Onboard Carbon Capture and Storage Systems (OCCSS) in Shipping: Shanghai Qiyao Environmental Technology Conducts First Ship-to-Ship Liquefied CO2 Transfer

     Onboard carbon capture and storage systems (OCCSSs) are an emerging method of decarbonizing shipping. Hydrogen, methanol, and ammonia are expected to compete for powering ships with reduced carbon footprints. DNV explains onboard carbon capture:

“Onboard carbon capture (OCC) covers a range of technologies to capture carbon dioxide emissions from ships during operation. For post-combustion systems, OCC involves cleaning of exhaust gases from CO2, separating it, and storing it onboard for eventual offloading, in various different forms depending on the technology (gas, liquid, or mineral). For pre-combustion, carbon is separated from the fuel to produce hydrogen and use it in dedicated energy conversion machinery.”

     DNV has a great white paper on OCCSSs. They note that ideally, an OCCSS should be incorporated into new ship builds rather than retrofitted. This is because space on the ship must be carefully organized, and its safety maximized. It is also more expensive to retrofit. DNV, which has been working with OCC since 2009, notes:

“A scaling of the CCUS infrastructure network, across geographies and nations, will establish the grounds for uptake of onboard carbon capture technology. As of today, this infrastructure is not established. The shipping industry needs to reach out to relevant CCUS development projects near major shipping hubs to discuss how the maritime industry can connect to the wider CCUS value chain.”

     They also point out the importance of after-treatment and compare it to the SOx scrubbers utilized after the 2020 sulfur rules for ships went into effect.  

“Shipping companies will aim to ensure compliance through effective combinations of decarbonization options: carbon-neutral fuels, energy-efficiency improvements, operations optimization, and onboard carbon capture. Similar to what happened in the 2020s with the global sulphur cap, the after-treatment of carbon emissions is expected to be relevant for both existing ships and newbuilds.”

     An important consideration is that carbon capture systems use fuel to run them, and that fuel must be accounted for in decarbonization accounting, cost analysis, and overall ship energy systems. The availability of disposal systems for the captured CO2 is another important consideration. Offshore wells are being outfitted for carbon sequestration in many places, so that will likely be a main route for disposal.

     DNV lists five steps of the OCCSS value chain: 1) onboard capture, 2) onboard storage, 3) offloading, 4) transportation, and 5) permanent storage or utilization.

     Product specifications and purity requirements must be met for offloading. Ports around the world must be coordinated with CCUS projects around the world to minimize CO2 transport costs. Different methods of carbon capture are summarized in the graphics below.

     They note that the capture rate must be balanced against the fuel penalty.  

“The fuel penalty depends on the type and performance of the capture technology, as well as the ship’s operating profile and engine load. The trade-off between high capture and low fuel penalty is one of the main challenges of onboard carbon capture, as it affects both the environmental and economic viability of the technology. Systems operating with a high capture rate may have excessive energy demands, making them less feasible from an operational and cost perspective.”

     Cost analysis is very important for these projects. Ships that run on LNG can have some advantages in coordinating processes such as liquefaction and can implement smaller capture systems, saving energy and space. Cost must be balanced with decarbonization goals.

      Regulations vary by region and include GHG regs, safety regs, and waste handling regs. These are summarized below.

     Other practical considerations are noted in the graphics below, including onboard positioning and the different needs for different types of ships. The extra weight of the CO2 and its capture and storage system is also a consideration.

 

Shanghai Qiyao Environmental Technology Conducts First Ship-to-Ship Liquefied CO2 Transfer

     Shanghai Qiyao Environmental Technology (SMDERI-QET) recently conducted the world’s first ship-to-ship liquid CO2 transfer at the Yangshan Deep-Water Port in Shanghai. Global Data explains:

“This transfer demonstrates an end-to-end solution comprising onboard carbon capture, liquefaction, storage, and offloading to carbon utilisation facilities.”

