiversity and sediment flow to mangroves.

The document argues that capturing biogas—primarily methane—from organic waste sources is a cost-effective method to mitigate climate change and displace fossil fuels. It details the technical and economic viability of landfill gas (LFG) projects, wastewater treatment anaerobic digestion, and agricultural manure digesters, while identifying policy barriers such as high capital costs and grid interconnection issues.

The report analyzes the 'hidden costs' of CAFOs, including taxpayer-funded subsidies and externalized environmental and health damages. It argues that CAFOs are not more efficient than medium-sized or pasture-based alternatives but are favored by government policies and the market power of large meat processors. The document details the pollution caused by manure, the rise of antibiotic-resistant pathogens, and the economic decline of rural communities, while proposing policy reforms to level the playing field for sustainable alternatives.

The document examines the dominance of gas pipeline refurbishment projects within Russia's JI portfolio under Track 2, specifically analyzing whether these projects are 'additional' or would have occurred due to economic incentives. It highlights the role of Gazprom's institutional control over distribution networks and the lack of historical leakage data, which complicates the establishment of accurate emission baselines.

The document describes how automated air/fuel ratio (AFR) controls can optimize the operation of natural gas engines to reduce fuel consumption and emissions. It highlights a case study where the installation of the REMVue system on 51 engines in the Gulf of Mexico led to fuel savings of 18-24% and a reduction of 128 Mcf of methane emissions per unit annually. The economic analysis indicates a total cost of $6.1 million for the project, with an average installation cost of $120,000 per unit and a calculated payback period of 1.4 years based on fuel savings.

The document outlines how the use of monitoring equipment, process models, and regular maintenance of heat exchangers in cryogenic Nitrogen Rejection Units (NRUs) can reduce methane loss in vent streams. It highlights a specific case where process adjustments reduced methane content in the vent stream from 5% to 2%, resulting in significant gas recovery.

The document outlines a method for recovering gas from pipeline pigging, where liquids are removed from gathering systems using pigs. It details the necessary equipment, such as vapor recovery compressors and storage tanks, and provides economic data showing that small recovery systems can be installed for approximately $24,000 with annual operating costs exceeding $1,000.

The document outlines a method to capture methane and other pollutants from condensed liquids at the first compressor station of transmission pipelines. By using gas combustion devices to burn off gases released when liquids are moved to atmospheric pressure storage tanks, operators can reduce emissions. One partner, Columbia Gulf Transmission, reported saving 334,000 standard cubic feet of methane annually from two condensate storage tanks.

The document outlines the practice of capturing 'casing head gas'—methane and other gases that accumulate in the annular space between the casing and tubing—by routing it into a vapor recovery unit (VRU) instead of venting it to the atmosphere. This approach is applicable to wells producing via tubing without packing units and leverages the similar pressure and composition of casing head gas and tank emissions. One reported case by Marathon Petroleum showed an average annual recovery of 7,300 thousand cubic feet of methane over five years, which is equivalent to approximately 10,000 thousand cubic feet of gas containing 73% methane. Economically, the recovery of this gas can offset the costs of piping and increased electricity required for the VRU to inject gas into a 100 psi system, with one partner reporting an electricity cost increase of 3,400 USD per year at a rate of 7.5 cents per kWh.

The document outlines a practice reported by Chevron U.S.A. Production Company to replace methane-rich natural gas used for blanketing water storage tanks with produced CO2-rich gas. This conversion prevents the formation of explosive mixtures in tanks while reducing the venting of methane into the atmosphere. A specific implementation across nine units at a water treatment plant resulted in an annual saving of 32,600 thousand cubic feet of methane gas. The document notes that while CO2-rich gas is a better alternative, it can form acid when dissolved in produced water, necessitating internal tank lining to prevent corrosion.

The document outlines the use of electronic flare ignition devices to replace traditional continuous or intermittent flames in flare stacks, preventing the release of unburned methane and volatile organic compounds (VOCs) when flames are extinguished by wind. It highlights that these devices can be powered by solar-charged batteries in remote areas and may be paired with flame sensors to shut off gas flow. Economically, the primary driver is the saving of natural gas that would otherwise be burned as a pilot flame, with a reported payback period of less than three years and a methane reduction of 168,000 standard cubic feet per year per device replacing a flame that is out for 24 hours annually.

The document outlines a technique where foaming agents (soap) are injected into gas production wells to facilitate the removal of liquids, thereby reducing the frequency of gas purging and the associated methane emissions. Reported results for a single well show a methane emission reduction of 2,520 thousand cubic feet per year.

The document details the use of an ejector—a Venturi-style pipe opening—to mitigate methane emissions during the maintenance of compressors and pipelines. By using high-pressure gas to draw low-pressure gas into a medium-pressure stream, the system avoids atmospheric venting. One partner, Marathon Oil Company, reported saving over 8,000 cubic feet of gas over 55 months using this method. The analysis suggests a single ejector used once a year to drain a 2-mile, 18-inch pipeline can reduce emissions by 700,000 cubic feet per year, with a potential return on investment in less than three years.

The document describes the transition from gas-expansion turbine starters to electric starters for internal combustion engines used in compressors, generators, and pumps within the natural gas sector. It highlights that electric starters eliminate methane venting and leakage, potentially reducing emissions by 23,000 to 600,000 cubic feet per year per unit. The analysis suggests the project can achieve a return on investment in less than three years, depending on capital costs and electricity prices.

The document outlines a technical opportunity to mitigate methane emissions by using pressurized storage for condensate instead of atmospheric storage, which prevents the flashing of methane into the air. Based on data from Burlington Resources, the implementation of four pressurized tanks resulted in total savings of 27,992 thousand cubic feet per year, with methane savings specifically accounting for 7,000 thousand cubic feet per year. The capital cost for installation in 1998 was 37,500 USD, with annual operating costs of 2,500 USD, allowing the methane recovery savings to cover costs within two years.

The document outlines a technical opportunity to reduce methane emissions in natural gas production by installing velocity tubing strings. These strings increase gas flow velocity to remove reservoir liquids without venting gas to the atmosphere. One reported case showed a reduction of 4,680 thousand cubic feet of methane emissions per year per well by eliminating bi-weekly venting. The technology is most applicable to wells with relatively small liquid production and higher reservoir pressure, with a potential payback period of less than three years.

The document outlines a method for reducing methane emissions during compressor shutdowns by redirecting purge gas to a fuel gas system. This practice, reported by the Phillips Enron Gas Pipeline Group, can recover approximately 12,000 cubic feet of gas per shutdown event. For a station with six compressors experiencing 42 shutdowns annually, the estimated savings are 500,000 cubic feet of methane per year. Capital costs for necessary piping and valves are estimated between $900 and $1,600 per compressor, with a projected payback period of less than three years based on a gas price of $3 per thousand cubic feet.