HomeCoal FiredDriving a low-carbon path for North American power

Driving a low-carbon path for North American power

Canada's Boundary Dam is the first commercial-scale post-combustion CCS process on a coal-fired power plant
Canada’s Boundary Dam is the first commercial-scale post-combustion CCS process on a coal-fired power plant
Credit: Sask Power

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A confluence of factors is driving the North American power sector down a low-carbon road. Responding to customer demands, OEMs are expanding the capabilities and material composition of their products in order to meet efficiency demands and develop a new generation of technologies, finds David Appleyard

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Although the US lags behind Europe’s policymakers in efforts to address carbon emissions from the power sector, under the Obama administration the Environ-mental Protection Agency (EPA) has moved to tackle carbon dioxide output from electricity generation.

In June the EPA issued a proposal for a so-called Clean Power Plan, under which guidelines will be set for states in order to address greenhouse gas emissions from existing fossil fuel-fired generation assets. Reflecting that different states have different mixes of sources and opportunities, the EPA plans to deliver state-specific, rate-based goals for CO2 emissions from the power sector.

Currently under consultation, a final ruling on the plan is due in June 2015. States are now attempting to identify a path forward using either current or new electricity production and pollution control policies to meet the proposed programme’s goals. These plans are due in June 2016, though under some circumstances states will have until 2018 to deliver their proposals.

Power plants account for roughly one third of all US greenhouse gas emissions and while there are limits in place for emissions of pollutants such as arsenic, mercury, sulphur dioxide, nitrogen oxides and particulates, until recently the US has been largely resolute in its rejection of constraints on carbon emissions.

However, in June 2013 President Obama issued a presidential memorandum directing the EPA to complete greenhouse standards for the power sector under the auspices of the Clean Air Act.

As a result, by the time the proposed plan is fully implemented in 2030, the EPA aims to cut carbon emissions from the power sector by 30 per cent below 2005 levels nationwide, as well as cut particulates, nitrogen oxides and sulphur dioxide by more than 25 per cent as a coincidental benefit.

This, says the EPA, will avoid up to 6600 premature deaths annually and provide up to $93 billion in climate and public health benefits. Simultaneously, the agency expects the measures to reduce electricity costs by roughly 8 per cent through increasing energy efficiency.

Ravi Krishnan, founder of global marketing and strategy consultancy firm Krishnan & Associates, highlights the policy context for the US, but also the challenging market structures which have existed to date, saying: “The US market was obviously expecting some future CO2 emission norms for power plants. However, there were no monetization mechanisms such as a national cap-and-trade system, penalties, tax credits or subsidies for power producers to avail themselves of. Therefore, unlike Europe, there are fewer pre-combustion, post-combustion or advanced combustion technologies being demonstrated in the USA.”

Certainly, the nation appears to be making up for lost time. Measures to address emissions from existing generating facilities follow proposals announced in September 2013 that set emissions standards for new-build projects, a plan also developed under Obama’s Climate Action Plan.

Under this proposal, new large natural gas-fired turbines are limited to 1000 pounds of CO2 per MWh (about 450 kg/MWh), while new coal-fired units would need to meet a limit of 1100 lb/MWh.

However, the American Coal Council (ACC) said the EPA’s revised carbon pollution standard for new power plants sets an emissions limit for coal “that cannot be met given current technology. Thus, the practical effect of such a rule would be to stop the construction of any future coal-fuelled generation capacity in the US.”

This is a point echoed by Krishnan, who says: “The US is moving away from coal and it is unlikely that any new supercritical or ultra-supercritical power plant will be built in the future.”

Building on market trends

The EPA’s guidelines for existing facilities build on trends already underway in the power sector that are resulting in a cut in carbon intensity, both from existing power plants and across the evolving generation portfolio as a whole.

As part of the proposed measures, the EPA offered four ‘building blocks’ that it believes are central to state measures to achieve portfolio-level reductions in carbon intensity. The EPA identifies measures to make existing fossil-fuelled plants more efficient and suggests despatching lower-emission sources, such as natural gas, more often.

In particular, the emergence of cheap and abundant shale gas has seen the marginal cost of coal-fired capacity become increasingly uncompetitive.

Scott Nolen, Global Technical Solutions Leader at GE Power & Water’s Distributed Power business, highlights the impact of shale gas on cutting US carbon emissions: “The most remarkable thing is the transformation of the generation mix in the US driven by economic forces. The dynamism of the US oil and gas industry has created a great reduction in power generation from coal, and the generation mix has seen the biggest benefit in terms of carbon footprint and that’s driven just by economic forces.” As a recent example, Nolen cites the hub pricing for gas outside New York City, where the natural gas price went to $1.70 per million BTU. “There is no way coal can compete with that; it’s due to this tremendous amount of supply that’s driven that change,” he says.

