The bright future for natural gas

April 20, 2021
Drew Robb

Turbomachinery Magazine, March/April 2021,

The big surprise was the bullishness of oil & gas executives about the future of natural gas. They presented a united front on the necessity of hydrocarbons within the energy mix, while at the same time working hard to reduce emissions.

Hydrogen-based turbomachinery and carbon capture, utilization, and storage (CCUS) of natural gas loomed large in the agenda. Similarly, the expansion of liquefied natural gas (LNG) merited several sessions, as well as ways to lower the carbon footprint of oil & gas operations.

Lorenzo Simonelli, Chairman & CEO of Baker Hughes, kicked things off by explaining the “Energy Forward” conference theme. He emphasized that energy is, and will continue to be, the foundation for the world’s progress.

“There are people who believe hydrocarbons should be relegated to the history books, that economic progress is at odds with environmental stewardship,” said Simonelli. “I think that is short sighted; we can be the positive agents of change.”

His argument centered around the fact that the peak of oil production and consumption could occur in the next ten years. Yet energy demand will continue to rise. There are nearly a billion people without access to electricity. As a result, it will be difficult to counter the demand for coal in the developing world.

“There is no scenario where hydrocarbons disappear so efficiency matters and we must work on reducing emissions,” said Simonelli. “Hydrogen generation, CCUS, and energy storage must become more cost competitive and scalable.”

He outlined what his company is doing on these fronts. This includes the acquisition of a carbon capture company and successfully testing its NovaLT gas turbines operating on 100% hydrogen.

“There is no scenario where hydrocarbons disappear, so efficiency matters and we must work on reducing emissions,” said Lorenzo Simonelli, Chairman & CEO of Baker Hughes.

“Renewables will not scale fast enough to displace energy demand in the coming years so we must learn to consume hydrocarbons in a better way,” said Simonelli. “Natural gas should serve as both a transition and a destination fuel; its efficiency is compelling.”

He ended by making the case that LNG is a favorable option for countries that lack home-grown resources. Baker Hughes is engaged in improving LNG’s emissions profile, as well as addressing methane venting, fugitive emissions, and flaring, which Simonelli regards as a bigger opportunity to reduce greenhouse gases (GHG) than CO2.

One of the scenarios proposed to reduce carbon dioxide emissions. Carbon capture, switching from coal to gas, and raising equipment efficient account for more than 50% of potential gains.[/caption]

Changing role for gas

The Baker Hughes AM is a gathering of top oil & gas execs from around the world. Several offered their views on the oil & gas market.

Peter Coleman, CEO of Australian LNG and energy producer Woodside, has attention on handling emissions from his company’s massive storage operations, such as addressing leaks from valve stems, and the elimination of flaring. He said process upsets can lead to flaring, so work is being done to prevent such upsets.

Coleman expressed doubts about Europe’s attempt to turn away from gas, while Asia is embracing it.

“Despite severe economic stress, LNG grew 2% globally last year,” he said. “Fundamentally, Asian nations know their pathway to climate commitments has gas as an important element.”

Woodside’s plans to reduce its emissions include investment in hydrogen, carbon sinks such as growing trees, and CCUS, which he said will be attractive to deploy within a few years.

“We are protecting the value of our existing business and looking at what we can invest in based on what we are good at,” said Coleman.

On hydrogen, he said we still need to crack the hydrogen code. A little-known fact is that ten times the energy is needed to convert hydrogen from water compared to what it takes to make LNG.

Meanwhile, Woodside has formed an agreement with Japanese companies JERA, Marubeni, and IHI to undertake a joint study examining the large-scale export of hydrogen as ammonia for use in decarbonizing coal-fired power generation in Japan. It will examine the construction and operation of large-scale ammonia facilities and optimization of supply chain costs.

Another deal with the Tasmanian government in Australia is a pilot project to turn abundant hydroelectric power into hydrogen. The hope is that a five-ton electrolyzer will provide hydrogen to power the transportation fleet on the island. But Coleman drew attention to the small scale of this equipment in comparison to typical LNG projects. The scaling up of hydrogen has not really been thought through, he said.

He ended by pointing out that there is no industry around the world other than oil & gas with the funding or the ability to deploy the vast resources, the personnel, and the equipment anywhere in the world needed to bring hydrogen to fruition. He called for common sense about the future of energy.

“It will be 2030 before hydrogen at scale is available,” said Coleman. “The transportation market will move at a different pace to power generation as each has a different price point for viability.”

