Gas turbines have an upstream axial air compressor coupled to a downstream turbine section and a combustion chamber in between. The fresh air that flows through the air compressor increases pressure. Energy is then added by spraying fuel into the air and igniting it so that the combustion generates a high-temperature, high-pressure gas flow. This high-energy gas enters the turbine section, where it expands down to the exhaust pressure, producing a shaft work output. The turbine shaft work drives the air compressor and driver, such as a gas compressor, large pump, electric generator, etc. Energy not used for the shaft work comes out in the exhaust gas—a high-temperature gas with a relatively high velocity. In many gas turbines, heat recovery steam generators (HRSGs) are installed to recover some heat from the exhaust.

Higher combustion temperatures can allow for greater efficiencies; however, temperatures are limited by the ability of the turbine’s materials to withstand high temperatures and stresses. To combat this, many turbines feature complex blade air-cooling systems.

The smaller the gas turbine, the higher the rotating speed of the shaft(s) required to maintain the tip speed. The blade-tip speed determines the maximum pressure ratios obtained by the turbine and air compressor. This, in turn, limits the maximum power and efficiency obtained by the gas turbine. For example, medium-sized gas turbines (5 - 15 MW range) operate around 10,000 rpm, while small micro-turbines (60 - 100 kW) spin as fast as 300,000 rpm.

Internal air systems play a vital role in modern gas turbines and impact efficiency, performance, and reliability. They provide air for blade cooling and other purposes. Approximately 8 - 16% of the air provided by the air compressor is used for cooling, sealing, and other applications.

The flow in axial turbines is inherently unsteady due to the relative motion between rotor and stator blade rows. In a turbine, the incoming wakes are chopped by the rotor blades and then diffused and deformed as they pass through the non-uniform pressure field in the rotor passage. These unsteady phenomena affect the performance of airfoils and generate noise and vibration.

The loss in efficiency due to different internal leakages or tip clearance flows accounts for an important part of the overall losses in gas turbines. Different clearance gaps, between 0.5 - 1.5 mm, are used in different sections. Sometimes higher clearance gaps (2 mm or more) might be required. The losses caused by leakage flow over blades can be minimized by reducing the leakage. A tip shroud reduces leakage and improves blade performance.

A case study using a 15-MW twin-shaft industrial gas turbine for a gas compressor drive application helps demonstrate these principles. The turbine contains a compact gas generator and a three-stage power turbine, incorporating the latest aerodynamic and combustion technologies. It has a simple-cycle efficiency of 38% with waste heat recovery for steam generation. The mass and temperature of the exhaust gas are approximately 41 kg/s and 535° C, respectively. The exhaust gas is fed into the HRSG.

The axial air compressor of the gas turbine has 12 stages with a total pressure ratio of 18.5. (Pressure ratio is estimated at 1.28 per stage.) The air compressor has five-stage variable guide vanes to ensure surge-free flexible performance in a wide range of operations. The speed of the air compressor and high-pressure turbine is around 14,500 rpm. The turbine uses a sophisticated shrouded concept. The nominal speed of the output shaft turbine is 9,600 rpm. The power turbine is directly coupled to the gas compressor. The speed of the power turbine varies between 5,600 rpm and 10,000 rpm (58% - 104% of the nominal speed). This variable speed range can offer excellent operational flexibility to the compressor driver and the entire turbomachinery train. 

The temperature of ambient air could affect turbine-produced power and, consequently, compressor performance. Approximately 100 kW (0.7%) of produced power is reduced with each 1° C rise in the ambient temperature. However, since the margin for the power rating and operational flexibility are provided, this is of no concern. More than a 17% margin was considered for the driver’s size. Combined with the flexibility of a gas turbine and wide variable speed range, the gas turbine/compressor train can handle all operating scenarios in all possible ambient temperatures.

Amin Almasi is a Chartered Professional Engineer in Australia and the U.K. (M.Sc. and B.Sc. in mechanical engineering). He is a senior consultant specializing in rotating equipment, condition monitoring, and reliability.

Articles

Gas turbines, including the air compressor and combustion chamber, face challenges such as high temperatures and the need for blade-cooling systems.

Turbo Tips: Practical Notes & Useful Guidelines on Modern Gas Turbines

When I started to work in college with computational fluid dynamics (CFD) software (in the late 80s), we would write our codes ourselves (usually in FORTRAN) and were really happy when we could run a problem without crashing the code. User interfaces were unknown, at least to us. Two-dimensional runs were fairly standard, but Navier Stokes was still difficult, especially for separated flows, and the appropriate turbulence models were sought. Transient Analysis just started. Turbomachinery secondary flows were a hot topic. Today, most of us in industrial settings are used to well-tested commercial codes with convenient user interfaces, the capability to automatically generate appropriate grids and helpful post-processing tools. So, why do we still need aero engineers?

Here’s why: Codes do not understand flow problems; they are simply tools that produce numbers—albeit with the capability to produce copious amounts of colorful graphs. And CFD results don’t always match test data! That doesn’t mean they are entirely wrong, but they may miss flow features, create artifacts, or miss bulk results, such as flow, head, and efficiency.

It is also a misunderstanding to think that purchasing one of these tools creates aero components “out of the box.” Practically all industrial users have internal guidelines and procedures that allow them to bring the experience from many designs into the discussion. The starting port is always an existing design, with known performance data, and the use of one-dimensional tools that allow it to reflect the user’s experience.

We have to acknowledge that CFD employs numerical methods that try to approximate the real world. The Navier Stokes equations themselves are accurate, but they cannot be solved analytically (at least not for the flow problems involving turbomachinery), so all codes attempt to use mathematical numerical models for approximation. The approximation becomes difficult for laminar-turbulent transition, flow separation, fluctuating flow, shock structures, or flows that are not adiabatic. Usually, it’s easier to predict the flow at the well-behaved design point but not near in-surge or choke. The gases we compress show real gas behavior, while numerical codes use ideal gases, tabulated data, or if equations of state are used, create a large computational cost.

The geometry for the problems we’re solving is not exactly the geometry of our compressors. We apply a grid that more or less matches the geometry but only at discrete points. Grids can be refined, but ultimately, computational times rounding errors and the fact that there are manufacturing tolerances or the difference between a hot part and a cold part. Clearances are often dependent on pressures, temperatures, and rotational speed.

The approximation also often involves excluding or simplifying other real-world influences, such as heat transfer, real gas behavior, fluid-solid interaction, or the description of surface roughness.