The Petra Nova Carbon Capture Project is expected to capture 90 per cent of the CO<sub>2</sub> in the processed flue gas from an existing unit
The Petra Nova Carbon Capture Project is expected to capture 90 per cent of the CO2 in the processed flue gas from an existing unit
Credit: NRG

Carbon capture and storage

Don Ryan, who manages the advanced technology group at Babcock & Wilcox Power Generation Group, explains that setting carbon emission limits for coal-fired plants only marginally above the demonstrated emissions from a gas turbine combined-cycle plant makes carbon capture and storage a mandatory element for new coal-fired capacity in the US. “Where we see the regulations for new units is that, even with the best-available, highest-efficiency boiler and steam turbine technology, you would need partial carbon capture to get to the EPA limits,” he says.

The best coal-fired technology on the market right now features ultra-supercritical steam conditions with pressures in the 3700-4000 psi range and steam temperatures of 1110-1130oF. However, as Ryan explains: “That doesn’t get you down to the CO2 emission level of a gas turbine combined cycle without the addition of carbon capture to a coal-fired boiler.”

As a result, North America has seen some recent advances in CCS technology. Indeed, NRG’s carbon capture business recently broke ground on a 240 MW project at Unit 8 of the 610 MW WA Parish power plant in Fort Bend County, southwest of Houston, Texas.

The WA Parish Petra Nova Carbon Capture Project is a commercial-scale system that is expected to capture 90 per cent of the carbon dioxide in the processed flue gas from an existing unit. When complete in 2016, the project is expected to be the world’s largest post-combustion carbon capture facility installed at an existing coal plant.

In October, NRG announced that the majority of the excavation needed to begin building was complete, allowing drilling of the approximately 800 piles that will serve as the plant’s foundation to begin. NRG has formed a 50/50 joint venture with JX Nippon Oil & Gas Exploration Corp to build and operate the Petra Nova Carbon Capture Project.

The captured CO2 will increase oil production at the West Ranch oilfield some 130 km away, jointly owned by Petra Nova and Hilcorp Energy Co. Enhanced Oil Recovery (EOR) is expected to boost oil production at the field from around 500 barrels per day (bpd) to approximately 15,000 bpd. A US Department of Energy grant of up to $167 million has been awarded to the $1 billion project as part of the Clean Coal Power Initiative (CCPI) programme while additional funding will come from loans of $250 million and equity contributions from both NRG and JX Nippon.

The project will be constructed under a fixed-price contract by a consortium composed of Mitsubishi Heavy Industries Americas and The Industrial Company using the KM-CDR Process jointly developed by MHI and Kansai Electric Power Co.

October also saw the official inauguration of SaskPower’s Boundary Dam project, claimed as the world’s first post-combustion commercial-scale CCS process on a coal-fired power plant.

Located in Estevan, Saskatchewan, Canada, the C$1.4 billion ($1.25 billion) rebuild project at Unit 3 of the 824 MW coal-fired power plant generates 110 MW. CCS will reduce carbon emissions by 90 pe cent and, when fully optimized, the process will capture up to one million tonnes of carbon dioxide annually. The captured CO2 will be used for EOR. Babcock & Wilcox Canada was engineer, manufacturer and constructor of the critical components to retrofit the boiler under a $107 million contract.

The government of Saskatchewan invested C$240 million in the demonstration project. Canadian economy minister Bill Boyd noted: “This project is important because it is applicable to about 95 per cent of the world’s coal plants.” Likewise Luke Warren, chief executive of the Carbon Capture and Storage Association, commented: “It is hoped that Boundary Dam will form part of a much-needed commercial proof point that the economics make sense.”

However, the economics of CCS technology are still tenuous, as Krishnan explains: “Future development of CCS technology will depend on its cost, CO2 transport and storage mechanisms, natural gas prices, regulatory factors and the monetization of CO2 emissions. Presently the CAPEX of CCS projects and technology solutions is extremely high.”

This is a point echoed by B&W’s Ryan, who notes that the FutureGen research project on oxy-fired combustion, being developed in the US state of Illinois, has been delayed by the challenges of raising commercial finance. The project’s total capital cost (planning, design and construction) is approximately $1.65 billion, of which DOE will contribute $1 billion and the private sector will contribute the remainder.

Says Ryan: “There’s a piece of the funding that the equipment suppliers are putting into it, the US DOE are putting into it and there’s a piece that we needed to go out to commercial financial institutions. It’s been delayed due to working out the terms with the commercial financing institutions to get the last piece of funding.”

The FutureGen Industrial Alliance was formed to partner with the DOE on the FutureGen 2.0 project to retrofit an existing plant. Construction was due to begin on both the plant and the CO2 pipeline and storage facility in 2014, with commercial operations originally scheduled for autumn 2017.

