Alissa Marrapodi

Exterra Solutions Carbone Inc. entered a strategic collaboration with Énergir Développement Inc. (ÉDI) to accelerate carbon capture and enhance carbon sequestration efforts in Quebec. The two companies will identify business opportunities to develop joint decarbonization solutions related to the capture, transportation, and sequestration of CO2.

"Exterra combats climate change with its technology that allows for CO2 sequestration using mining residues,” said Olivier Dufresne, CEO and Co-Founder of Exterra. “This highly secure method will appeal to major industrial players seeking a sustainable decarbonization solution with a high level of social acceptability. Our strategy is also beneficial for producers of biogenic CO2, such as pulp and paper mills or renewable natural gas producers, who, even without being subject to carbon tax, can monetize their emissions by sequestering them with Exterra. This will enable them to produce high-quality carbon credits that can be sold on the voluntary carbon market."

Jean-François Jaimes, Executive Director of Renewable Energy & LNG Development at Énergir, echoed Dufresne, stating: "The challenge of the energy transition is immense, and we need a variety of solutions to successfully manage it. This is why we believe it is crucial to collaborate with innovative sectors in Quebec, key players who are implementing these solutions. We are excited to join forces with Exterra to explore the potential of the carbon capture and sequestration sector in Quebec. It not only offers a relevant solution to reduce the carbon footprint of sectors with limited options but also represents a coherent diversification opportunity linked to Énergir's decarbonization strategy."

As reported in Turbomachinery International’s cover story from May/June 2023

, large-scale adoption of carbon capture and storage

 is a challenge in both the United States and Europe. One way to increase adoption is through regulatory avenues. The United States passed the Inflation Reduction Act (IRA), which includes $369 billion in green energy grants and subsidies to accelerate the reduction of carbon. In March, Europe proposed the Net-Zero Industry Act, which aims to establish a framework of measures for strengthening Europe’s development of net-zero technologies.

Following the passage of the IRA, Aniruddha Sharma, Chair and CEO of Carbon Clean, a UK-based company focused on carbon capture solutions, said: “Carbon Clean has experienced a 64% leap in inquiries, and we expect the United States to become one of our largest markets,” Sharma said. “In March, we announced a significant expansion in North America to meet this booming demand. [We opened] a U.S. headquarters in Houston and are currently developing a local supply chain.”

Articles

The two companies will identify business opportunities to develop joint decarbonization solutions related to the capture, transportation, and sequestration of CO2.

Exterra Solutions Carbone, EDI Partner for Carbon Capture, Storage 

MOL Grou’s new green hydrogen plant in Százhalombatta, Hungary was recently outfitted with, created by Plug Power, to produce approximately 1,600 tons of carbon-neutral green hydrogen per year. The Hungary-based Danube Refinery will benefit from the €22 million investment by a reduction of more than 25,000 tons of CO2 per year. The plant will start producing later this year.

"MOL Group has reached another milestone: We can now produce green hydrogen without producing any greenhouse gases. Using this technology, we are able to achieve the same emissions reduction as if we took roughly 5,500 cars off the road overnight,” said József Molnár, CEO of MOL Group.

The electrolyzer technology will replace the natural gas-based production process over time, which currently accounts for one-sixth of the MOL Group's total CO2 emissions. The plan is for MOL to use the green hydrogen primarily in its own network for fuel production.

“Today, our new green hydrogen plant is only making MOL's industrial operations greener, but tomorrow it will offer solutions for the whole industry and hydrogen mobility,” Molnár said. “After Száhalombatta, we will take the technology to the other two fuel production units of the group to make the fuel production process more sustainable at each of MOL Group's refineries."

Plug Power's electrolysis equipment uses electricity from renewable sources to break down water into hydrogen and oxygen. It offered MOL hydrogen generators, optimized for the production of pure hydrogen, that have almost 50 years of operational experience.

