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'Clean Coal' Technologies, Carbon Capture & Sequestration
(Updated November 2018)
Coal is used extensively as a fuel in most parts of the world.
Burning coal produces over 14 billion tonnes of carbon dioxide each year.
Attempting to use coal without adding to atmospheric carbon dioxide levels is a major technological challenge.
The greatest challenge is bringing the cost of this down sufficiently for 'clean coal' to compete with nuclear power on the basis of near-zero emissions for base-load power.
There is typically at least a 20% energy penalty involved in 'clean coal' processes.
World R&D on CCS exceeded $1 billion per year over 2009 to 2013, then fell sharply.
The term 'clean coal' is increasingly being used for supercritical coal-fired plants without CCS, on the basis that CO2 emissions are less than for older plants, but are still much greater than for nuclear or renewables.
Some 27% of primary energy needs are met by coal and 38% of electricity is generated from coal. About 70% of world steel production depends on coal feedstock. Coal is the world's most abundant and widely distributed fossil fuel source. However, each year burning coal produces over 14 billion tonnes of carbon dioxide (CO2), which is released to the atmosphere, most of this being from power generation.
Development of new 'clean coal' technologies is attempting to address this problem so that the world's enormous resources of coal can be utilised for future generations without contributing to global warming. Much of the challenge is in commercialising the technology so that coal use would remain economically competitive despite the cost of achieving low, and eventually 'near-zero', emissions. The technologies are both costly and energy-intensive.
As many coal-fired power stations approach retirement, their replacement gives much scope for 'cleaner' electricity. Alongside nuclear power and harnessing renewable energy sources, one hope for this is via 'clean coal' technologies, such as carbon capture and sequestration, also called carbon capture and storage (both abbreviated as CCS) or carbon capture, use and storage (CCUS). It involves the geological storage of CO2, typically 2-3 km deep, as a permanent solution. However in its Energy Technology Perspectives 2014 the International Energy Agency (IEA) notes: “CCS is advancing slowly, due to high costs and lack of political and financial commitment.” In its 2016 version of the same report, the IEA reported that there were 17 large-scale CCS projects operating globally.
Consequently the term 'clean coal' is increasingly being used for supercritical and ultra-supercritical coal-fired plants without CCS, running at 42-48% thermal efficiency. These are also known as high-efficiency low-emission (HELE) plants. The capital cost of ultra-supercritical (USC) HELE technology is 20-30% greater than a subcritical unit, but the higher efficiency reduces emissions and fuel costs to about 75% of subcritical plants. A supercritical steam generator operates at very high temperature (about 600°C) and pressures (above 22 MPa), where liquid and gas phases of water are no longer distinct. In Japan and South Korea about 70% of coal-fired power comes from supercritical and ultra-supercritical plants.
Managing wastes from coal
Burning coal, such as for power generation, gives rise to a variety of wastes which must be controlled or at least accounted for. So-called 'clean coal' technologies are a variety of evolving responses to late 20th century environmental concerns, including that of global warming due to carbon dioxide releases to the atmosphere. However, many of the elements have in fact been applied for many years, and they will be only briefly mentioned here:
Coal cleaning by 'washing' has been standard practice in developed countries for some time. It reduces emissions of ash and sulfur dioxide when the coal is burned.
Electrostatic precipitators and fabric filters can remove 99% of the fly ash from the flue gases – these technologies are in widespread use.
Flue gas desulfurisation reduces the output of sulfur dioxide to the atmosphere by up to 97%, the task depending on the level of sulfur in the coal and the extent of the reduction. It is widely used where needed in developed countries.
Low-NOx burners allow coal-fired plants to reduce nitrogen oxide emissions by up to 40%. Coupled with re-burning techniques NOx can be reduced 70% and selective catalytic reduction can clean up 90% of NOx emissions.
Increased efficiency of plant – up to 46% thermal efficiency now (and 50% expected in future) means that newer plants create less emissions per kWh than older ones. See Table 1.
Advanced technologies such as Integrated Gasification Combined Cycle (IGCC) and Pressurised Fluidised Bed Combustion (PFBC) enable higher thermal efficiencies still – up to 50% in the future.
Ultra-clean coal (UCC) from new processing technologies which reduce ash below 0.25% and sulfur to very low levels mean that pulverised coal might be used as fuel for very large marine engines, in place of heavy fuel oil. There are at least two UCC technologies under development. Wastes from UCC are likely to be a problem.
Gasification, including underground coal gasification (UCG) in situ, uses steam and oxygen to turn the coal into carbon monoxide and hydrogen.