In addition, we are often not able to completely define our physical space: Geometry is subject to manufacturing tolerances, and inlet and outlet conditions often have to be averaged. A more precise description would require a definition far upstream and downstream, where they may be reasonably uniform. Fillets, brazed, or welded parts are typically simplified or omitted. Surface roughness is assumed to be uniform in all directions, which, in reality, depending on manufacturing methods, is usually not the case.

So, why does it work at all? Besides the very sophisticated methods available, we improve our codes by using actual test data to calibrate our methods. And we have experts who interpret the data and, for example, identify whether flow structures in those beautiful color graphs actually make sense. We know what the results for similar problems were. We also just look for the difference in results for a known geometry and the new geometry.

So, CFD is a great tool, but it takes experienced engineers to get appropriately accurate results. The combination has allowed us to precisely predict machine performance.

Klaus Brun is the Director of R&D at Elliott Group. He is also the past Chair of the Board of Directors of the ASME International Gas Turbine Institute and the IGTI Oil & Gas applications committee. 

Rainer Kurz is a recent retiree as Manager of Gas Compressor Engineering at Solar Turbines Inc. in San Diego, CA. He is an ASME Fellow and has published over 200 articles and papers in the turbomachinery field. 

CFD is a great tool, but it takes experienced engineers to get accurate results.

Myth: If You Have CFD, You Don't Need Engineers

For many of us in the large rotating equipment market, gas turbines are our main area of focus, and for good reason. Gas turbines are manufactured using leading-edge metallurgy, coatings, and aero-centric geometries to efficiently deliver rotational power at very high temperatures and pressures. But many times, the receiving end of this rotational power is equally impressive compressors, deployed for a variety of critical industrial processes.

The centrifugal compressors market is served by over 20 OEMs globally, producing over 2,000 units per year. In 2022, the value of this market (not including related aftermarket repairs) was approximately US$3.4 billion.

This market overview focuses on units rated above 1 MW and does not address positive displacement, diaphragm, or axial compressors.

There are two types of centrifugal gas compressors: in-line (also called beam-type or between-bearings type) and integrally geared. In-line compressors have one or more impellers in a single casing, generally with the impellers located between two radial bearings on a single shaft. An exception to this rule is the single-stage gas pipeline compressor with an overhung impeller (both radial bearings on the same side of the impeller) and axial inlet. All impellers within an in-line compressor casing rotate at the same speed.

In contrast, integrally geared compressors have two or more impellers, each located in its own casing with each casing mounted on a single gearbox with a single bull gear driving each impeller through a pinion gear. This arrangement allows each impeller to rotate at a different speed. The required total pressure ratio is achieved by having the gas move through two or more single-stage compressors in series. 

Incorporates a single impeller on an overhung shaft with the gas inlet oriented directly into the impeller eye, with the gas discharging radially. Due to reduced gas turning this design is more efficient than beam-style compressors and can achieve efficiencies above 90%.

Incorporates one or more impellers mounted on a single shaft between two bearings. The casing split is vertical, which allows for better sealing at higher pressures, up to 1,000 bar.

A type of radially split-barrel compressor with one to four impellers mounted between two bearings. Generally used for multistage pipeline boosting applications.

A design featuring a high-speed variable frequency motor driving one or more compressor impellers in a hermetically sealed casing that uses magnetic bearings. Benefits include reduced weight and footprint compared to traditional designs and no possibility of oil or gas leaking into the environment.

TYPICAL APPLICATIONS FOR CENTRIFUGAL COMPRESSORS

Applications served by centrifugal compressors (as segmented in this report) fall into three oil and gas sectors and one industrial sector:

These compressor applications are seen in oil and gas production operations, both onshore and offshore. They include initial processing operations done close to the point of extraction, including the dehydration and separation of liquids. Also included in upstream activity are compressors used in LNG liquefaction plants. (Note, some view LNG liquefaction as a downstream activity, but for the sake of this article, we are including them in the upstream segment.)

There are thousands of compressors used in gas transportation via pipeline as well as compressors used in underground gas storage applications. This segment also includes fuel gas compressors for gas-fueled power plants.

Compressors may also be used in refining and petrochemical production processes. These applications also include compression needs for fertilizer production and its precursors (ammonia, urea, nitric acid, etc.).

Compressors used in other industrial applications, including air separation, CO

, compressed air energy storage, and plant/process air compressors over 10,000 m

The more than 20 OEMs that serve the centrifugal compressor market manufacture multiple configurations of these compressors including: 

While many of the OEMs in this market primarily serve a regional customer base, for example, those in Russia, China, and India, other OEMs serve the market on a global basis. Many of the globally diverse OEMs have broad product lines, like those mentioned above, while others have a narrower focus on specific product types.

A detailed review of these OEMs, the market segments they serve, and the product types they offer are included in Dora Partners & Company's annual 

. The largest OEMs serving this market include Baker Hughes, Siemens, Elliott Group, MAN Energy Solutions, Solar Turbines, Mitsubishi, Atlas Copco, and Shenyang Blower Works.

A detailed analysis of the market suggests that the annual OEM revenue for centrifugal compressors is more than US$3.4 billion per year. In 2022, approximately 2,300 units were ordered from the OEMs included in our study.

From a unit quantity perspective, the industrial segment is the largest, but most of these units are smaller and less expensive than the compressors used in the other segments. Units used in upstream applications are generally the most expensive, followed by those used in the midstream and downstream segments. From a total revenue perspective, downstream is the largest application segment.

There are significant differences in driver types across the application segments, with gas turbines frequently being used in the midstream and upstream segments, and steam turbines often being used in the downstream segment. Electric motors are used in all segments with almost all units in the industrial segment using this driver type.

From a geographic perspective, the largest destination region is Asia-Pacific, followed by the Americas. 

Unlike many pieces of rotating machinery, such as gas turbines, reciprocating engines, and reciprocating compressors, centrifugal compressors have very few, if any, parts that are life- or wear-limited and require replacement on a scheduled basis. A well-designed and maintained centrifugal compressor can run for decades with very little corrective maintenance. As a result, most aftermarket revenue associated with centrifugal compressors comes from both parts and services that are required when something fails or revamps the equipment to modernize it or change its capabilities.

Dora Partners has estimated that 2023 will result in new unit orders of more than US$3.6 billion, with a relatively consistent growth forecast over the next 10 years. Overall, the market is expected to grow most rapidly in the Asia-Pacific region and the industrial market segment.