“SMDERI-QET's Onboard Carbon Capture and Storage System (OCCS) has achieved more than an 80% capture rate of carbon dioxide with a 99.9% purity level.”

“Since delivering the first full-process OCCS in early 2024, SMDERI-QET has completed several LCO₂ offloading projects, enabling ship owners to improve their Carbon Intensity Indicator (CII) ratings.”

     The company noted that the lack of port infrastructure capable of managing large-scale carbon storage and recovery has hindered their ability to offload more ship-to-shore LCO2. They noted that:

“…transferring LCO₂ from ship to ship greatly enhances the adaptability of operations, allowing for efficient loading and unloading for ships at terminals that may lack the necessary facilities.”

     They plan to collaborate with domestic and international partners to help develop regulations and standards for marine carbon capture and transportation.

     SMDERI-QET's general manager, Su Yi, noted:

“We are confident that the completion of the world’s first ship-to-ship LCO₂ transfer, together with the further development of onboard carbon capture technologies, will not only lead to rapid development of a global network of shore-based carbon storage and utilisation facilities, but accelerate the decarbonisation of shipping.”

 

 

References:

 

SMDERI-QET successfully conducts world’s first ship-to-ship LCO₂ transfer. GlobalData. June 27, 2025. SMDERI-QET successfully conducts world’s first ship-to-ship LCO₂ transfer

Onboard Carbon Capture and Storage on Ships. Chara Georgopoulou. DNV. Onboard carbon capture and storage on ships

The Potential of Onboard Carbon Capture in Shipping. DNV. White Paper. September 2024. DNV_Onboard_Carbon_Capture_White_paper_24-09_web.pdf

Russia Offers to Supply LNG and Technology to Mexico: A Proposed Option to Leverage Against Trump Tarrifs?

     Russia’s offer to supply Mexico with LNG and LNG technology is a bad idea on several levels. According to a report by Russian Energy Minister Sergey Tsivilyov published by the Russian state news agency TASS, Russia is ready to supply Mexico with LNG along with technology to extract and refine in difficult geological conditions. He said they are prepared to manage the whole production chain from extraction to refining and transportation. His remarks were made at the St. Petersburg International Economic Forum. According to Daily Digest:

“The Xataka portal explains that 72% of Mexico's natural gas supply comes from the United States, according to an analysis by Fitch Ratings, something which is of concern to Mexico as it fears US President Donald Trump could take advantage of this energy dependence.”

     Thus, Mexico is dependent on the U.S. for natural gas, which comes from pipelines at a very low price, which benefits Mexican power and industries. It is difficult to see how Russian LNG, no matter how discounted, could compete. Mexico has not commented on the offer.

“However, according to Xataka, Pemex is going through a difficult time, trying to reopen some of its 30,000 wells, about a third of which are closed. However, it goals are being thwarted by a lack of funds and delapidated infrastructure.”

Pemex has long been a poorly run nationalized company. A majority of the world’s best geologists and engineers are nearby in Texas and could no doubt offer better rejuvenation for Mexican oil production.

“According to Infobae, Mexican President Claudia Sheinbaum stated that new energy projects will be created, including power plants and gas pipelines. According to Reuters, Mexico indicated back in January that it was speeding up plans to double its strategic gas storage to avoid being trapped by Trump.”

     Mexico does not need Russian LNG, but they do need assurances from the Trump administration that oil and gas deliveries won’t be disrupted by trade dispute issues. The selling of Texas oil and gas to Mexico benefits both countries immensely. It is a win-win that should not be altered significantly. Mexico should also soundly reject the idea of supporting sanctions on Russian oil & gas due to their brutal invasion of Ukraine. Mexico has been too friendly to Russia, in my opinion.