Elena Burmistrova, Deputy Chairman of Gazprom Management Committee, Director General of Gazprom Export, continued the positive theme.

“Gas can substitute for coal quickly, efficiently, and economically while lowering emissions,” she said.

Burmistrova laid out the case for gas in any energy mix: It has mature market mechanisms, self-balancing characteristics compared to oil, price predictability, is a known technology, and has the lowest emission rates among existing fuels. Gas pipelines are also the cheapest way to transport energy. She believes it makes sense to invest in pipeline infrastructure in a way that hydrogen, biogas, and syn gas can gradually be introduced to take advantage of the network.

“The rise in renewables raises the volatility of energy production and gas is needed for stabilization,” said Burmistrova. “Overly ambitions emissions goals foster regulations that are pushing immature solutions and exclude technologies that are efficient.”

She complained that the EU is proposing very low criteria for power plants that she believes are an attempt to outlaw gas plants. She also doubted the economics of green hydrogen when blue hydrogen makes more economic sense. (Blue hydrogen is produced from gas using steam methane reforming, with related carbon emissions offset. Green hydrogen is produced from renewable energy using electrolysis. In both production processes hydrogen is combined with nitrogen to form ammonia to enable it to be shipped as a liquid).

Bob Dudley, Chair of the Oil & Gas Climate Initiative and former CEO of BP, had a similar take.

“I see no scenario that is credible for an energy future without natural gas,” he said.

This assertion is supported by analyst assessments. IHS Markit predicts that the worldwide share of renewables will rise from 25% today (including hydro and biomass) to more than 50% by 2050. Coal will continue to dominate followed closely by natural gas. But gas will displace coal and become the top energy source during the 2030s. Its use will expand steadily through 2050. Coal usage, however, will begin to decline slowly but won’t disappear. According to IHS Markit, coal use will be around the same as photovoltaic solar by 2050 and will still amount to more than onshore wind.

LNG expansion

Many of the AM sessions focused on LNG. The current installed capacity of LNG is about 460 million tons per annum (MTPA). Demand is expected to double in the next 15 years. Final investment decisions should be made for another 100 MTPA of LNG over the next year or two.

While the LNG market is expanding rapidly, those involved are working to make the technology cleaner and greener. Approaches include the adoption of low-emission equipment that can be integrated with combined cycle plants, renewables, hydrogen, and CCUS. Baker Hughes’ new LM9000 gas turbine, for example, has 44% simple cycle efficiency. It has been designed to reduce project cost and the time required to provide mid-sized train modules for LNG.

Nicholas Fulford, Global Head of Gas and LNG at the GaffneyCline Consultancy, explained that about a quarter of the emissions attributable to the burning of natural gas are from LNG and its various operations.

“Upstream gas production, processing, and transport emissions contribute heavily to the carbon intensity of LNG,” said Fulford. “Liquefaction is next in volume of emissions with shipping being the lowest.”

“With respect to past projects, today we can reduce emissions and carbon in LNG production by 30% with no additional cost in production using existing technologies,” said Daniele Marcucci, LNG Decarbonization Manager, Baker Hughes. But there is no silver bullet. Waste energy recovery, zero leakage compression, high efficiency gas turbines and centrifugal compressors, eLNG, combined cycle gas turbines, H2 blending, and digital efficiency will all play a part.”

He said an LNG plant utilizing LM9000 gas turbines instead of heavy duty units could achieve an emissions reduction of up to 20%. The LM9000 provides 73 MW at 44% efficiency with 15 NOx and 25 ppm CO. Baker Hughes eLNG option pairs the LM9000 with a 40 MW electric motor-driven compressor for modularized, midscale LNG in the 0.8 to 1.0 MTPA per module range. Weighing less than 2000 tons with less than 2000 square meter footprint, it can lower LNG train emissions by 30%.

LM9000s are to be used in Novatek’s Arctic LNG 2 project in Eastern Russia. The company has 4 trillion cubic meters of resources in its Russian Arctic portfolio. It plans to produce 70 million tons of LNG produced by 2030 via its Artic LNG 1 and 2 projects. By building two transshipment terminals (one further south where the Pacific Ocean won’t freeze up), it plans to have year-round service.

“Let’s not be apologetic about our industry as we are lifting millions out of poverty,” said Mark Gyetvay, Deputy Chairman of the Management Board at Novatek. “Without fossil fuels, society would not be where it is today. Natural gas is clean energy. It is a false narrative that it is harmful.”