Upcoming market trends include growth in LNG production, carbon capture and storage, subsea compression, and hydrogen/ammonia applications, as worldwide decarbonization initiatives advance across the globe.

Note: Dora Partners & Company’s detailed report provides a much deeper evaluation of each market segment, product strengths for each of the main OEMs, and a 10-year forecast segmented by upstream, midstream, downstream, and industrial sectors. The report includes regional and OEM market share information, application, and trend observations. In addition, OEM profiles are provided detailing product and market strengths for the top nine compressor OEMs.

About the Authors: Anthony Brough is the Principal Consultant at Dora Partners & Company, and Tony Ruegger is the Senior Consultant at Dora Partners & Company.

A high-level overview of the centrifugal compressors market.

Centrifugal Compressors: The 'Business End' of Many Critical Industries

Turbomachinery International spoke with James Montgomery, Chief Design Engineer, Novel Nuclear, and John Mason, Systems Design and Integration Technical Specialist of Rolls-Royce, to take a deep dive into micro-reactors—compact, portable rectors that produce thermal energy for use as heat or electrical power—and give readers an inside look at the company’s innovations, challenges, and design considerations for its micro-reactor and nuclear technology in terrestrial and lunar applications.

Q: What is a micro-reactor, and how does it differ from a small modular reactor (SMR)?

Micro-reactors are very small scale, in the range of 1 MWe - 10 MWe compared to a typical grid-supplying power plant in the gigawatt range and compared to the new generation of SMRs in the 1/2 GW range—micro-reactors are much smaller than that. We have two potential applications for the micro-technology we’re working on in the United Kingdom: The first one is the terrestrial variant for supplying power to different applications on Earth; and the second is the space micro-reactor that has potential applications for the lunar base as part of the space program and, in the longer term, for power and propulsion applications on satellite and deep-space missions.

Q: What goes into designing a micro-reactor, and how are they customized?

At Rolls-Royce, we have a great pedigree in designing complex systems like this, so the first step in that process is to work with potential end users to understand the user requirements and use cases where we can get value from the technology. Then we’ll work through the process of preliminary design and size of the plant, understanding what the technology can do and where the technology gaps might be. That launches us into a technology program to acquire the technologies we need.

The micro-reactor plant is interesting because it’s genuinely a new product for us at Rolls-Royce, as with the rest of the industry. We’ve pieced together some of our pedigree from the nuclear side and the turbomachinery side that we have developed over many years for aerospace and industrial applications.

Across the Rolls-Royce group, we have experience in several different industries and capabilities. We have large civil engines that power airliners. We are engaged in combat aircraft and military transports, and a large element of our business looks at turbomachinery for turbo-compressors— centrifugal machines, turbochargers for yachts, large mining and industrial applications, etc. We can pull from all these capabilities and experiences and apply them to new industries and new technologies.

Q: What advantages do micro-reactors offer, and in what environments/locations do they work best?

In terms of the terrestrial variant of the micro-reactor, imagine a small-scale power plant in a shipping container-sized envelope that can be deployed to a remote location where access to fossil fuels is strained—that’s our vision for the micro-reactor. The great thing about a micro-reactor is, depending on its size and detailed design, it can be fueled for five to 10 years of operation, which means if you are a remote-unit or -running community or a remote military installation, it makes you resilient to the risks surrounding the fossil-fuel supply chain. Also, as a net-zero technology, it eliminates reliance on fossil fuels for communities.

The space micro-reactor is a completely different application. Many different missions are looking to use these kinds of power plants: In particular, NASA’s Fission Surface Power Project, as part of the Artemis Mission, was looking to develop a power plant for use on the lunar base. There, it’s about operating in areas where solar power is limited, particularly around the south part of the moon where we’re looking to explore, so having a nuclear source that can run reliably day and night is a game changer for moon-based operations.

In the long term, nuclear can be used as a source of power for propulsion and space missions, particularly for deeper space missions where solar power become weaker.

The Artemis Mission aims to build an infrastructure to Mars, and this technology could extend to those kinds of missions' demands. 

From a power-conversion viewpoint on our terrestrial applications, we can utilize our knowledge and expertise gained from our naval applications. These are designed and packaged to fit in a confined space envelope, similar to an ISO container, which is needed to transport the system. With an open Brayton Cycle, we are simply replacing the combustion chamber, where normally fuel is burned, with a heat exchanger to the reactor.

Where things get very interesting from a power-conversion point of view is with space applications. We still use Brayton cycles, but operation in space requires a closed cycle—we can’t continue to take air in the front and push it out the back, so we take the exhaust gas out of the back of the turbine and recondition that flow back to where we started before it re-enters the compressor. So, we’re looking at the most efficient way to do that with recuperation intercooling and various other things.

This presents challenges, but it also gives us additional design levers—because it’s a closed cycle, we can change the working fluid, so, for example, we don’t have to use air as we do with the open cycles for civil aircraft. We can also change the start conditions—optimize it by changing the pressures and temperatures at the beginning of the cycle. Depending on the requirements of the system, we can pick and choose where the design point of the turbomachinery sits.

Q: Can you talk about the use of nuclear energy and its role in a sustainable future?

One of the key technologies that enable micro-reactors is the development of coated-particle nuclear fuel, TRistructural ISOtropic (TRISO) fuel: a kernel of uranium fuel coated in different layers of carbon-like material that has different functionalities for protecting the fuel from overheating and for containing fission products within that small particle in a resilient way. This means that we can potentially simplify the design of the rest of the plant and hence enable much smaller plants more than we’ve historically been able to achieve safely. There are other aspects of the plant as well that are being looked at within the industry to enable a passively safe nuclear design—by that we mean it’s effectively fail-safe from the way it responds to different failure modes.

In terms of power conversion, the key impact of the micro-reactor and heat transfer from the reactor into our cycle is the peak temperature that goes with the fuels and technologies of that reactor. They are much lower than the operating temperatures of civil airliners, and the technology in the power conversion and Brayton Cycle is not being pushed by the cycle’s temperature levels. It gives us other headaches in terms of trying to design the cycle for high efficiency to minimize the size of the overall system, the reactor core, and the amount of fuel needed for the lifetime of the application.