Pemex noted that it is working to reopen oil wells that were shut in to boost production as it struggles to reach the government's target of 1.8 million barrels per day. I do not think Mexico’s energy concerns about supply disruptions are warranted, but I do understand the concerns around Trump’s chaotic and hardball trade policies. Mexico rightly wants to increase its energy security and rejuvenate its mismanaged oil fields. U.S. oilfield technology would be better, cheaper, and much more sensible than Russia. U.S. companies are already working together with Pemex in offshore plays. According to an article in Skillings Mining Review:

“Mexico, already navigating U.S. scrutiny of its energy policies under the USMCA, sees diversification as a necessary risk.”

“Mexico isn’t pivoting away from the U.S.—it’s creating options,” said Leo Timmons, an LNG advisor in Houston. “Energy trade has become a proxy for broader geopolitical shifts.”

     Mexico is also cooperating more with Russia, importing more agricultural goods and industrial equipment. Russia’s economy is singularly focused on conquering more Ukrainian territory, which gives it even more goods to sell from the stolen resources. Thus, buying Russian goods is an indication of support for their brutal war machine, which includes North Korean soldiers and Iranian weapons technology. The U.S. government obviously does not want more Mexico-Russia cooperation, and for good reason. While the deal is only speculative at this point, it would be a slap in the face to Ukraine and the U.S.

 

     

References:

 

Mexico quietly sheds US energy dependence with Russia's offer of natural gas. thedailydigest.com. June 27, 2025. Mexico quietly sheds US energy dependence with Russia's offer of natural gas

Could Russia Supply Mexico With LNG, Replace U.S. Natural Gas Pipeline Imports? Christopher Lenton. Natural Gas Intelligence. June 26, 2025. Could Russia Supply Mexico With LNG, Replace U.S. Natural Gas Pipeline Imports?

Russia is ready to provide LNG to Mexico. World Energy News. June 21, 2025. Russia Is Ready To Provide LNG To Mexico

Russia LNG Deal Injects Geopolitics into Mexico Energy Trade: Russia’s LNG offer challenges U.S. dominance in Mexico’s energy trade and gas diplomacy. Charles Pitts. Skillings Mining Review. June 25, 2025. Mexico Energy Trade Faces Shake-Up as Russia LNG Deal Surfaces

Fermi America’s Amarillo Hypergrid: Rick Perry and Texas Tech Aim to Make the World’s Largest Energy and AI Data Center Campus Using Nuclear, Solar, Natural Gas, Batteries, and Wind

     Fermi America, a company co-founded by former Energy Secretary and Texas Governor Rick Perry and Texas Tech University, is planning the world’s largest energy and AI data center campus, near Amarillo, Texas, in the Texas Panhandle region. The proposed site encompasses 5800 acres. According to the Amarillo Tribune:

“On Thursday, Fermi America announced that a “first-of-its-kind” HyperGrid campus “expected to integrate the largest nuclear power complex in America, the nation’s biggest combined-cycle natural gas project, utility grid power, solar power, and battery energy storage to deliver next-generation artificial intelligence” is coming to Amarillo. In partnership with the Texas Tech University System (TTU System), Fermi America expects the project to be the world’s largest energy-driven AI complex.”

“The campus will span 5,769 acres and have the potential to deliver up to 11 gigawatts of power and 18 million square feet of AI capacity. It will be near the nuclear facility Pantex.”

     The first phase of the project is expected to deliver 1GW of power by the end of 2026. The site will include 18 million square feet of data centers. The project will also include academic and research opportunities for faculty and students, including internships, employment, and workforce training and placement programs.

“Project backers say the site’s location near Pantex highlights its strategic value. In addition to its proximity to the DOE site, the nearly 5,800-acre plot sits above one of the country’s largest natural gas fields and near key U.S. gas pipelines.”

“In its official statement, the energy company described the Hypergrid as “the only site with the potential to include safe, clean, new nuclear power, the nation’s biggest combined-cycle natural gas project, utility grid power, solar power, and battery energy storage at unprecedented scale.”