Sequestration refers to disposal of liquid carbon dioxide, once captured, into deep geological strata.
Some of these impose operating costs and energy efficiency loss without concomitant benefit to the operator, though external costs will almost certainly be increasingly factored in through carbon taxes or similar which will change the economics of burning coal.
However, waste products can be used productively. In 1999 the EU used half of its coal fly ash and bottom ash in building materials (where fly ash can replace cement), and it used 87% of the gypsum from flue gas desulfurisation.
Carbon dioxide from burning coal is the main focus of attention today, since it is implicated in global warming, and the Kyoto Protocol requires that emissions decline, notwithstanding increasing energy demand.
CCS technologies are in the forefront of measures to enjoy 'clean coal'. CCS involves two distinct aspects: capture, and storage.
The energy penalty of CCS is generally put at 20-30% of electrical output, though since no full commercial systems are yet in operation, this is yet to be confirmed. US and European figures below suggest a small or even negligible proportion.
Table 1. Coal-fired power generation, thermal efficiency
country Technology Efficiency Projected efficiency with CCS
Australia Black ultra-supercritical WC 43% 33%
Black supercritical WC 41%
Black supercritical AC 39%
own ultra-supercritical WC 35% 27%
own supercritical WC 33%
own supercritical AC 31%
Belgium Black supercritical 45%
China Black supercritical 46%
Czech Republic own PCC 43% 38%
own ICGG 45% 43%
Germany Black PCC 46% 38%
own PCC 45% 37%
Japan, Korea Black PCC 41%
Russia Black ultra-supercritical PCC 47% 37%
Black supercritical PCC 42%
South Africa Black supercritical PCC 39%
USA Black PCC & IGCC 39% 39%
USA (EPRI) Black supercritical PCC 41%
OECD Projected Costs of Generating Electricity 2010, Tables 3.3.
PCC= pulverised coal combustion, AC= air-cooled, WC= water-cooled.
Capture & separation of CO2
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Under the new Administration in 2010 however, the project was reconsidered, and design work, geological investigations and a revised cost estimate proceeded. In August 2010 DOE said that it would abandon the original FutureGen idea and would now retrofit unit 4 of Ameren's existing oil-fired plant in Meredosia, Illinois, with oxy-combustion rather than IGCC, calling this FutureGen 2.0 – "a clean-coal repowering program and carbon dioxide storage network." It would burn pulverised coal and capture over 90% of the CO2 produced (1.3 Mt/yr over 30 years), to produce 166 MWe net. A pipeline would link it to a regional CO2 storage hub, and a site will be sought for this to enable sequestration in the Mt Simon Formation. Ameren would use B&W technology for oxy-combustion repowering of the plant, and FutureGen Alliance will focus on the pipeline and storage, with a view to also drawing on other CO2 sources within 160km, so that some 500 million tonnes capacity was sought.
The DOE said that it would be prepared to contribute $1.1 billion of the $1.65 billion cost to it as a public-private partnership involving the FutureGen Industrial Alliance (FGA), Ameren Energy Resources, Babcock & Wilcox, and Air Liquide Process & Construction, Inc. Late in 2010 members of the FGA included domestic coal companies Peabody, BHP Billiton, Rio Tinto and Consol Energy, plus E.On. No domestic utilities remained, though Exelon had indicated an intention to join. In December 2012, the Illinois Commerce Commission mandated that Commonwealth Edison (ComEd) and Ameren Illinois had to purchase the electricity from the project for 20 years, but the utilities challenged this on the grounds of cost.
After identifying a suitable sequestration site in Morgan County, the design phase of the project was announced in February 2013. Construction was due be completed in 2015, with the project being on line mid-2016, but this was delayed as most members of the FGA dropped out, leaving only Peabody, Glencore and Anglo American. In February 2015 DOE cancelled further funding for the project, after having spent $202 million on it.
Other demonstration projects
North America
The US Department of Energy (DOE) has said that funding would be made available to assist other projects that aim to add carbon capture and storage (CCS) to existing coal plants, but will no longer include hydrogen production as part of the project. Over half of the CO2 capture projects in development or operation globally are in North America, and all but one of these is oriented to provide CO2 for enhanced oil recovery (EOR).
Duke Energy Corp in the USA is building a $3 billion, 618 MWe, IGCC plant at Edwardsport, Indiana ($4850/kW). This is a regulated plant, but Duke says that consumers will not be asked to pay for more than $2.72 billion of its final construction cost, excluding financing.