One of the interesting applications for terrestrial micro-reactors is the need to safely transport and operate it at a remote site. As part of our concept, we'll have a containerized solution and ship it to the site using conventional transport. That itself poses design challenges to the way that you transport the radioactive and spent fuel when the site has been decommissioned. There's a lot of work in the industry looking at that.

It gives a flexible solution to the customer because you could have multiple nuclear reactor modules to create nuclear heat combined with multiple modules of John's power-conversion technology to scale the plant to different applications, which could also include the supply of heat for chemical and industrial processes.

The primary fluid used in the Brayton Cycle provides the coolant for the reactor as well. So, there are a lot of scenarios that we don't normally face when designing the system that we need to incorporate additional functionalities for and make sure there's the right redundancy to provide the safety case for these reactors. There are cases that in a normal application—for example, a civil airliner in which you would reduce the power or shut the engine down and rely on other engines to complete the flight safely—that may not work for the nuclear side because it needs to flow continuously to cool the reactor, which will have a big impact on how the system is designed.

Another factor is the environment in which these systems will operate. There are opportunities to use these in various conditions, from cold, Arctic conditions to hot, desert-like conditions such as in mining communities, and these intake conditions for terrestrial systems have a very big impact on their performance. We have to account for these factors when designing what the system and turbomachinery look like to ensure good performance and efficiency throughout each case.

Ambient temperature is a huge factor for space conditions in lunar applications—the day-to-night temperature varies between 100° Kelvin - 385° Kelvin, that’s -300° F - +230° F. That will have a huge impact on our ability to reject heat from the system through the radiators to return the fluid to its starting condition before it goes back through the compressor. From a systems-level point of view, there are many things that we need to think about which do we design for? Peak efficiency of power conversion, which minimizes the size of the reactor plant needed to launch and the amount of fuel you need to take with you? Or do we design for the minimum size of radiators that have to be packaged into the rocket to get the reactors there in the first place? There are many things we have to think about that we don’t normally consider.

This is a really interesting product for us because it brings together our aerospace heritage and our knowledge of how to build lightweight aerospace systems with our nuclear heritage. But this is our first nuclear application where weight has been a real concern, both from a transport point of view for the terrestrial reactor and for the spacecraft where the payload mass and volume are key constraints on the system. So, that's giving us a real challenge and driving us to some interesting packaging solutions for the space reactor in particular.

TurboTime Podcast: Micro-Reactors with Rolls-Royce.

Rolls-Royce is using its nuclear and turbomachinery heritage to create micro-reactors for space and terrestrial applications.

Q&A: Micro-Reactors with Rolls-Royce

The road to decarbonization is a diverse mix of solutions that includes advanced turbomachines, lower-carbon fuels, renewables, regulatory support, and a lot of collaboration.

As the industry moves toward a sustainable energy ecosystem, organizations are looking at it from all angles, including infrastructure, supply, cost, technology, and science.

Lower-carbon fuels such as hydrogen and ammonia present both opportunities and obstacles for power generation.

Along the Gulf Coast spans roughly 1,600 miles of a hydrogen-ready pipeline—it is home to the largest consumption and production of hydrogen in the United States. So, if you’re down south, infrastructure is not an issue.

But “what we’re talking about is a future where the production and use of hydrogen are more decentralized across the United States,” said Dr. Jeffrey Goldmeer, Global Hydrogen Value Chain Leader at GE Vernova. “That might imply a lack of infrastructure in other places, but those places today don’t have large-scale hydrogen production or consumption. So, it’s not a matter of infrastructure—we just haven’t developed the hydrogen ecosystem in those locations.”

That said, many companies are producing and using hydrogen locally for applications such as fuel cells and forklifts, but one difference between these uses and power generation is transportation. Hydrogen, in these cases, is being transported by trucks because these industries don’t have the volume that requires a pipeline.

Beyond infrastructure lies the issue of technology. But as OEMs like GE Vernova build out hydrogen-ready machines, supply and cost are the two major barriers that power generation encounters, not technology.

“This is not a technology gap,” Goldmeer said. “All the OEMs are on a path to develop advanced combustion systems to burn 100% hydrogen. Many gas turbines today can already burn 100% hydrogen using diffusion flame combustion systems. The real challenge to operating at 100% hydrogen on a gas turbine is scale: scale of supply. Gas turbines can consume a large amount of fuel very quickly. We have the infrastructure to deliver that fuel for natural gas systems; we don’t have that infrastructure to deliver hydrogen as a power-generation fuel because we’ve not had to.”

Thus, creating the second barrier: cost. Whichever way hydrogen is produced, it comes with a price premium compared to natural gas.

“Cost is a barrier. The way we dispatch gas turbines today is really a function of the lowest cost of electricity, so you need the lowest cost fuel,” Goldmeer said. “We don’t have a carbon tax or something else to level the cost [of hydrogen], so you choose the lower-cost fuel. [It then becomes] a matter of how we set up the electricity markets, how we think about infrastructure, and how we think about fuel cost: Do we prioritize lower-carbon fuels and incentivize them with subsidies?”

As Goldmeer mentioned, legacy diffusion flame combustion systems can not only support 100% hydrogen, but they are extremely reliable; however, hydrogen’s high flame temperatures, along with other behaviors, have made it a challenge for dry low NOx/emissions (DLN/DLE) combustor systems.

To combat this, “GE Vernova and most OEMs are investing in next generation combustion systems to create DLN combustors that can burn 100% hydrogen,” Goldmeer said. “But again, we’re looking at this with a new focus: How do I use 100% hydrogen in a combustor that has specific roles that we have to maintain around efficiency and NOx? But we have decades of experience with DLN systems, and we’ve learned more about how hydrogen behaves, so now we’re taking all these experiences from the last 30 - 40 years and bringing them to bear with new technologies and design tools and developing next-generation combustors."

Ammonia is another lower-carbon fuel that has an established global network of infrastructure (There’s already a global community and trade in ammonia, and the United States has 3,000 miles of ammonia pipeline.), and it has economic advantages over hydrogen. Contrary to hydrogen, ammonia condenses at -33° C, so it requires significantly less energy to move. 

Yes, there are toxicity issues, but as Goldmeer points out, the industry already safely moves 15 - 20 million tons of ammonia each year, so there are solutions to this hurdle. And although ammonia will require a new combustion system to resolve NOx production, the industry is already in the process of engineering new systems.

“I trust that engineers in the industry will solve these problems, and now it’s just a matter of weighing under what situations do the economic benefits make sense for the use of ammonia versus hydrogen or other fuels,” Goldmeer said.