      The Nuclear Regulatory Commission (NRC) is currently reviewing Fermi America’s plans. The company is billing the project as important for defense-critical infrastructure, a key project for a U.S. nuclear renaissance, and a way to compete with China for AI innovation. Of course, nuclear is not cheap and takes time, years to decades to go from the proposal stage to the completion stage. Thus, no timelines were given aside from 1GW of power by the end of 2026. The project is expected to be formally launched on July 4.

 

     

 

 

References:

 

US plans 5,800-acre world’s largest energy campus to power 8 million homes. Sujita Sinha. Interesting Engineering. June 27, 2025. US plans 5,800-acre world’s largest energy campus to power 8 million homes

Breaking: Advanced nuclear energy AI campus ‘HyperGrid’ coming to Amarillo. Fermi America partnering with Texas Tech University System to build 18 million square feet of artificial intelligence capacity. Jo Early and Brianna Maestas. Amarillo Tribune. June 26, 2025. Breaking: Advanced nuclear energy AI campus ‘HyperGrid’ coming to Amarillo : Amarillo Tribune

TTU System and Fermi America Announce the World’s Largest Advanced Energy and Intelligence Campus. Kristina Butler. Texas Tech University System. June 26, 2025. TTU System and Fermi America Announce the World’s Largest Advanced Energy and Intelligence Campus | Texas Tech University System

Rethink Power. Fermi America. Fermi America | Gigawatt Scale Power for Next-Gen AI

Gold H2 Uses Microbes to Convert Residual Oil in Depleted Well to Make Hydrogen: They Think They Can Soundly Beat Green Hydrogen Costs with Similar Emissions

     With a process they are calling bio-stimulation, U.S. company Gold H2 announced that the first phase of their pilot test at a legacy oilfield in California’s San Joaquin Basin, extracting a gas stream with 40% purity hydrogen from a depleted oil well. I first wrote about so-called gold hydrogen, also known in this case as bio-hydrogen, a few years ago. Finally, Gold H2 is doing pilot tests of its new technology. I have also heard of injecting oxygen to produce hydrogen, but that is a much different process.

“Gold H2 exists to do what no one ever has: produce clean hydrogen directly in the subsurface using biology, engineering, and existing energy infrastructure,” said Prabhdeep Singh Sekhon, CEO of Gold H2.

“This field trial is tangible proof. We’ve taken a climate liability and turned it into a scalable, low-cost hydrogen solution. It’s a new blueprint for decarbonisation, built for speed, affordability, and global impact.”

     According to the news release:

“Using the abandoned oil as a feedstock, the microbes produce a hydrogen-rich stream that can be extracted using existing well infrastructure. Once scaled, Gold H2 claims that the process will have a similar carbon intensity as green hydrogen but with costs below $1 per kg – comparable to the current price of natural gas.”  

     That kind of pricing, comparable to grey hydrogen production costs, at $1 to $1.50 per kg, would be amazing and economical for producers, if it could be achieved. If these trials are confirmed successful and tweaked for commercialization without significant technological constraints, they could be scaled up quickly due to the favorable economics. Bloomberg doesn’t think green hydrogen will hit parity with grey hydrogen made from natural gas for decades. The DOE has an unfeasible aspirational goal of green hydrogen via electrolysis production costs of $1/kg by 2031, but that seems highly unlikely. 2050 seems more likely. Gold H2 thinks they can do it for $0.80 kg and even down to $0.5. CEO Prabhdeep Sekhon thinks it should be given in $/MW to be more comparable.

     The company utilizes a proprietary blend of microbes and nutrients that consume the oil left in the reservoir and a product of the reaction is hydrogen gas, which can be produced through the well tubing. The hydrogen is processed and purified, which does require energy and produces some CO2, but the emissions are similar to those of green hydrogen derived from water electrolysis. The purification process involves separating H2 from other gases and is currently the major cost hurdle.

