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The document outlines a practice reported by Western Gas Resources to control gas hydrate formation in low-pressure gas gathering systems (50-400 psi) by replacing glycol dehydration units with solar-powered methanol injection pumps. This transition eliminated volatile organic compound emissions from dehydration units and reduced methane emissions by an average of 800 thousand cubic feet per site annually. The implementation cost is approximately $2,250 per installation, with a payback period of one year, driven by reduced maintenance, lower operating expenses, and the value of saved gas.

The document describes a practice of extending the replacement interval for internal rotating modules in turbine meters from two years to three years. This change reduces the frequency of pipeline venting during maintenance, thereby lowering methane emissions and labor costs. One partner, Columbia Gas Transmission, reported that this adjustment reduced methane emission rates by approximately one-sixth across hundreds of meters. For a system of 500 8-inch turbine meters, the estimated methane savings are 27 million cubic feet per year.

The document outlines a method to mitigate methane leaks by replacing or supplementing single-use burst plates with secondary relief valves that close automatically once pressure returns to safe levels.

The document outlines a method for removing water from natural gas pipelines using conical separators and in-line heaters instead of traditional glycol dehydration. This approach avoids methane emissions associated with glycol dehydrators. One partner reported saving 1,930 thousand cubic feet of methane by replacing 14 dehydrators, with an estimated annual saving of 130 thousand cubic feet for a specific gas flow volume. The technology is noted for having a fast payback period because capital and operating costs are significantly lower than those of glycol dehydrators.

The document outlines a cost-effective practice for identifying and repairing leaking pressure safety valves to mitigate methane emissions. It specifies that proactive testing using organic vapor analyzers, acoustic leak detectors, or large-volume samplers can prevent significant gas leaks caused by worn seals or contamination. The report provides specific emission reduction data, noting an average emission rate of 57.5 thousand cubic feet per year per valve, with one partner reporting a total methane surplus rate of 853 thousand cubic feet per year. Economic analysis suggests that the practice is most cost-effective when applied to large groups of valves, with a specific example of reducing emissions by 170 thousand cubic feet per year for compressors with three safety valves.

The document outlines a practice where a pig is placed in an isolated pipeline section and pushed by an inert gas to displace natural gas. This process prevents the common practice of depressurizing pipelines by venting gas to the atmosphere during operation or maintenance. One partner reported avoiding 538,000 cubic feet of methane over six such purging operations. The primary driver for this practice is safety rather than methane savings, and it requires pig launching/receiving equipment and a mobile nitrogen supply.

The document outlines the technical application and economic impact of installing downhole separator pumps to mitigate methane emissions from produced water storage tanks.

The document outlines a method for reducing methane emissions in gas production wells by injecting foaming agents (soap) to help lift liquids to the surface, thereby reducing the need for atmospheric purging. It highlights a specific case where emissions were reduced by 2,520 Mcf per year for a single well by changing the purging frequency from bi-weekly to monthly. The primary benefit is the extension of the well's productive life, with capital costs typically ranging from under $1,000 to over $10,000 depending on the installation.

The document outlines a practice for the annual inspection and repair of blowdown valves at compressor stations, which are prone to leaks due to pressure and thermal stress. It provides estimated gas savings, economic evaluations, and methane content assumptions across different natural gas industry sectors.

The document outlines how installing smaller-diameter velocity tubing strings increases gas flow velocity to lift liquids from the reservoir, eliminating the need for frequent atmospheric venting. Based on a report from TotalFinaElf, this practice can save 4,680 Mcf of methane per year per well by removing bi-weekly liquid discharges of 180 Mcf. The technology is most applicable to natural gas wells with higher reservoir pressure and relatively small liquid production, offering a potential return on investment in less than three years.

The document outlines a method for reducing methane emissions by optimizing the operation and maintenance of turbine compressors to avoid frequent engine starts, which typically vent unignited gas to the atmosphere. A reported case by PECO Energy Company demonstrated a reduction in compressor restarts from 9.4 to 1 per year, saving 132 Mcf of methane annually.

The document details a 'Smart' Automation System implemented by BP on over 2,200 gas wells in the San Juan Basin, New Mexico. The system uses remote measurement units and artificial intelligence to monitor well parameters—such as casing and tubing pressure and flow rates—to optimize liquid removal and reduce the need for venting gas to the atmosphere. This implementation resulted in a reduction of methane emissions by 2.3 billion cubic feet annually, generating an estimated $6.9 million in additional annual income based on a gas value of $3 per thousand cubic feet. The system is applicable to gas wells that produce associated liquids and are subject to loading, with installation costs estimated at less than $12,000 per well and a typical return on investment within 1 to 3 years.