As stated, ammonia also creates combustion challenges. Legacy diffusion flame systems run near stoichiometric conditions, whereas DLN systems run lean and reduce NOx emissions with natural gas but cause emission issues with ammonia.

“The fundamental question then is what combustion system resolves the fundamental chemistry issue, because this is a chemistry issue,” Goldmeer said. “The science itself behind these systems isn’t new but the application is.” 

Today, GE Vernova’s technology either runs at or near stoichiometric—i.e., fuel and air in perfect chemical balance—or on the lean side, but the rich side of the stoichiometric dome—fuel-rich and oxygen lean—provides less air for the nitrogen to turn into NOx when using ammonia. To this point, GE Vernova and IHI are developing a two-stage combustion system with a rich dome to resolve the ammonia-NOx problem—building upon IHI’s development of a 2-MW gas turbine using 100% liquid ammonia and GE Vernova’s expertise in engineering and manufacturing of gas turbine combustion systems and balance of plant systems.

“The solution is we don’t take today’s combustion systems and repackage them; we go back to the fundamental science of combustion and look for the answer there and it gives us the answer,” Goldmeer said. “We’ll be focused on the technological development and technical deliverables, aiming for the validation of the combustion technology in the next two years and a potential commercially available product by 2030.”

Looking toward 2030, Goldmeer said building out both solar and wind is paramount to a decarbonized future. In fact, GE Vernova signed up to build 674 onshore wind turbines for the SunZia Wind Project, set to go online in 2026 and projected to be the largest wind project in the Western Hemisphere.

There's a lot of momentum with wind and solar.

As many regulations are still in flux and need to shake out, the Department of Energy’s plan for seven hydrogen hubs across the United States will help build out the infrastructure needed to support hydrogen and ultimately drive costs down.

“These hubs are all about supply and demand—how to make and use hydrogen,” Goldmeer said. “If they are successful, in 10 -15 years you’re going to see the large-scale production of hydrogen not just in the Gulf Coast but lower-carbon intensity hydrogen in different parts of the United States.”

Gas turbines running on natural gas are also part of a decarbonized future, as they provide reliable, dispatchable power. “I’m hoping over the next 5 - 15 years we start to see some of those units available to operate on hydrogen, but again, it’s a hydrogen supply issue, not a gas-turbine technology issue,” Goldmeer said.

Ensuring that gas turbines are 100% hydrogen-capable when the fuel supply becomes available is paramount for GE Vernova and the industry so that gas turbines are not a barrier to decarbonizing the power generation sector.

In the meantime, hydrogen can be used by other industries to reduce their carbon emissions. “Maybe hydrogen doesn’t go into power, maybe hydrogen goes into mobility applications such as fuel-cell vehicles. Hydrogen isn’t the answer for just gas turbines. There are so many other places where it makes sense to use it. I’d like to see it here on the Gulf Coast as we start producing more and more hydrogen that’s at a lower carbon intensity to put into fertilizer production. Let’s take a real bite out of carbon intensity and some of these industries that use hydrogen today.”

In the end, it's about pathways to decarbonization.

Jeffrey Goldmeer of GE Vernova discusses the steps toward a decarbonized energy economy—from supply and cost to turbomachines and lower-carbon fuels.

Pathways to Decarbonization with GE Vernova

The 24th Baker Hughes Annual Meeting (AM) took place in late January 2024 in Florence, Italy. More than 2,000 customers attended, well up on the previous year’s total of 1,700. The show highlighted a surge in turbomachinery orders and the unveiling of decarbonization, carbon capture, and hydrogen-related advances.

Lorenzo Simonelli, Chairman and CEO of Baker Hughes, opened the event by announcing the overarching theme of energizing change. He laid out his three hard truths:

The need to scale current technologies to reduce emissions and meet net-zero targets.

There is no world without hydrocarbons, at least for the next several decades.

The industry needs to continue to advocate for the displacement of coal with natural gas.

Simonelli urged attendees to strive for higher efficiency from current technologies. He cited the International Energy Agency (IEA): Technology efficiency improves by about 2% per year. If the industry can achieve a 4% gain per year, most emissions targets will be met despite there being a large increase in energy output.

“There is no path to net zero without innovation and collaboration,” said Simonelli. “We must achieve growth that meets our needs without compromising the ability of the future generation to meet theirs.”

Baker Hughes’ annual orders for 2023 for its Industrial & Energy Technology (IET) segment (comprised of turbomachinery and other energy production, digital, and monitoring solutions) were 12% higher than last year’s record level.

“We booked the previously announced 9.6.metric tons per annum (mtpa) Ruwais LNG project in the United Arab Emirates,” said Simonelli. This is for two electric liquefaction systems and is one of the first all-electric LNG projects in the Middle East.

Baker Hughes was awarded a contract by SBM Offshore to provide turbogenerators, turbocompressors, electric motor-driven compressors, and commissioning and spare parts for a floating production, storage, and offloading vessel. Other orders included a contract for one electric motor-driven sour gas booster compression package to support the development of offshore natural gas fields in the Middle East. Further quarterly business included service contract commitments worth more than $1 billion, primarily driven by LNG and offshore projects in North America and the Middle East, as well as upgrade orders, particularly in Europe for refinery and gas network applications to boost efficiency and lower emissions. The company’s Cordant digital solutions also reached a multi-year deal with Shell to centralize the Baker Hughes System 1 asset condition and performance monitoring systems across 33 sites. There was a similar deal for System 1 with India’s Oil and Natural Gas Corp. Ltd., this time for 12 offshore platforms.

This does not include what is being characterized as the biggest turbomachinery order in Saudi Aramco’s history: The formal announcement won’t be out until late spring, but a few details have emerged: an order for 17 gas compression trains with more to come.

Khalid bin Khalifa Al Thani, CEO of QatarEnergy LNG, laid out his plans for natural gas expansion: the development of 16 new offshore sites for gas production and six new mega LNG trains with a capacity of 8 mtpa each. This will take QatarEnergy LNG to 126 mtpa by 2030. In tandem, the company is developing carbon-capture and storage (CCS) technology.

“We are advancing the energy transition, and LNG is the solution,” said Al Thani. “Gas will be needed for baseload energy well beyond 2050.”