     The current Congressional spending bill being debated is threatening to reduce or eliminate the 45V tax credits for clean hydrogen, just implemented in the Inflation Reduction Act. If the credit is removed, the company is prepared to offer its proprietary technology to countries with favorable incentives, such as Canada, the Middle East, Europe, and Brazil.

     Project partners and investors, Chart Industries, Inc., and ChampionX, are optimistic about the technology scale-up:

“This breakthrough isn’t just a step forward, it’s a leap toward climate impact at scale,” said Jillian Evanko, CEO and President at Chart Industries, Inc., Gold H2 investor and advisor. “By turning depleted oil fields into clean hydrogen generators, Gold H2 has provided a roadmap to produce low-cost, low-carbon energy using the very infrastructure that powered the last century. This changes the game for how the world can decarbonize heavy industry, power grids, and economies, faster and more affordably than we ever thought possible.”

“ChampionX is proud to have supported this pioneering effort,” said Deric Bryant, COO and President of Chemical Technologies at ChampionX. “As a technology-focused company that supports sustainable energy production through the entire lifecycle of a well, we’re excited by the results of Gold H2’s field trial and what it could mean for the future of clean hydrogen production.”

     The process utilizes existing water injection infrastructure, which suggests it is going to be used mainly in depleted waterflooded fields to tap residual and immovable oil – that oil that stays in the reservoir even after secondary recovery, which is a vast amount of oil. Indeed, Sekhon confirms this. Wells in the San Joachin Basin are commonly steam-flooded for EOR. The reservoir itself becomes a bioreactor. Another co-benefit of the process is that depleted wells can be converted to microbial water injection/production for hydrogen recovery, rather than be plugged and abandoned, delaying decommissioning liabilities.

     The microbial breakdown of oil, known as biodegradation, is not new. It has been used, for instance, to break down oil that has been spilled to remove a portion of it from the environment. Their method leverages the metabolic pathways of certain microbes to produce hydrogen from oil in rock. The process begins by identifying the microbes that are naturally present in the reservoir so that they can understand the existing microbial community. The desired microbes are fed by specifically tailored nutrients. With the nutrients, the process can be turned up or down, on or off.

     At scale, they think they can produce well over 100 tons of H2 per day in a commercial field. Processing may take different forms and be done by different providers depending on local offtake needs and H2 purity specs. Hydrogen embrittlement is a concern in steel pipelines. Their pressures are lower than in the H2 pipeline, but they can build new pipelines or use coatings as needed. Off-takers could in the future be AI data centers. There are several depleted oil reservoirs in several regions in the U.S. favorable for data center locations.

     Projects should be near the depleted oil assets. That is very important for hydrogen. Gold hydrogen could compete with stranded gas for data centers or power plants. It can be blended with natural gas in some cases. The process produces water that could be used for cooling in data centers.

     There is a great webinar by Enverus where Enverus analyst Graham Bain discusses gold hydrogen with Prabhdeep Sekhon, CEO of Gold H2. Sekhon is a petroleum engineer who started out working for Hess in the early years of the Bakken and internationally. He thinks that gold hydrogen changes the story about hydrogen and decarbonization. He sees the issue as an integrated subsurface problem that requires microbiology, geology, and reservoir engineering. With gold hydrogen, the reservoir is transformed into a bioreactor with the feedstock already in place – just add microbes and nutrients. Oil reservoirs have microbiomes. With oil production, the natural microbes are generally not desirable and may be intentionally inhibited. Microbe balances are rewired by the addition of the optimal microbes and nutrients in amounts that are not too high as to make a gas cap that would seal in pressure. Microbes are also added to inhibit the formation of methane and H2S. In fact, Sekhon says this makes up about 60% of the microbial brew. He said something about temperature of 170 deg C and 300,000 ppm salinities, but I’m not sure if that is an upper limit (I would think so since 170 deg C would be considered a high-temperature reservoir), or ideal. They note that another company, Geo-redox, is doing a different process to create serpentinization to make hydrogen in a deeper and hotter reservoir.

