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Sitting down with the VP of Sales at Siemens Energy Compression to learn more about methane emissions in Turbomachinery
1. How can the industry harness technology to improve the current infrastructure for methane avoidance, recapture, and utilization?
Methane is a potent greenhouse gas (GHG). There is a great deal of interest to minimize or, where possible, avoid methane emissions from the natural gas value chain. It is considered feasible, and one of the best short-term opportunities for the industry to reduce GHG emissions.
From EPA studies, the UN Environmental Program’s Global Methane Assessment, and our own work with customers, we think that 60 - 80% of methane emissions from existing well heads, and gas transmission, storage and distribution infrastructure can be avoided, or captured and utilized at relatively low cost.
Many industry participants have committed to achieving zero methane emissions from oil and gas assets by 2030 as signatories and supporters to the Aiming for Zero Methane Emissions Initiative as part of the OGCI (Oil and Gas Climate Initiative). This is in addition to various other international initiatives such as the Global Methane Pledge, and the World Bank’s Zero Routine Flaring by 2030.
2. Please tell us about any technologies you have in the following areas:
a) Methane detection
Siemens Energy offers a Spontaneous Leak Detection Service (powered by ProFlex), which is a detection solution for gases, liquids and multi-phase fluids transported through pipelines. Our technology can detect leaks ½ inch to 2 inches in size within seconds and provide localization to +/- 20 feet. With accurate detection of small leaks, operators can effectively mitigate the release of methane. With previous technologies, accurate detection of small leaks was very difficult, and often went unnoticed, or resulted in a high number of false positives.
At Siemens Energy, we have also developed significant predictive analytics technologies and digital twins of our turbomachinery. One is the Predictive Emissions Monitoring Software (PEMS) for our Small Gas Turbines portfolio. PEMS for Small Gas Turbines takes a physics-based approach and allows operators to predict regulated emissions accurately. Although methane slip or Unburned Hydrocarbons (UHC) in the exhaust of gas turbines is lower compared to other engines, we’ve received many queries from customers, and are planning to incorporate the prediction of UHC into PEMS for small gas turbines.
b) How can operators improve their compressor seals, capture methane, and ensure more gas reaches the destination?
We design compressors to eliminate or minimize fugitive methane emissions, depending on our customer’s specific plant requirements and operational constraints. In pipeline applications, for example, we offer the RFA series compressor, which has an overhung design and therefore only requires a single dry gas seal. Beam style compressors require two. Therefore, in applications where the RFA is a good fit, fugitive methane emissions from the compressor seals are halved. The RFA compressor also has polytropic efficiency up to 91%, so it reduces energy waste and CO2 emissions associated with the prime mover as well.
Non-contacting dry gas seals (DGS) are superior to wet mechanical seals for minimizing methane leakage and are the standard for new turbo-compressor designs. For brownfield installations, we offer retrofits for replacing wet seals with DGS, which reduce methane emissions about 10-fold, improving operational reliability. The typical primary leakage rates for industry standard DGS can be as high as 4 cfm (0.11 m3/min). The standard dry gas seals that Siemens Energy offers have half the leakage rates achieving 2 cfm (0.06 m3/min) or lower.
We also offer dry gas seals that avoid all leaks, but they require the use of an inert gas such as Nitrogen as a buffer gas for sealing. These dry gas seals are capable of longer pressurized holds, so customers can safely avoid unnecessary compressor depressurization and venting.
In addition, we provide a fugitive methane capture and recompression solution as an option with our compressor trains. The solution we offer has a modular design. It can capture and recompress the small amount of gas leaking from the compressor DGS, and the larger volume of gas between the unit isolation valves that must be removed when the compressor needs to be depressurized for maintenance or other non-emergency events.The compressed gas is stored in a pressure-rated vessel and re-injected into the suction header of the process when operations resume. If the prime mover can utilize it, the captured methane may also be routed into the fuel gas supply. The recompression solution can be scaled easily and helps customers attain near-zero methane emissions by addressing both dry gas seal leakage and process venting.
c) Methane storage
Underground gas storage is an essential part of the gas transmission and distribution network for managing demand fluctuations. Siemens Energy provides electric motor, gas turbine and dual drive compression trains for the storage and withdrawal of natural gas. These trains are typically sized between 7,000 to 55,000 hp. We can provide these trains with multiple compressor bodies operating in series or parallel, which extends the operating range. We can also provide a compact single body compressor with a back-to-back configuration that incorporates both the injection and withdrawal stages within a single casing. As mentioned earlier, with our DGS and recompression options, all our turbomachinery trains can be designed to meet near-zero methane emissions.
d) Flaring reduction or elimination
For flaring reduction, we take the first steps at the design stage working together with our customers, as unplanned compressor failures are a root cause of non-routine flaring incidents. From our products portfolio, we offer compressors used in flare gas recovery systems. In service,
we work with customers to plan preventative maintenance of compressors to minimize gas handling system shutdowns.
We also offer engineering services like process analysis, dynamic simulation, and quantitative risk analysis through process safety consulting to eliminate routine flaring and minimize unplanned flaring. For existing facilities like refineries, this has resulted in flare minimization and/or optimization, purge gas optimization of flare systems, and flare gas recovery.
We do not offer flaring elimination devices from the Siemens Energy Portfolio. For customers who want to integrate solutions such as enclosed burners or flameless thermal oxidizers along with our offerings, we can perform systems integration for the plant if requested by the customer.
e) 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.
Siemens Energy’s gas turbine driven mobile power generation units can utilize captured gas to produce electricity at site to prevent gas flaring. These are SGT-A05 and SGT-300 based single trailer power stations generating 5.8 MWe or 7.9 MWe, designed for fast mobilization between locations, and quick set up to produce electricity within 2 to 3 few hours of arriving at site.
We also offer the SGT-50, a 1.8 MWe turbine. These turbines have high fuel flexibility to help eliminate flares and provide electricity, often in remote, off-grid locations.
In LNG applications, Siemens Energy offers Boil-off Gas (BOG) compressors, which can be utilized to reliquefy the BOG or reinject non-recoverable BOG back into the gas network at regasification terminals. We also perform LNG process optimization in partnership with the engineering contractor. The compression trains are designed to minimize flares, for example, in the event of depressurizing the main refrigerant system.
3. What stands in the way of the industry following this course to significantly reduce methane emissions?
In the past, methane emissions were an economic externality with little incentives or penalties to facilitate the investments needed to reduce them. There were also regulatory limitations – for example, ones that limited a gas producer or transmission system operator from also producing electricity and feeding into the grid.
Times are changing. In the US, as part of the Inflation Reduction Act (IRA), methane emissions charges have been adopted. This is the first time the federal government has directly imposed a charge, fee, or tax on GHG emissions.
However, even before the IRA became law, there was a significant rise in demand for fugitive emission solutions from our customers, and concerted efforts from the industry to address methane emissions.
4. Are there incentives towards replacing natural gas with hydrogen, renewable natural gas, and other green alternatives? How does this compare to efforts in making current infrastructure more efficient for methane reduction? What can be done?
One method is replacing natural gas with Hydrogen, RNG, and others. Hydrogen has a unique value proposition as an energy vector that can store renewable energy and address decarbonization in multiple sectors that require heat and power through sector coupling. But it requires a large demand shift as well as significant changes in the energy infrastructure to generate, transport, and utilize Hydrogen at the industrial scale at which natural gas is used now. An ecosystem disruption at that scale requires significant funding and incentives, and there is a lot of debate around it
For more on methane, please read the Cover Story of the November/December 2022 issue here: Turbomachinery Magazine