A new Baker Hughes hydrogen testing facility in Florence supports the deployment of hydrogen-ready technologies. It is being used to validate its NovaLT industrial turbines to run up to 100% hydrogen. Its test bench allows full-load testing with fuel flexibility and features a 300-bar pressure and 2,450 kg of hydrogen storage capacity. For example, Baker Hughes recently completed manufacturing and testing its NovaLT16 hydrogen turbines for Air Products’ Net-Zero Hydrogen Energy Complex in Edmonton, Canada. These machines underwent full-load testing. 

In addition, the company reported the delivery of the first two trains of hydrogen compression solutions for the NEOM project in Saudi Arabia. This is said to be the largest green hydrogen project in the world. It is a joint venture of ACWA Power, Air Products, and NEOM. To further support the delivery of projects in the country, including NEOM, Baker Hughes is expanding its manufacturing site in Modon, Saudi Arabia, where it plans to do localized testing and packaging.

President Biden's January 2024 announcement of a pause on all new LNG permitting approvals in the United States caused controversy at the AM. 

“During this period, we will take a hard look at the impacts of LNG exports on energy costs, America’s energy security, and our environment,” said President Biden.

Several AM speakers and panelists took issue with the announcement. 

“We are disappointed with today’s announcement by the Administration to disrupt the growth of U.S. LNG, which has been one of the most transformative energy success stories of this century,” said Simonelli. “We strongly oppose this moratorium and call on the Administration to approve pending export applications with no further delays.”

Mike Sommers, President and CEO of the American Petroleum Institute, called it the worst energy decision made so far by the current administration.

“It is a win for Russia, and a loss for U.S. allies, American jobs, and global climate goals,” said Sommers. “European and other allies are begging for U.S. LNG. This undermines world security at a time when energy demands are rising.”

Jack Fusco, President and CEO of the top U.S. exporter of LNG, Cheniere Energy, offered a rebuttal about price rises and environmental impacts. Carbon dioxide levels in the United States reached an all-time high in 2007 and are down 15% since then due to coal-to-gas switching and despite rising energy usage and massive exports of LNG.

"The price of natural gas is the same as it was in 2007 despite the huge increase in LNG exports," said Fusco. 

Brad Crabtree, Assistant Secretary for the Department of Energy’s (DOE) Office of Fossil Energy and Carbon Management, found himself on the hot seat during an AM panel on government policy. It turned into a debate about President Biden’s announcement. Crabtree assured attendees that the administration would not allow any slowdown of urgently needed supplies to allies in Europe. He noted that the United States currently exports 14 billion cubic feet of LNG per day.

“Up to 48 billion cubic feet per day of LNG projects have already been authorized,” said Crabtree. “The pause does not include any of that. During the pause, the administration will conduct a robust analysis of the market and domestic, international, and environmental needs in order to make the right decision.”

However, several meaty projects have been left in limbo. These include Commonwealth LNG’s 9.3 million mtpa LNG export facility in Cameron, Louisiana; Sempra’s LNG trains 3 and 4 in Port Arthur, Texas (13.5 mtpa); Energy Transfer’s Lake Charles LNG facility in Louisiana; Magnolia LNG (developed by Glenfarne Group – 8.8 mtpa) in Louisiana; Venture Global LNG’s 20 mtpa expansion of its existing Calcasieu Pass project in Louisiana; and Cheniere Energy’s Trains 8 and 9 at its Midscale LNG project.

Carbon capture enjoyed a much higher profile at this event than in any previous one. Abdulkarim A. Al-Ghamdi, Executive Vice President for Gas at Saudi Aramco, said the company is targeting a 50% increase in gas production over the next five years supported by major investment in CCS. The nation intends to double its natural gas generation capacity and add up to 7 GW of combined-cycle capacity awarded each year for the next decade. 

Danny Rice, CEO of NET Power, also advocated on behalf of CCS. His company is developing near-zero-emissions utility-scale power using natural gas. It uses natural gas and oxygen to fuel a supercritical CO

) cycle that generates electricity, while also capturing CO

. Baker Hughes is partnering with NET Power to develop SCO

 turboexpanders and other pumping and compression technology for NET Power.

“We need to reduce carbon in a way that assures the energy supply,” said Rice. “The incentives within the Inflation Reduction Act make it attractive to create CCS projects at low cost.”

Rather than focusing all investment and attention on new technologies that have yet to be proven, are difficult to scale, and lack the infrastructure to support them, Rice advocates using existing infrastructure and existing technologies to achieve emissions and net-zero targets.

Maria Sferruzza, Executive Vice President of International Engineering, Construction & Solutions at Snam, stressed energy security as part of energy diversity. She explained that 70 bcm of LNG was suddenly needed in Europe to replace Russian LNG contracts when war broke out.

“LNG strengthens the natural gas market in Europe and will play a part in our energy mix for a long time to come,” said Sferruzza. “Diversity of supply is needed for security and lowest cost of supply.”

Snam has been expanding the pipeline network in the southern part of Italy to make it as strong as that in the north while making the entire network hydrogen-compatible and addressing methane abatement. This consists of instrumentation upgrades to detect methane leakage and verify pipeline integrity, as well as equipment to capture methane and recompress the captured gas.

Toby Rice, President and CEO of EQT, made it clear that the world needs more gas and more LNG now. 

“We need more than three times the current volume of LNG being produced to be able to replace coal usage worldwide,” he said.

As for the environmental impact of gas, Rice noted that more than 40% of natural gas producers have already signed on to meet zero or near-zero methane emissions by 2030. He said the technology already exists to pinpoint methane sources.

Rice was critical of environmental lobbyists who attempted to stop new pipeline projects. He contended that more natural gas and less coal equals lower emissions. By making these new pipelines hydrogen-ready, the network can move closer to net zero via hydrogen blending.

“The argument that we should not build pipelines is ridiculous, as they will be needed for the changeover from coal to gas, when hydrogen becomes available for power generation, and when we start to capture carbon at an industrial scale,” said Rice.

Alessandro Puliti, CEO and General Manager of Saipem, is another energy producer that is acting to lower emissions.

“Gas is the fuel of today, will be the fuel of tomorrow, and offers plenty of opportunities to reduce its carbon footprint,” he said. “Without LNG, we couldn’t have coped with the Russian crisis. LNG is essential in moving energy around the world.”

Liquid hydrogen transportation, he said, is problematic due to its lack of energy density. Instead, he sees a future for low-carbon ammonia as an easier way to transport hydrogen. Once delivered, it can either be converted to hydrogen for energy production or used as a raw material for fertilizer and other uses.

