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METHANE REDUCTION IN TURBOMACHINERY
1. Can you give an overview of Canadian methane reduction developments?
Reducing methane leakage and venting has been part of Canada's gas pipeline industry's programs since the mid-1980's for fuel savings, operational efficiency, and safety. In 1992, methane monitoring, prevention, and training became popularized as one of the most cost-effective ways to reduce GHG emissions. The Canadian Gas and Canadian Energy Pipeline associations were working in collaboration with government, as well as the US Gas Research Institute, on development and implementation of methane solutions.
Over the next two decades, the Canadian federal and provincial governments established specific regulations to reduce methane emissions from the oil and gas sector by 40-45% below 2012 levels by 2025, as part of the 2018 Pan-Canadian Framework on GHG reductions. These federal rules and the Alberta Directive 060 include some of the world's first specific compressor GHG venting limits.The US and Europe are now developing similar policies.
2. Who calculated the GHG value of methane, where it’s said to be 25 or 80 times more potent than CO2?
The original global warming potential (GWP) of methane was considered to be 21 times CO2 in 1992, and then 25 by year 2000, based on a 100-year timeframe.More recent atmospheric studies have shown some around the 20-year timeframe, with a GWP approaching 80. Whether policy and system design include either value, or an ‘average’ combination of both, will depend on specific regional circumstances.
3. Please tell me about any technologies you are aware of in the following areas, that are being used in the real world:
a) Methane detection
Normal routine inspection of valves, vents, fittings. active leak detection (soap, high flow samplers). Modern onsite and aerial surveys, laser, and infrared optical methods. Detailed inventories of system components to study leakage trends. Focused operations management, records, standards, and training.
b) Methane capture and storage
Compressor station electric blowdown recompression. Dry gas seal vent accumulators, and recompression for onsite uses.
d) Flaring reduction or elimination
Widespread provincial programs and regulations in the upstream gas processing sector to greatly reduce and manage flaring, for both health and climate objectives (Alberta AER Directive 060).
e) Compressor design changes or seal improvements or other ways to capture the methane and ensure more gas reached the destination
Dry gas seals were first introduced in 1988 to replace wet oil seals, and all new centrifugal compressor units are now equipped with DGS systems.Recent trials are being done with OEMs and users for re-injecting primary DGS vent emissions into compressor process suction, the GT fuel gas system, a low-pressure gas application, enclosed flare oxidation, or accumulation for a small electric generator.
f) Methane utilization such as turbines or trailers than can be sent on site to oil and gas facilities for example, to use the captured gas to power the facility
Mobile gas transfer compressors have been used across Canada since 1985. Advances in pipeline replacement, construction and looping added several new hot-tapping and welding methods from 1995. This allows repairs without major blowdowns of pipe sections, line inspections with modified pigging schedules, and operations to vent less gas.
Minimizing station blowdowns with better station and GT unit reliability.This is one reason that our 1992 Canadian gas turbine NOx emission rules were not too aggressive, so that unit combustion reliability would be high to prevent trips, shutdowns, blowdowns, and stops/starts. During gas turbine unit stops, unit isolation valves and a pressurized hold methodology allowed for reduced station blowdowns. New types of GT unit hydraulic and electric starters have sometimes been employed to replace gas expansion starters.
Beginning in 1987, the Canadian transmission pipeline systems began replacing most reciprocating compressor engines due to increasing O&M costs, and higher NOx and methane emissions. Today’s Canadian systems are predominantly centrifugal. Central gas control has improved to optimize smooth system operation to minimize blowdowns. Gas distribution and metering/regulating systems greatly reduced the use of continuous bleed pneumatic controllers that frequently vent small amounts of gas. They have widespread mandated 'call-before-you-dig' programs, predictive or computational leak detection, and replacement of all old cast iron piping and fittings. The oil industry has done some volatile organic compound (VOC) and methane vapour recovery systems on storage tanks.
4. What stands in the way of the industry following this course to greatly reduce methane emissions as above?
Natural gas pipeline and distribution companies in Canada have been proactively managing and reducing fugitive emissions since the mid 1980’s. There have been a few barriers. One of which is recognition that solving GHG issues is important to industry success, especially in upstream oil/gas production and processing. Minimizing methane is a key aspect, along with overall system efficiency and reliability.
When dealing with air pollutants, inclusion of GHG and efficiency issues and incentives is needed. More discussion of health & safety benefits from reduced venting and flaring of VOCs and methane. With continuous research in implementing new system mitigation technologies and operations, operators need an improved understanding of fugitive emissions and impacts. Focused onsite training of operational staff, management, and regulatory staff will help, documenting system solutions, operating guidance, and measuring performance.
Reducing methane emissions can also benefit air quality. Actions that release methane emissions, such as unintentional leaking, and intentional venting and flaring can also emit harmful air toxics, black carbon emissions, and smog-forming VOCs. Therefore, actions to reduce methane emissions can also lead to improved public health protections as a co-benefit.