“We are thrilled to celebrate, in partnership with MOL, the inauguration of one of Europe's largest green hydrogen plants supporting a refinery," stated Plug CEO Andy Marsh. "As a potent way to reduce carbon emissions within refinery operations, we are proud to equip MOL with electrolyzer technology to efficiently produce green hydrogen. Together, we are advancing toward carbon neutrality, fostering greener operations, and propelling the hydrogen economy forward.”

The investment is in line with the MOL Group's SHAPE TOMORROW corporate strategy.

September/October print issue of Turbomachinery International

, several experts, engineers, and OEMs addressed hydrogen’s role in the energy landscape, including supply and demand, opportunities, and obstacles. In 

, the various obstacles that are preventing the large-scale implementation of hydrogen, including the costs of manufacturing hydrogen, transporting it to a power station, and providing large-scale storage at the site, were each addressed.

“Reasonably priced and affordable electrolyzers are the prerequisite for covering the growing demand and future hydrogen costs,” said Alex Habeder, Head of Business Strategy

Sustainable Energy Systems at Siemens Energy. “Furthermore, generating green hydrogen requires a significant and accelerated expansion of renewable energy worldwide. This expansion can only accelerate if permitting becomes faster and less complicated. Automated factories for electrolysis on an industrial scale (including the GW scale) must be constructed, and the pipeline and industrial-scale hydrogen storage infrastructure must be implemented for storing and transporting the hydrogen.

A 10-MW electrolysis unit was installed at the oil company’s green hydrogen plant to produce roughly 1,600 tons of green hydrogen to offset its carbon emissions in its fuel-production network.

MOL Group Invests €22M in Green Hydrogen to Reduce CO2 at Danube Refinery

MTU Maintenance Berlin-Brandenburg completed an audit by Luftfahrtbundesamt (LBA)l, the German aviation authority, for the next steps in obtaining its CFM56-7B test capability. And MTU Maintenance Dallas received approval, from the Federal Aviation Authority (FAA), to test the engine model after a successful correlation of its test cell.

The test cell approval (for its location south of the German capital) completes its CFM56-7B portfolio expansion so that the Berlin-Brandenburg location can conduct the full range of maintenance, repair, and overhaul (MRO) workscopes on the engine model, including testing, at one site.

“The ability to test CFM56-7B engines in Europe, North America, and Asia within an independent network is quite unique to MTU because customers from any market in the world have near-immediate access to our comprehensive services,” said André Sinanian, Managing Director and SVP at MTU Maintenance Berlin-Brandenburg. “Expanding our capabilities and capacity across locations enables us to better serve the MRO needs for the prolific CFM56 and to continue MTU Maintenance’s success story.”

In 2023, MTU conducted more than 130 shop visits on the CFM56-7B network-wide. Additionally, in 2023 it moved its MTU Maintenance Dallas to a 440,000-square-foot facility at Perot Field Fort Worth Alliance Airport.

MTU Maintenance also announced its plans to expand its global ON-SITEᴾˡᵘˢ service activities. The company is integrating its on-site services by creating a central unit that will oversee and steer the global network of MRO response teams. In 2023, MTU’s ON-SITEPlus completed 1,000+ on-site events for over 500 customers globally.

“We are seeing a definite rise in demand for on-site and near-wing workscopes across the world, and have been expanding our capabilities in Australia, the United States, Brazil as well as here in Germany, in order to be as flexible with our service provisions as possible,” said Michael Schreyögg, Chief Program Officer at MTU Aero Engines.

Xaver Schmid was appointed VP Global ON- SITEᴾˡᵘˢ Network to further develop the global operations and build on MTU’s track record of customer support. Beyond the on- and near-wing activities, responsibilities include operational oversight of MTU Power’s field service crews for industrial gas turbines.

MTU Maintenance completed its portfolio addition and announced plans to expand its global services network. 

MTU Maintenance Completes CFM56-7B Test Capabilities, Expands ON-SITEᴾˡᵘˢ Services Network

During this episode of the TurboTime podcast, we discuss digital ecosystems with Jim Nyenhuis, the Performance Consultant at Emerson’s Power and Water Solutions Business. We focus on software, including AI-based software, detection and monitoring technologies, software’s influence on a turbomachine’s life, as well as cybersecurity and potential risks that power plants are exposed to.