"Ammonia is the best way to transport hydrogen on ships," said Puliti. 

About the Author: Drew Robb, former editor of Turbomachinery International, is a freelance writer specializing in engineering and technology. Email Drew at drew@robbeditorial.com.

The Baker Hughes conference argued in favor of natural gas as a fuel that can help meet net-zero goals.

Baker Hughes Annual Meeting: Turbomachinery in a Decarbonized Future

Methane, the main component of natural gas, is on the Environmental Protection Agency’s (EPA) hit list, calling it a climate “super pollutant.” Methane has a shorter lifetime in the atmosphere than CO

 but a greater near-term warming potential. According to the EPA, methane is responsible for approximately one-third of the current warming resulting from human activities and is a greenhouse gas (GHG) with a global warming factor 28 times higher than CO

The Agency released its final rule in late 2023 that will sharply cut methane and other GHG emissions from oil and gas operations—the nation’s largest industrial source of methane. The ruling includes revisions to the new source performance standards and emissions guidelines and promotes the use of methane-detection technologies.

The International Energy Agency (IEA) says methane abatement in the oil and gas industry is one of the cheapest options to reduce GHG emissions anywhere in the economy, and the industry has the largest potential for abatement in the near term. The energy sector accounts for nearly 40% of total methane emissions from human activity; oil and gas operations are responsible for 80 million tons of methane emissions.

The solutions and technologies outlined by the EPA will prevent an estimated 58 million tons of methane emissions from 2024 - 2038. The EPA said the rule would achieve a nearly 80% reduction below the future methane emissions expected without the rule.

In IEA’s Net-Zero Emissions by 2050 (NZE) scenario, energy-related methane emissions decrease by around 75% by 2030—two-thirds of which comes from reducing oil and gas operations emissions. Further, more than 40% of the emissions reductions to 2030 in the NZE Scenario can be achieved with measures that would result in overall savings given the value of the captured gas. These measures include mechanisms to detect and immediately tackle large leaks, replacing pneumatics and pumps, and installing recovery systems. According to IEA, they would require just over 10% of the total spending on methane abatement and can produce results quickly, laying the groundwork for further reductions.

Toby Rice, President and CEO of EQT, said at the 2024 Baker Hughes Annual Meeting (AM) that more than 40% of natural gas producers have already signed on to meet zero or near-zero methane emissions by 2030. In addition to other efforts, EQT—the largest U.S. natural gas producer—is partnering to conduct aerial monitoring of an area the size of France to detect methane emissions. 

The Italian energy company Snam is addressing methane abatement throughout its network: instrumentation upgrades to detect leakage and verify pipeline integrity, as well as equipment to capture and recompress methane gas to boost utilization and efficiency, according to Maria Sferruzza, Executive VP of International Engineering, Construction & Solutions at Snam, who also spoke at the Baker Hughes AM.

One of the big ways oil and gas companies such as bp have reduced their methane emissions is by eliminating flaring. bp aims for zero routine flaring by 2025 at its U.S. onshore operations and globally by 2030. 

Saipem, an Italian multinational oilfield services company, also pledged zero methane leakage by 2030. At the Baker Hughes AM, Alessandro Puliti, the CEO and General Manager, talked about the company’s zero-flaring technology for power plants and other areas of the infrastructure to detect fugitive methane emissions.

“All new design and engineering for our new plants is done to ensure zero flaring and zero fugitive emissions while lowering the physical and environmental footprint,” he said.

One Saipem customer found a way to utilize boil-off gas from its LNG storage facility, which was previously flared or vented, thus improving the efficiency of the ecosystem.

From big-picture site design to hand-held detection cameras, actuators, and aerial technologies such as satellites, airplanes, and drones, the industry uses the latest technologies to detect, reduce, and eliminate leaks and methane emissions.

As they say, less is more. And that’s true in the case of Chevron’s production facilities in the Mustang area in Colorado. The design, completed in 2022, only uses 7.5 surface acres versus the 400 surface acres usually required to deliver the same oil and gas production volume—that’s more than a 95% reduction in surface footprint. The minimal design also lowers lifecycle costs by 15 - 20%.

But it eliminates more than space. Because it produces spec oil direct-to-pipeline, there’s no need for big production tanks, flare systems, or further downstream processing facilities. In addition, flowback technology eliminates air emissions. This design can lower Chevron’s GHG by more than 90%.

The company has been using utility electrical power since 2019 to drill 56 wells, and, when possible, uses grid electricity versus onsite generators to power the drilling rig. This step eliminates 100% NOx and other ozone precursor emissions during the summer months, and close to 75% in colder months when operations require boilers for heat. Plus, it eliminates truck traffic—the design cuts down on more than 152 million miles of truck traffic and associated emissions—and noise from the generators.

 that its goal is simple: “Keep methane in the pipe. We believe methane reductions are possible in the energy industry, and in other key sectors, through the adoption of industry best practices, advancement in measurement technologies, carbon pricing, and methane regulations. Our methane strategy is focused on preventing methane emissions and using advanced detection technologies to validate performance, inform repairs, and improve inventories. We believe this approach can scale quickly across a global asset base, provide actionable information for methane emissions reduction, and augment emissions reporting as protocols become available.”

Oil and gas companies like Chevron use high-tech cameras, such as Teledyne FLIR optical gas imaging (OGI) cameras, in upstream and downstream operations to detect leaks proactively and for regulatory compliance. FLIR OGI cameras quickly scan broad sections of equipment and survey difficult-to-reach areas. They can also detect leaks from safe distances and display invisible gases as clouds of smoke.

“OGI cameras’ largest market is the detection of methane (and other hydrocarbons) in the oil and gas industry from upstream (well pads) to downstream (LNG or refineries),” said Craig O’Neill, the Global Director of Business Development at FLIR. “We also have business in renewable methane industries like biogas production, landfill gas-to-energy, and LNG markets.”

O’Neill said the biggest advantage of handheld OGI cameras is the “ground truth” that the technology shows. Once a leak is detected, the camera stores a video so the technician can share it with coworkers, repair personnel, or environmental professionals. “Many other technologies simply provide an ‘alarm’ that methane is present or a single snapshot image showing methane emissions. While these are great, they don’t tell the whole story of what is happening nor provide a true understanding of the emission event—is it a vent or a leak? Was it an intermittent emission event? Exactly what component is leaking rather than a general area where emissions are present?”