He called for the industry to unite as one voice to combat misinformation. The Keystone Pipeline, he said, is an example of what can happened if we don’t advocate our clear message. He believes the correct transition is from coal to renewables and natural gas.

The company’s Yamal LNG project is operating and has already offloaded 500 cargoes amounting to more than 40 million tons. It consists of four trains. Artic LNG 2 has train one half finished with contracts signed for about 84% of the project’s total expenditures.

Gyetvay reviewed the various models and scenarios proposed to reduce carbon emissions. Regardless of the scenario, he said Asia will use more natural gas, not less. Even with the achievement of net zero carbon by all countries by 2060, there will still be 480 MTPA of LNG consumed. With business as usual, it would be 740 MTPA.

“Natural gas will play a large role in the energy mix despite any net zero scenarios,” said Gyetvay. “We will be a supplier of natural gas for many decades.”

Baker Hughes is partnering with Novatek to develop low carbon hydrogen technology for LNG trains. A pilot program will introduce hydrogen blends into the main process for natural gas liquefaction to reduce carbon dioxide emissions from LNG facilities, including the Yamal LNG complex.

Carbon capture

Carbon capture, utilization and storage received more attention at this year’s AM than at the last ten combined.

Hege Rognø, Head of R&D, Low Carbon Oil & Gas Technologies at Equinor, called CCUS a “climate mitigating business opportunity.” Her company (formerly known as Statoil of Norway) has industrial-scale experience with CCUS. Its Sleipner Field in the North Sea has been doing CO2 injection since 1996. In that time, it has stored more than 18.5 million tons in subsurface layers. In addition, the Snohvit Field has injected 8.5 million tons of CO2 since 2008. And its Test Center Mongstad (TCM), operating since 2012, is testing a variety of technologies and approaches for carbon capture.

On the more adventurous side, Equinor’s Longship project will capture CO2 from plants on the east coast of Norway, compressed it, take it on ships, and into a storage facility on the west coast where it will be piped offshore to be injected. In conjunction with Total and Shell, Equinor plans to have this one operational by 2023. Eventually, it will scale up the number of ships to gather CO2 from ports around Europe. The company is also working on CCUS projects in the UK and is searching for viable saline aquifers and depleted oil and gas fields as new places for storage.

“CCUS is key to achieving large volumes of hydrogen,” said Rognø.

Like Equinor, Baker Hughes is pursuing CCUS. It has invested in solvent-based post combustion carbon capture technology. A cyclic and continuous absorption/desorption process uses an aqueous solvent. In the absorber, the CO2-rich flue gas is treated by a CO2-lean solvent that can capture CO2. The solvent is then discharged from the absorber, and the solvent is regenerated in the stripper for reuse. A chilled ammonia process helps prevent solvent degradation and means less energy is needed in compression. It is being tested currently at TCM Equinor.

Baker Hughes acquired this technology via its purchase of Compact Carbon Capture (3C), a company specializing in carbon capture. 3C’s technology differs from traditional solvent-based solutions by using rotating beds instead of static columns to distribute solvents in a modularized format. The rotating bed technology is said to enhance the carbon capture process while having a 75% smaller footprint and lowering capital expenditures.

Hydrogen

Baker Hughes has more than 70 gas turbines worldwide operating with a natural gas/hydrogen blend, including the NovaLT gas turbine product family which can start-up and burn gas blends up to 100% hydrogen. An ongoing project has the goal of finding the ideal hydrogen concentration, one that would not require a major gas turbine retrofit. Currently, an upgrade can be done on a 7EA gas turbine. This enables it to run on 25% to 30% hydrogen with a minor impact on footprint and output. The major adjustment is that the DLN fuel gas skid is moved outside the GT package.

Turbomachinery will be needed in all areas of the hydrogen value chain.[/caption]

Powered by a blend of up to 10% hydrogen, a Baker Hughes NovaLT12 turbine will be installed at Snam’s gas compressor station in Istrana, Italy. 70% of Snam’s pipelines are already built with “hydrogen ready” pipes. The unit recently completed testing and will be installed later this year 2021. By blending 10% hydrogen into the total annual gas capacity transported by Snam, it is estimated seven billion cubic meters of hydrogen could be introduced into the network each year.

“Hydrogen can be cost competitive within five years,” said Marco Alverà, CEO of SNAM.

He estimates it will cost around $2 per kg to produce hydrogen gas. But it will cost a lot more to get it into someone’s truck. More like $9, he said. ■

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