Q: How does a digital ecosystem improve operational efficiency, plant safety, etc.?

 Digital technologies allow us to address all those issues. We work with customers to understand what operational efficiency means to them based on their objectives. Plant safety is without question built into everything we do. We want to understand and leverage what the underlying technology can tell us and let that information feed up through the digital ecosystem—how do we understand what's working well at the plant level, how do we identify if there are control problems or if individual pieces of equipment are having issues? A lot of that information is lying within the automation infrastructure, and I don't think we've leveraged that to the degree we want to. We find many customers do not understand the performance characteristics of their closed-loop controls or areas to drive additional improvement, efficiencies, etc.

Performance and control management is another big area that we look at. Our information, such as the automation system, will oftentimes track what operators are doing within the system. In the past, that information was stored in text-based logs, but there's a lot of valuable information stored in those log files that if we expose that information, we can understand how operators are interfacing with the system during different periods of operation, be it startup, shut down, various operating modes, etc., and based on that we can determine where operators are spending a lot of their time.

Podcasts

In this episode of the TurboTime podcast, we talk about digital ecosystems, including AI-based software, cybersecurity, and more with Jim Nyenhuis from Emerson. 

TurboTime Podcast: Software & Cybersecurity with Emerson 

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

In this episode of the TurboTime podcast, the Myth Busters, Klaus Brun, the Director of R&D at Elliott Group, and Rainer Kurz, a recent retiree from Manager of Gas Compressor Engineering at Solar Turbines, discuss turbomachinery codes and standards. The two differentiate codes versus standards, which are important for turbomachinery, and what to do if an operator or manufacturer disagrees with a standard.

Brun broke down the four components: standards, codes, specifications, and guidelines. “A standard is somewhat of a generic requirement; you can almost call it the minimum requirement that industry associations agree on for a piece of equipment,” he said. “There's a lot of gray area between here. Next are specifications—they are often related to a specific customer—one of the major oil companies may have its own specifications, and they often tie in standards. For example, let's say Shell or Chevron has their own machinery specification, and they may refer to standards, such as American Petroleum Institute (API) 616 or the American Society of Mechanical Engineers (ASME) standards, material standards, etc. And then you get into things like codes, where the gray area becomes even bigger. But codes traditionally refer to something a little stricter. These can be test codes, where there is a process that you have to follow, and you don't deviate from this process. There are codes related to OSHA requirements or legal requirements. Codes tend to be a little more rigid, more relevant, and more richly followed. Finally, there are industry guidelines from the API and other professional societies. They give advice and guidance on how to handle testing processes, design, etc.”

Kurz stressed that standards are not legally enforceable unless included in a purchasing agreement: “What makes a standard enforceable is if a customer in the purchase specifications says ‘Thou shalt follow such and such API requirement or these ASME standards.’ And then it becomes part of the contract and enforceable” he said.

Kurz also pointed out that one purpose of codes and standards is for system integration. “If you build a refinery, there's one manufacturer who builds the compressor, then there are people who build the pressure vessels, others who build the piping, and maybe the steam turbines. So, there are a lot of different parties involved that have to come together. And one thing that these codes and standards do is create a reasonable definition of the interfaces. At the end of the day, somebody needs to integrate all that equipment.”

The Myth Busters, Klaus Brun and Rainer Kurz, discuss turbomachinery codes and standards on the TurboTime podcast. 

TurboTime Podcast: Turbomachinery Codes and Standards with Myth Busters

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%.

Chevron's tankless facility design in Colorado. Credit: Chevron

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.

Teledyne FLIR optical gas imaging hand-held camera. Credit: FLIR

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.”

Methane leakage detection. Credit: Duke Energy

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.