FLIR has cameras in almost every mid-to-large oil and gas operator in the upstream industry, ranging from a single unit to dozens.

Plus, OGI cameras also support the new methane-mitigation industry requirement to quantify emissions detected with technology. For example, the Bayernoil refinery complex in southern Germany integrated a gas detection camera into its leak detection and repair programs and used it to minimize hydrocarbon gas discharges from its piping systems, specifically leaks near flange gaskets.

IBS GmbH, headquartered in Bremen, Germany, conducts in-process analysis and detects gas leaks in biogas facilities. For IBS, using the FLIR GF320 camera not only significantly reduced the time it takes to scan a biogas facility compared to conventional gas detection technology, but it also enabled ground access to difficult areas such as where the tank meets the roof and the inner gas membrane. The case studies were similar for both BP Chemicals and Inspectahire, who said they were able to enhance safety and efficiency—the thermal imaging in FLIR’s cameras allows techs to keep a safe distance, when needed, to detect gas leaks and reduce repair downtime, among other benefits.

With the help of the NGIF Accelerator and its Emissions Testing Center (ETC) program, cleantech startups are developing innovations to tackle methane emissions. The program—operated by the not-for-profit arm of NGIF Capital Corp.—offers dedicated spaces via host sites for these companies to develop, test, and validate their solutions. The four-stage program includes access to the entire gas value chain, including a live gas operations environment.

Through the ETC program, Qube Technologies tested its fixed sensor that continuously, versus intermittently, monitors methane emissions. Since testing at the Tourmaline Oil/Perpetual Energy West Wolf Lake Plant—an ETC program host site—it has deployed over 4,000 sensors at over 1,000 sites, including Canadian operators such as Arc Resources, Enhance Energy, and Ember Resources.

Drones, satellites, and other detection technologies have helped many organizations significantly reduce their emissions. In fact, the Environmental Defense Fund reported on March 4, 2024, that MethaneSAT—a satellite designed to detect and quantify methane emissions—detached from SpaceX Transporter-10 into space. It will circle the Earth 15 times a day and measure changes in methane concentrations as small as three parts per billion.

To reduce emissions at its operations in the Permian Basin, ExxonMobil uses airplanes and helicopters to trail airborne technologies outfitted with methane sensors. It then integrates information collected from flyovers with data from ground-based mobile and fixed sensors remotely monitored from Houston. ExxonMobil said it “reduced methane emissions from all operated assets by nearly half as of year-end 2021 when compared to 2016” and eliminated 100% routine flaring in the Permian Basin, as per the World Bank Zero Routine Flaring Initiative.

Pneumatic devices comprise 40 – 50% of upstream oil and gas methane emissions. Rice said that a certain widely used pneumatic device at EQT turned out to be the company’s biggest source of methane emissions. The company replaced all 9,000 of these devices within 18 months, lowering companywide methane emissions by 70%.

Kathairos Solutions developed a system that uses liquid nitrogen, an inert gas, to power pneumatic devices, thereby replacing instrumental gas and eliminating the need for methane venting. It’s designed for smaller remote well sites, and its adaptable set-up is designed to minimize downtime and reduce operational disruptions.

Mitch Jones, Project Engineer at Kathairos Solutions, said the system gives customers the flexibility to set, commission, and fill the tank before tying it into their system, or Kathairos can facilitate this step. Within the first year of the unit’s commercial availability, 1,000 Kathairos units were installed and offset methane emissions by 40,000 metric tons of CO

Jones said one of its customers in the Rockies region had over 140 tanks installed in less than three months, averaging five tanks installed and tied-in per day. This addressed the needs of 2,500+ wells and around 9,000 pneumatic devices, significantly reducing methane emissions from oil site pneumatics.

Another example from ETC program is Kinitics Automation, a Vancouver-based company whose roots are in the automotive and power-generation industries. The company developed an electric valve actuator to replace methane-venting pneumatic actuators. During tests at one of the ETC program host sites—the University of Calgary and its labs—the actuator’s positional performance was evaluated at a variety of temperatures. Outcomes revealed that the actuator reached the target positions within 0.1% at all tested temperatures and responded to motion commands of 0.25%—the smallest commanded value. In a differential pressure test, the actuator maintained a closed-valve state with a 4,000 kPa(g) differential pressure present across the valve. The electric valve actuator met or exceeded the performance of traditional pneumatic actuators. 

Duke Energy developed its Integrate Methane-Monitoring Platform (IMMP) to detect leaks and measure methane emissions on natural gas distribution systems. It uses a satellite with a short-wave infrared sensor to monitor methane emissions and ground-based technologies such as continuous monitoring sensors, gas cloud imaging cameras, and handheld/portable gas-sensing analyzers.

“IMMP started with satellite captures in Greenville, SC, which helped the team refine, improve, and scale the technology and the methane detection algorithms to various types of local distribution company assets with varying terrain and geography,” said Lauren Crowe, Managing Director of Natural Gas Business Transformation at Duke Energy. 

IMMP has reduced recordable leaks in the Carolinas by more than 85% since its inception in 2022. “Duke Energy’s Natural Gas Business Unit is also using cross-compression technology to capture methane,” Crowe said. “We are also making investments in renewable natural gas, which is considered carbon-neutral because it removes methane from the atmosphere and displaces geological gas.”

The cloud platform ingests and calculates high volumes of real-time leakage data and then quantifies and prioritizes findings in graphic dashboards. Crowe explained that because the technology automates leak detection closer to the source, “pipeline management and operations teams can dispatch repair and maintenance crews to targeted sites for remediation based on near real-time information provided on cloud-enabled mobile devices. Using this method and technology enables us to identify and remediate any leaks in our system quicker and more comprehensively.”

The company’s extension program was selected by the U.S. Department of Energy’s Office of Fossil Energy and Carbon Management for nearly $1 million of funding. “As part of our IMMP extension project, we are testing a suite of both top-down and continuous-monitoring technologies with hopes of being able to detect and quantify emissions across all spatial and temporal scales and to evaluate the efficiency and accuracy of the various types of technologies,” Crowe said. The expansion project will include interstate, customer natural gas assets, upstream, and midstream. “The IMMP extension project will help us build a standard admissions, accounting, and reporting framework that will be useful across the entire value chain.”

To hear more about methane emissions in the oil and gas industry, check out our TurboTime podcast episode with the 

From ground-based technologies to site design and aerial innovations, the industry continues to use smart devices to abate methane emissions.

March/April 2024