     Sekhon notes that the color wheel for hydrogen qualifies something that should be quantified, and it would be better to compare and classify by cost and carbon intensity. A downside of green hydrogen is the large amount of water needed as feedstock. Grey hydrogen requires methane as a feedstock. Gold hydrogen requires no water. Its feedstock is built in, and in addition, it avoids or delays a liability to decommission the well, potentially by 10-20 years as the suggested gold hydrogen project life. He says that permeability is more important than porosity for microbes. Stimulated reservoir volume (SRV) is also important. He mentions that in some projects, one may want to create methane in a reservoir or compress residual oil so that it can be produced. He notes that the company may become involved in projects to inhibit H2S production via microbes and sweeten sour crude. The microbes they use are naturally occurring. They spent a few years bioprospecting for the optimal microbe formulas, utilizing hundreds of static and dynamic lab tests. They are also working with microbes on other problems. In fact, he notes that in light of his disdain for the hydrogen color wheel, or rather in light of their diversifying projects, they are planning to rebrand and rename the company in the near future. He notes that reservoirs vary, so each must be bio-stimulated according to its characteristics. Field tests differ from lab tests. They are planning nine-month field trials. Purification plants are on the surface and can be controlled. As in natural/geologic hydrogen production, consumption of H2 must be prevented; thus, the 60% inhibitory microbes and their interest in sweetening sour reservoirs. He notes that they don’t have to worry about structural geological traps like natural hydrogen explorers. He mentions that they are looking at making ammonia in the subsurface with H2 and nitrogen gas (N2).

      In responding to a question about volumes per well, he notes that it depends on the reservoir. An independent lab suggested volumes of 1000kg per well per day. At less than $1 per kg production costs, including purification, that can mean a nice profit. He thinks they can develop 10,000 – 250,000 + kg/day projects. He predicts stable production over a 10-20-year period. The water vapor produced must be cooled. He mentions an MOU with a major turbine manufacturer to go from 100% methane to 100% H2 with the same turbine. Gemini out of LA is developing a compressor that also purifies H2, so new tech will soon be applicable. He wonders how fast they could get to deployments of 1MM to 10MM kg per day. Of course, there is still a need to reduce costs. Green H2 projects have been cancelled due to costs, even before the 45V issues. He thinks 45V credits should stay as prescribed in the IRA, but is ready to focus where the incentives are best, if necessary.

    

References:

 

Gold H2 uses microbes to extract hydrogen from disused oil well. The Engineer. June 26, 2025. Gold H2 Taps Hydrogen From Abandoned Oil Well

Oil-Eating Microbes Offer Tantalizing Clean Hydrogen Solution. Toya Levi. Bloomberg. June 24, 2025. Oil-Eating Microbes Offer Tantalizing Clean Hydrogen Solution | Gold Hydrogen

Creating clean hydrogen from old oil reservoirs using biology. Colorado Hydrogen Network. Podcast. January 17, 2025. Creating clean hydrogen from old oil reservoirs using biology | Gold Hydrogen

DOE Sets Eyes on Cutting Clean Hydrogen Cost, $1/Kilo by 2031. Jennifer L. Carbon Credits. May 10, 2024. DOE Sets Eyes on Cutting Clean Hydrogen Cost, $1/Kilo by 2031

Press Release: Gold H2 Delivers First Successful Subsurface Bio-Stimulated Hydrogen Production Field Trial. Toya Levi. Gold Hydrogen. Press Release. Jun 25, 2025. Press Release: Gold H2 Delivers First Successful Subsurface Bio-Stimulated Hydrogen Production Field Trial | Gold Hydrogen

