CCS – a challenge for natural gas [NGW Magazine]
The latest report by the Inter-Governmental Panel on Climate Change, published in October, warned both of the dangers of allowing atmospheric temperatures to rise more than 1.5 °C above pre-industrial levels and of the far-reaching measures that would be necessary to limit that rise to 1.5 °C in coming decades.
As the diplomats gear up for the next climate change conference in Katowice, Poland, from December 2-14, the evidence base is moving inexorably towards ‘net zero by 2050’. This means a state in which the world lives within its carbon budget. No more carbon is produced than can be absorbed by the environment.
Moreover, this balanced state must be achieved earlier than had been expected. There is no guarantee that it will be, but the signal for industry is that the push towards ‘deep decarbonisation’ is likely to intensify.
This presents a challenge for gas-fired power generation, which, while relatively low carbon in relation to coal or oil, is nevertheless a major emitter of CO2.
If net zero by 2050 is pursued, at some point, gas-fired power generation will face the same pressures – both political and economic – that have seen the pipeline of new coal plant construction stall, leaving aging coal fleets in Europe and the US declining into a low carbon sunset.
That in turn implies that it is gas-fired generators who must meet and resolve the challenge of carbon capture and storage (CCS), if they are to sustain a permanent place in the energy firmament. They must succeed where coal-fired generation has so manifestly failed. It is a tough challenge.
The central problem with existing means of carbon capture is that they deliver a double hit to power plant economics. They involve substantial capital expenditure on new equipment, which then creates a parasitic load on the plant.
In other words, capital and operating costs rise, while saleable power output and thus income falls. It adds up to high-cost generation with the added burden of long-term CO2 storage.
However, two new technologies are under development in the US which will be watched with intense industry interest: NetPower’s Allam cycle gas-fired power plant at La Porte in Texas and FuelCell Energy’s molten carbonate fuel cell (MCFC) project at Barry in Alabama.
Both projects have substantial backers. La Porte is being built in partnership with Exelon Generation, McDermott and 8 Rivers Capital, using a Toshiba turbine, while the Barry project is backed by ExxonMobil and Southern Company, which owns the Barry generation complex.
Both technologies have unique characteristics which treat CO2 as an integral part of the power generation process. This holds out hope for a game-changing advance in the economics of CCS, one that is based on natural gas rather than coal-fired generation.
Rather than use pure hydrogen, MCFCs use the hydrogen bonded in natural gas directly, although in theory any hydrocarbon can be used as a fuel source. The process also pumps CO2 around the system and concentrates it at the fuel cell’s anode, which facilitates carbon capture. The process needs an additional carbon source, which is supplied by exhaust gas from hydrocarbon combustion. In the Barry project, flue gas from the Barry power plants will be used.
The process is high temperature, which has two advantages – nickel rather than platinum can be used as a catalyst, and the waste heat can be recycled raising overall process efficiency close to the level of a combined heat and power plant.
In effect, the carbon capture process via the fuel cell increases capital and operational expenditure, but adds to rather than detracts from power output.
However, it is not all plain sailing. The high temperatures mean components have to be replaced often, while operating the fuel cell and power plant in tandem requires a delicate and sometimes elusive ‘balance of plant’.
The board of South Korea’s Posco Energy in November approved the sale of its 2.9% stake in FuelCell Energy, following major losses in its fuel cell business, which included the installation of MCFCs. A 1-MW demonstration project at Kings County in the US, which started in April 2004, and ran on both natural gas and biogas, was discontinued after two years on cost grounds, despite producing some positive results.
FuelCell Energy says that with a cogenerating fuel cell, a conventional power plant’s output could be boosted by 80%. However, according to Matthew Eisler, a fuel cell expert at Strathclyde University in Scotland and author of Overpotential: Fuel Cells, Futurism, and the Making of a Power Panacea, a 500-MW coal plant would require 400 MW of fuel cell capacity to capture 90% of the CO2 emissions, representing three to four times the capital expenditure of a conventional coal plant.