Methane: How the Oil & Gas Industry is Cleaning Up Emissions

In this episode of the TurboTime podcast, we are featuring part of an interview with Dr. Jeffrey Goldmeer, the Global Hydrogen Value Chain Leader at GE Vernova, recorded at POWERGEN 2024 with our assistant editor, James Cook. Dr. Goldmeer discusses the many pathways to decarbonization, including next-generation combustors that support hydrogen and ammonia.

Below is a quick snippet of the interview with GE Vernova's global hydrogen leader:

 In the United States, in the South and Southwest, there are only approximately 1,600 miles of hydrogen-ready pipeline. Why is there a lack of hydrogen infrastructure in the United States, and are there roadblocks for hydrogen development in other areas of the country?

 When you say lack of infrastructure, if you're here in the Gulf Coast, where most hydrogen in the United States is consumed and produced, I don't think they would tell you they have an infrastructure issue. What we're talking about is a future where we might see the production and use of hydrogen more decentralized, across the United States. So that might imply maybe there's a lack of infrastructure in those places, but those places today don't have large-scale hydrogen production and consumption, So, I don't think it's a lack of infrastructure; I think that we haven't developed the hydrogen ecosystem in those locations. Now that's not to say that hydrogen isn't produced locally and used locally around the world, even in the United States—I think about companies that are producing hydrogen to use in fuel cells and forklifts. but they're producing it and transporting it by truck because they don’t have the volume of needing a pipeline.”

 featuring more content from our interview with Dr. Goldmeer.

This episode of the TurboTime podcast features an interview with Dr. Jeffrey Goldmeer, the Global Hydrogen Value Chain Leader at GE Vernova. 

TurboTime Podcast: Hydrogen, Ammonia, Decarbonization with GE Vernova

The 35th annual POWERGEN International Conference, held Jan. 23 – Jan. 25, 2024 in New Orleans at the Ernest N. Morial Convention Center, brought together folks from the power-generation sector, utilities, engineering, procurement, and construction (EPC), OEMs, and energy users. The tagline for this year’s show, Destination 2050, underscored much of the show’s content and education tracks, including the Mega Sessions and Technical Programs.

“There’s a lot of emphasis on the future—how do we future-proof the current assets that we have and how do we look toward low- and zero-carbon technologies,” said Kevin Clark, Content Director for POWERGEN International, Clarion Events. “A switch doesn’t flip overnight. Renewables are going to change the way we operate our equipment and machines, and we want to provide a forward-looking platform for these kinds of discussions for now and in 10, 15, 20 years, because it’s changing rapidly, and it will look very different in the future.”

This year’s show tallied more than 450 exhibitors, around 8,000 attendees, and boasted increases in utilities, up 42% from last year, and large-scale energy users, up 32% from last year. EPC's and large OEMs remained steady in attendance at 21% and 20%, respectively. 

Exhibit floor at POWERGEN 2024. Credit: Turbomachinery International

Clark said POWERGEN changed some of its Mega Session content. “[There are] a lot of new developments this year applicable to the power sector, such as EPA’s proposals that are affecting existing and new gas and coal plants,” Clark said. To address the legislative trend, the team populated a panel with representatives from EPA and Entergy.

POWERGEN 2024 also added a track to focus on operations and maintenance for utility-scale solar and wind. And, of course, the conference also gave tribute to its host city, New Orleans, through exhibition-hall cooking demos with Creole food, Golden Feather Hunters at the keynote, and more.

 addressed how power is impacting not only industry and policy but consumers, including the need for sustainable power during storms, the use of renewables and carbon capture, and the goals set forth by the Biden Administration.

Deanna Rodriguez, President and CEO of Entergy New Orleans, spoke of the city’s resiliency and its vulnerabilities to climate change. After the city was without power for seven days following Hurricane Ida, Entergy had to submit a resilience plan that centered around keeping power on during a storm and restoring it when it goes out.

"We are looking at resilience, reducing our carbon emissions, and affordability," she said. 