Rewiring the Reservoir | Biohydrogen and the Next Energy Frontier. Webinar. Enverus. Graham Bain. Prabhdeep Sekhon, CEO of Gold H2. June 18, 2025. Rewiring the Reservoir | Biohydrogen and the Next Energy Frontier

 

HyTerra’s Nemaha Project in Kansas is Drilling Three Exploratory Wells for Geologic Hydrogen and Helium

     HyTerra’s Nemaha Project in Kansas is currently involved in drilling three exploratory wells along the Nemaha Ridge of the Mid-Continent Rift Zone in Kansas to evaluate the potential for producing geologic, or natural hydrogen gas, as well as helium. They also plan to further evaluate a well in nearby southern Nebraska on their Geneva Project with their partner on that project, Natural Hydrogen Energy.

     A LinkedIn comment by Benjamin Mee, executive director of HyTerra:

“We have the largest exploration program globally that I know of publicly which positions us well (data is king), but it’s more important to us to deliver this on time, on budget, and safely.”

     The company’s Blythe 13-20 well was drilled to a total depth of 5053 ft, with 2272 ft drilled into the Precambrian basement rocks section. This is 3100 ft deeper than the historic Scott-1 well drilled in 1982, which was found to have 56% hydrogen concentration in the gas stream.

     Below are several slides from HyTerra's April 2025 corporate presentation.

     Isotube gas samples were taken from the wells by NH2E and analyzed by Isotech Laboratories in Illinois. The company plans to drill several deeper wells targeting different traps along fault zones and develop regional geophysical data to further develop the prospect area. They have good, plausible local offtake opportunities for both hydrogen and helium.

      This is an exciting project that could have significant potential for developing hydrogen and helium prospects all along the Mid-Continent Rift System, which is extensive and present in several states in including Kansas, Nebraska, Michigan, Missouri, Iowa, Wisconsin, Minnesota, and possibly Ohio and Kentucky - as some geologists believe that the so-called Grenville Front there is more accurately a part of the Mid-Continent Rift System.

 

   

Mid-Continent Rift System

  

 

References:

 

Nemaha Project Operational Update. HyTerra. Press Release. June 10, 2025. Nemaha Project Operational Update – HyTerra- InvestorMax

Maiden Drilling At Our Nemaha Project, USA: Exploring for natural hydrogen and helium in the United States. HyTerra. Corporate Presentation. April 2025. PowerPoint Presentation

Midcontinent Rift System. Wikipedia. Midcontinent Rift System - Wikipedia

H2S to H2 and Sulfur: Converting a Dangerous and Destructive Waste Gas into Useful Products: Ongoing Research

     Research in 2021 from a couple of different papers shows that the dangerous and destructive gas hydrogen sulfide, or H2S, can be converted into hydrogen gas (H2) and sulfur, both desirable and valuable products. In one case, a reactor design achieved 24% higher sulfur uptake in 2% Molybdenum-doped iron-based sulfur carriers compared with undoped sulfur carriers. Both processes use a sulfur looping reactor that involves two processes: sulfidation and regeneration.

     H2S is commonly emitted from manure ponds, sewers, and is a major byproduct of oil refining, paper production, and mining. It also occurs naturally in some rock formations and in some oil & gas reservoirs, where it can endanger workers. I experienced low-level H2S poisoning while working on a well in Eastern Kentucky in the 1990s. We had an H2S detector and measured 10 parts per million (ppm) constant flow, but about 40ppm when the rig made a connection (added more drill pipe). The gas was from the St. Peter Sandstone, and we were drilling “on air” using compressed air to clean the hole. The H2S actually caused a hole to form in the flow line. After a few days of this, while staying onsite, I developed a constant headache and neck ache and decided to get a hotel room away from the site. Once we loaded the hole with drilling mud, there was no longer any HS coming from the well. I also took an H2S training course where we had to use Scott Air Packs and learn protocols for dealing with the gas. Several oil and gas workers have been killed by H2S, some due to a lack of training and not observing necessary safety protocols. H2S is also known as a very corrosive agent to metals, even at low levels.