The document describes the installation of pumpjacks (positive displacement, sucker-rod downhole pumps) on low-pressure gas wells that suffer from liquid loading. By removing produced water, pumpjacks eliminate the need for operators to manually vent gas and water into the atmosphere, which can otherwise take up to one hour per well daily. One partner reported that installing pumpjacks on 45 wells reduced methane emissions by 43,780 thousand cubic feet annually, or 973 thousand cubic feet per well per year. Economically, this reduction in emissions represents an additional annual revenue of $2,900 per well, based on a nominal value of $3 per thousand cubic feet of gas. While the payback period is estimated at 15 to 22 years with installation costs around $62,000 per well, the practice is justified by extended well life and increased gas recovery. Additionally, using electric motors instead of natural gas engines for pumpjacks can further reduce methane emissions by approximately 8 thousand cubic feet per unit annually, as it eliminates the 0.5% unburnt methane typically associated with fuel consumption of 1,500 thousand cubic feet per year.

The document describes the installation of pumpjacks (rod-driven positive displacement pumps) to extract formation water from low-pressure gas wells that would otherwise require atmospheric venting to restore flow. One participant, ConocoPhillips, reported that installing pumpjacks on 45 wells eliminated venting emissions totaling 43,780 Mcf per year, or 973 Mcf per well annually. While the investment recovery period is estimated at 15 to 22 years with installation costs around $62,000 per well, the practice is justified by increased gas reserves, extended well life, and additional revenue of $2,900 per well annually. The document also notes that using electric motors instead of natural gas engines can further reduce emissions by approximately 1,500 Mcf of fuel per unit per year.

The SEI/UNEP Fuel Chain Project developed a methodology and software tool within the LEAP/EDB system to assess the full life-cycle environmental impacts of energy resources. By analyzing the 'chain' from extraction to end-use, the project aims to provide a more comprehensive comparison of fuel options than site-specific assessments. Case studies in Sri Lanka and Venezuela were used to validate the tool, focusing on biomass, coal, natural gas, and petroleum. In Sri Lanka, biomass was found to be environmentally superior to coal for electricity generation, while LPG was cleaner than biomass for household cooking. In Venezuela, natural gas was preferred over residual fuel oil for electricity, but its advantage over diesel for transport was mixed due to methane emissions and lower vehicle efficiency.

The document is a letter from a coalition of Canadian organizations supporting the Pan-Canadian Framework on Climate Change and Clean Growth. The authors argue that Canada's long-term prosperity depends on investing in a low-carbon economic transformation to remain competitive in a global clean technology market. They emphasize the necessity of 'just transition measures' to support workers and communities affected by the shift away from high-carbon sectors. The coalition offers specific support for implementing the framework, including prioritizing engagement with Indigenous communities based on the United Nations Declaration on the Rights of Indigenous Peoples, establishing a robust federal backstop for carbon pricing, and modernizing electricity and transportation systems to reduce greenhouse gas emissions.

The report estimates that the Coal Phase-Out Regulations, Clean Electricity Regulations (CER), Volatile Organic Compound (VOC) Regulations, and Methane Regulations will provide between $18 billion and $21 billion in direct health benefits by 2050. These savings, primarily derived from respiratory benefits of reduced emissions, are equivalent to the cost of 2,200 to 2,500 doctors over a 36-year period. The regulations target pollutants including particulate matter, benzene, mercury, lead, NOX, SOX, PM2.5, and VOCs.

The document argues that the LNG and fracking industries in British Columbia increase healthcare costs by exacerbating climate change, causing local health issues, and contributing to physician shortages in regions like Dawson Creek. It calls for a moratorium on new fracking, stricter pollution regulations, and a phase-out of natural gas in buildings by 2025.

A group of doctors and nurses issued a health advisory to the British Columbia government, warning that the expansion of liquefied natural gas (LNG) and hydraulic fracturing (fracking) poses severe risks to public health. They highlight the acceleration of climate change via methane leaks, air pollution causing respiratory and cardiovascular diseases, water depletion and contamination, and adverse community impacts including mental health issues and human rights violations against Indigenous peoples. The advisory calls for a moratorium on new fracking, stricter pollution regulations, an end to natural gas tie-ins in buildings by 2023, and support for workers and Indigenous communities transitioning to a clean-energy economy.

The Canadian Association of Physicians for the Environment (CAPE) and other applicants argue that the Canadian Gas Association (CGA) has engaged in greenwashing by marketing natural gas as a clean and affordable energy source. The document asserts that natural gas has a lifecycle climate impact comparable to coal, causes significant indoor and outdoor pollution, and is less affordable than heat pumps, especially as carbon pricing increases. The applicants request a Competition Bureau inquiry, a public retraction of the claims, and a $10 million fine.