The Barry project is way off this scale, but it is a start, comprising a 2.8-MW MCFC, fuelled by natural gas with coal plant flue gas as the additional carbon source. Plant operation is expected to begin in early 2019 and will run for about six months before switching to the exhaust gas from one of the Barry site’s gas-fired units.
The La Porte project is more advanced and significantly larger. The 50-MW (th) plant fired up in May, and its primary developer Netpower says 300-MW commercial plants are under development, with potential deployment in the early 2020s.
The plant uses the so-called Allam cycle, which involves combusting natural gas with pure oxygen rather than air. The lack of nitrogen in the combustion stage reduces nitrogen oxides. The CO2 produced during combustion is then used under high temperatures and pressures (supercritical CO2) as the working fluid, replacing steam, to drive the turbine. The system retains heat within the system which increases efficiency rather than losing it to the atmosphere.
The additional cost of an air separation unit for the combustion process is offset by no longer needing a cooling tower. Moreover, because CO2 is used as the working fluid, it can be taken off as a high-purity, high-pressure stream for storage or other use, for example in enhanced oil recovery (EOR). NetPower says that its Allam cycle gas plants are directly competitive with best-in-class natural gas plants without CCS.
This claim remains unproven. As with the MCFCs, component durability and process stability are likely to present challenges, owing to the use of supercritical CO2. Moreover, despite talking up EOR as a potential use for CO2, the opportunities for this in reality are very limited. In addition, neither technology addresses the problems and concerns surrounding long-term CO2 storage.
The idea that commercial plants based on these technologies will start to be widely deployed in the early 2020s is almost certainly over-optimistic.
However, both technologies appear to hold promise by integrating carbon capture into the power generation process rather than leaving it as an afterthought which requires expensive remedial add-on equipment. This could prove a key part of the solution as gas-fired generation first benefits from the decline of coal, but in so doing becomes a more prominent source of CO2 emissions itself.
UK CCUS test site picked
Producers' group OGCI Climate Investments (OGCI CI) has agreed with BP, Eni, Equinor, Occidental Petroleum, Shell and Total to move forward with the UK’s first commercial full-chain carbon capture, use and storage (CCUS) project in the industrial heartland of Teesside.
CCS, or CCUS as it has latterly become, is key to achieving UN climate change limitation goals in the International Energy Agency's optimistic scenarios, among other outlooks; but so far its application has been limited commercially to projects where injecting CO2 can improve oil recovery rates. The UK has already flirted with CCS schemes once before, but the government of the day withdrew its planned funding after announcing a competition, leaving the projects at the planning stage.
This new plan will combine CO2 capture from gas-fired power generation and local industrial emitters in Teesside and inject it into a formation under the southern North Sea. The infrastructure created would enable industrial clusters in Teesside and elsewhere to capture and store CO2 from their processes. The clean CO2 could also attract CO2-utilisation companies, revitalising the region with new technologies and investment. As the project progresses, the team will be looking for additional partners across the full value chain. It is anticipated that the project will then progress toward front-end engineering design (Feed) in 2019, the OGCI said.
OGCI CI told NGW late November that most of the key decisions, such as the technology and the final repository for the CO2 were yet to be made, including whether to build anything or not. That will become clearer after Feed. However the six companies involved are looking at a 600-MW plant as the anchor project, with other industrial emitters to form a cluster. The site could hold three such trains, it said, releasing up to 1.8mn mt/yr. Storage candidates include a very large saline aquifer and a depleted gas field. “We are confident that we have very good storage options,” it said.
Other companies have found that injecting acid gas into reservoirs that had not held it before – in this case, in order to boost gas production – is a bad idea as the CO2 dissolves the rock and resurfaces.
OGCI Climate Investments has four investments in CCUS and is exploring several early stage CCUS projects for future investment with the goal of utilising the knowledge gained in advancing the Clean Gas Project. In 2019, the OGCI and Climate Investments will focus on significant collaborative efforts to inject momentum into a global CCUS industry.