     An article in the Brighter Side of News explains common industrial practices for dealing with H2S. Currently, one of the most widespread technologies for H2S processing is the Claus process, a catalytic process that converts H2S into elemental sulfur and steam.

“Current industry practices use the Claus process to remove hydrogen sulfide from waste streams. This process burns the gas to recover elemental sulfur and steam, but it wastes hydrogen and requires large amounts of energy. It's costly, inefficient, and doesn't recover hydrogen as a fuel. Alternative strategies, like selective oxidation and reactive adsorption using metal oxides, can capture more sulfur but still destroy the hydrogen content.”

“A better way would be to keep the hydrogen and transform it into usable fuel. That’s where the new process—nonoxidative decomposition of hydrogen sulfide—comes in. Instead of burning the gas, this method splits it directly into hydrogen and sulfur. However, there's a catch. The chemical reaction needed is highly endothermic, meaning it demands a lot of heat. Worse, the reaction tends to reverse itself before much hydrogen is made.”

     A research team at Ohio State University developed a one-reactor sulfur looping design with two stages: sulfurization and regeneration.

“In the first step, a metal absorbs sulfur from hydrogen sulfide while releasing hydrogen gas. In the second step, the sulfur-laden metal is regenerated by heating it in an inert atmosphere to release solid sulfur, readying it for another round.”

     Low-cost, non-toxic iron sulfide (FeS) is used as the sulfur carrier in the reaction. However, it does not react fast enough alone to make the process effective. 2% Molybdenum doping is utilized as a catalyst to speed up the reaction, leading to 24% more sulfur absorption, making it more effective and economical. Hydrogen yield was also increased. The process is still at lab scale, so commercialization of it is still far off, but the results are promising.

     Another sulfur looping reactor scheme to decompose H2S into H2 was developed utilizing CO2  and Ni3S2 as carriers and zirconium oxide (ZrO2) and magnesium aluminate (MgAl2O4) as supports. The results were published in a December 2021 paper in the Chemical Engineering Journal. The abstract notes:

“This work demonstrates a novel strategy for H2S and CO2 utilization and provides new insights into effective support selection aiding the design of a robust and efficient sulfur carrier.”

 

    

 

References:

 

Researchers transform ‘sewer gas’ into clean hydrogen fuel. The Brighter Side of News. June 10, 2025. Researchers transform ‘sewer gas’ into clean hydrogen fuel

Mo-Doped FeS Mediated H2 Production from H2S via an In Situ Cyclic Sulfur Looping Scheme. Kalyani Jangam, Yu-Yen Chen, Lang Qin, and Liang-Shih Fan. ACS Sustainable Chemistry & Engineering. Vol 9/Issue 33. August 12, 2021. Mo-Doped FeS Mediated H2 Production from H2S via an In Situ Cyclic Sulfur Looping Scheme | ACS Sustainable Chemistry & Engineering

Researchers transform ‘sewer gas’ into clean hydrogen fuel. Researchers found a way to turn hydrogen sulfide—a toxic industrial byproduct—into clean hydrogen fuel using iron and molybdenum. Joseph Shavit. The Brighter Side of News. June 5, 2025. Researchers transform ‘sewer gas’ into clean hydrogen fuel - The Brighter Side of News

Synergistic decomposition of H2S into H2 by Ni3S2 over ZrO2 support via a sulfur looping scheme with CO2 enabled carrier regeneration. Kalyani V. Jangam, Anuj S. Joshi, Yu-Yen Chen, Shailaja Mahalingam, Ashin A. Sunny, and Liang-Shih Fan. Chemical Engineering Journal. Volume 426, 15 December 2021, 131815. Synergistic decomposition of H2S into H2 by Ni3S2 over ZrO2 support via a sulfur looping scheme with CO2 enabled carrier regeneration - ScienceDirect