In Texas, the Petra Nova project near Houston, a partnership of the US DOE, NRG Energy and JX Nippon, is set up to capture 1.4 million tonnes of CO2 per year (90%) from NRG's WA Parish 240 MWe power plant and use it for enhanced oil recovery. In a post-combustion process the flue gas is cooled and the CO2 removed by amine scrubbing. The CO2 is released from the solvent with low-pressure steam. The Petra Nova Parish plant started up late in 2016 on time and on budget, and is the largest post-combustion carbon capture project installed on an existing coal-fuelled power plant.
By April 2017 it had delivered 300,000 tonnes of CO2 through a 30 km pipeline to the West Ranch oilfield to increase oil production from 300 to 15,000 barrels per day. The system captures more than 90% of carbon emissions from a 240 MW equivalent stream of flue gas, and is rated at 4,776 tonnes of CO2 captured daily, effectively 1.4 million tonnes per year. The plant is reported to cover costs through the economic benefit of enhanced oil recovery. The $1 billion plant was financed with loans from the Japan Bank for International Cooperation and Mizuho Bank, supported by Nippon Export and Investment Insurance. The project also obtained $167 million in grants from the US DOE’s Clean Coal Power Initiative program.
Summit Power Group's Texas Clean Energy Project (TCEP) at Penwell is a 377 MWe IGCC power plant burning coal with CCS, capturing 90% of CO2 and 90% of NOx. It has $450 million funding from the DOE Clean Coal Power Initiative towards its $2.4 billion cost. It was due to operate from 2015, but construction start is not yet in sight. Of the approx 2.9 million t/yr of CO2 captured, 83% will be used for enhanced oil recovery in the West Texas Basin. Of the 377 MWe, 106 MW will be used to run the major project equipment on site, 16 MW will be used to compress CO2, and 42 MW will be used to produce urea, leaving 214 MWe for the grid. In December 2015 Summit signed an engineering, procurement and construction (EPC) contract with China Huanqui Contracting & Engineering Corporation (HQC), a subsidiary of China National Petroleum Corporation (CNPC), and SNC-Lavalin.
Mississippi Power and Southern Company's Kemper County Energy Facility in Mississippi was due to start up in 2016, but costs have blown out from $2.9 billion to over $7.5 billion. In June 2017 the company suspended start-up and operations activities involving the lignite gasification portion of the project in response to an order from the Mississippi Public Service Commission to remove financial risk to ratepayers over “unproven technology”. Though the company said that the lignite gasification part of the plant worked, the combined-cycle plant is being fully converted to operate using natural gas, as it has been for over two years, and the Mississippi Public Service Commission will relicense it accordingly. The plant aimed to gasify lignite using two transport integrated gasification (TIG) units and burn the syngas, principally hydrogen, using IGCC to generate 582 MWe of electricity, then capture 65% of the CO2 – 3 Mt/yr – which would be sold for enhanced oil recovery. Southern Company planned to pass on $4.2 billion in costs to (its subsidiary) Mississippi Power ratepayers, but in mid-2017 announced that it would absorb $5.87 billion in losses on the project. The lignite gasification plant is not expected to be competitive with gas prices below $5 per million BTU.
Net Power, backed by Toshiba, Exelon and others, has started to construct a 50 MWth plant in La Porte, Texas in March 2016 with oxy-fuel combustion of natural gas and recycled CO2 driving a turbine (Allam cycle) so that the plant produces only electricity, water and pipeline-ready CO2. Net Power stated in May 2018 that the project achieved first firing of a commercial-scale combustor made by Toshiba Energy Systems & Solutions. The companies are aiming to develop larger 300-MWe commercial-scale plants by 2021.
In Canada, a 110 MWe coal-fired plant is the world’s only commercial-scale CCS power station, operating from early 2015. SaskPower’s Boundary Dam unit 3 plant came online in October 2014. Prior to upgrading it at a cost of C$ 1.47 billion, with C$ 900 million of this for the CCS system, it operated at 139 MWe and released 3604 t CO2 per day. It now releases 354 t/day, so captures about 90%, more than one million tonnes per year. However, SaskPower is not installing CCS on units 4&5.
The Quest project in Canada’s oil sands commissioned in 2015 captures up to 1 million tonnes of CO2 per year from hydrogen production at the Scotford Oil Sands Upgrader for storage at a depth of about 2 km in an onshore saline aquifer.
Europe
In 2007, EU leaders endorsed a European Commission plan for up to 12 CCS demonstration power plants by 2015. In mid-2017 there are no such plants, nor any plans. CCS was also promoted by the International Energy Agency (IEA) and the Intergovernmental Panel on Climate Change (IPCC) as a promising means of transition to a low-carbon economy.
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