Bradford Crabtree, Assistant Secretary for the Department of Energy’s (DOE) Office of Fossil Energy and Carbon Management, spoke about carbon capture: “The DOE estimates that reaching President Biden’s ambitious plan for a net-zero emissions economy will require capturing and storing between 400 million and 1.8 billion metric tons of CO

 emissions from the U.S. economy annually by 2050. We’ve been making progress toward zero emissions of electricity, thanks to the dramatic expansion of renewables. Louisiana, one of the 15 states in the Southwest Power Pool, reached a record wind penetration of 88.5% on March 29, 2022. Of course, the annual average penetration is less than half that. Continued expansion of renewables and managing their reliability at ever greater and sustained levels of penetration will require the development and deployment of a much wider range of tools, including longer period duration battery storage, but also firm dispatchable resources such as next-generation nuclear, enhanced geothermal, and carbon capture and storage.”

Senior Vice President and Project Director at Sargent & Lundy, Kevin Huberty, led a 

high-level session on small modular reactors

 (SMRs) in which he addressed a commonly asked question: Why nuclear? The modern passive-safety features of SMRs have further improved the safety of nuclear technology, he said. Due to the power density of nuclear fuel, plants make efficient use of land, and the power does not produce direct carbon emissions.

In addition to producing baseload power and heat for industrial applications, “… the smaller footprint of these reactors, along with expected smaller emergency planning zones, make them more flexible for various locations,” Huberty said. “They can power up and down faster than your larger nuclear reactors for load-following of renewables.”

SMR licensing may be the largest hurdle, as the Nuclear Regulatory Commission requires extensive validation of SMRs before any land or technology permits are granted. However, a company can also obtain a license for the site and technology through a COL application, he noted, and the U.S. government has been supporting the technology through current legislation.

Marc Lemmons, Senior Technical Leader at the Electric Power Research Institute (EPRI), discussed the emerging interest in 

The available infrastructure for implementing hydrogen fuel includes ~1,600 miles of hydrogen-ready pipeline throughout the United States Gulf Coast. Despite this, organizations are currently repurposing natural gas pipelines for pure and mixed hydrogen transportation. However, there are other hurdles to overcome: Lemmons said hydrogen for power generation presents challenges with the electrical demand required to produce it, embrittlement, and high flame temperatures.

The United States maintains 3,000 miles of ammonia pipeline in the country’s central regions. These ammonia lines are equipped with centrifugal pumps. “The perk of ammonia is that we are very familiar with it, and it’s easily transportable,” Lemmons said. “Now, while I don’t think it makes the most sense for U.S. utilities to start investing its time in ammonia firing, remote areas, especially out west, may benefit from using ammonia.”

The power industry may not be interested in the use of hydrogen or ammonia for generation applications currently, but new technologies can transform the economics and technical feasibility of their integration. Further, smaller industries, such as utilities and refineries, are beginning to utilize hydrogen and ammonia on a smaller scale with documented success.

, a smart power base and coal-fired power plant in Emmet, LA, with three units (800 MW) from the early 80s, discussed artificial intelligence (AI) and the use of closed-loop optimizer solutions.

Two of the three turbines were outfitted with Siemens Energy’s Omnivise combustion optimizer—which targets optimum zone operation while considering dynamic operation constraints—as well as its soot-blowing and temperature optimizers. No mechanical changes were made to the units.

The goal: increased efficiency and a reduction in NOx and CO

 emissions. The outcome: The optimizer reduced reheat spray flows by 22%, superheat spray flows by 85%, flue gas exit temperature by 0.73%, excess oxygen and carbon monoxide, and NOx emissions. It also enabled more symmetrical reheat steam temperatures and lowered soot-blower air usage. Additionally, all furnace differential pressures remained optimal.

POWERGEN 2025 will be held in Dallas. The team is currently “recruiting some of the smartest and brightest people in the industry that can help us craft our content for next year,” Clark said. “I like the direction we’re going in as far as having a lot of different micro tracks where you talk about, for example, the potential future of small modular reactors (SMRs) and carbon capture. Hydrogen does really well, but of course, we’re not getting rid of the 

This year’s show focused on the future—how to future-proof current assets and incorporate new ones.