As Ryan says: “They’re expensive projects and you have to build pilot and demonstration plants to get everyone comfortable that they can add this technology to their plant.” He adds: “We’ve been pleased with the DOE support. They are seeing this to be the future of coal-fired generation.”

An alliance between commercial and state parties is also behind Canada’s Canmet advanced coal-firing research project. Between 1993 and 1995, CanmetEnergy invested over C$4 million in building the world’s first advanced oxy-fuel combustion pilot-scale research facility. Since its commissioning in 1995, CanmetENERGY’s CO2 R&D Consortium is now in Phase 9, which is developing a CO2 capture and compression unit.

Gas-fired generation and flexible reciprocating engines are increasingly economically attractive
Gas-fired generation and flexible reciprocating engines are increasingly economically attractive
Credit: GE

Challenging economics

But even with government support, the economics of CCS can be challenging. For example, in late September Leucadia National Corporation announced that it had decided not to proceed with further development of the greater Lake Charles project based on “final estimates of the likely ultimate cost”.

The decision came despite a December 2013 announcement from the DOE that it would support the project to the tune of $261.4 million under its Industrial Carbon Capture Sequestration (ICCS) programme. The petcoke-fired gasification plant was to transport the CO2 to the West Hastings oil field for use in EOR. The estimated total cost of the Lake Charles CCS project was $435.6 million.

The CCS project was to include two Lurgi Rectisol Acid Gas Removal (AGR) units and was designed to capture approximately 89 per cent of the CO2 produced.

Nonetheless, there are efforts to further commercialize CCS technology in the US. In April SaskPower and Vattenfall signed a five-year agreement to explore opportunities for collaboration on CCS knowledge and technologies. More recently, Shell Cansolv, the subsidiary of Royal Dutch Shell behind the technology used at Boundary Dam, agreed a deal with Technology Centre Mongstad (TCM) in Norway for further testing of the CO2 capture process. The testing was scheduled to start in the third quarter of this year and will last for approximately five months.

Given the challenges of developing economically viable CCS technology – it is no coincidence that the projects that have been developed in North America to date are based at older coal-fired plants and coincide with opportunities for EOR – the opportunities for carbon reduction are based on alternative approaches. As Krishnan explains: “Given the early-stage development of the affordable large-scale carbon capture technologies and associated high CAPEX of transportation and storage, I believe that the industry will focus on increasing efficiency by innovative equipment upgrades, best practices and switching to currently abundant natural gas.”

He continues: “The new EPA carbon pollution emission guideline for stationary sources will obviously result in new innovative approaches outside of CCS to meet the proposed targets. Power producers will seriously look at increasing the efficiency of fossil fuel power plants through upgrading technologies. Switching to coals that will improve the heat rate of the units and reduce its utilization will also be employed.”

Krishnan concludes: “In recent years, marginal or inefficient coal-fired power plants have been under tremendous pressure to lower their cost of generation to improve the despatchability of their units. As a result, several innovative boiler efficiency improvement technologies through retrofits, combustion controls and fuel switching have been incorporated. These strategies have resulted in some modest improvement in CO2 emissions.”

Ryan highlights the focus on more efficient combustion technologies: “About two years ago we were fortunate to get a contract with AEP to build the first [US] ultra-supercritical unit which is in the just-under-4000 psi steam pressure range, but the steam temperatures are up to the 1100-1150 range. That gave a 5 per cent to 6 per cent improvement in heat rate over the traditional supercritical cycles.” He adds: “We’re involved in a consortium of companies here in the US to develop advanced supercritical technology. That is pushing the steam pressures up to 5000 psi at the turbine inlet.”

He points out the challenges of materials development in achieving these steam conditions, saying: “The single biggest area we’re working on now is to make sure we understand the properties of the material, that it’s going to withstand those pressures and temperatures, have the life expectancy that utilities like to see, and be able to fabricate and repair the material in the field. We’re in the process of designing a small test facility to actually run some components at the same steam temperatures. We expect that to be done next year, and then another year or two from there we will have the ability to test some of these components.”

Michael Gradoia, Manager of Power Generation Product Marketing for GE Power and Water, also highlights the challenges of reducing carbon intensity with power generation products. He says: “Gas turbine efficiency is primarily a function of firing temperature and compressor pressure ratio. There is a need for materials that can withstand those higher temperatures, and cooling technologies that allow you to reduce the amount of air used for cooling that is therefore not used for power.”

For example, GE’s latest products, the HA gas turbines, utilize single crystal alloys in the turbine section. Illustrating the challenges, Gradoia adds: “When looking at a turbine section, there are components that are operating at about 400 degrees above the melting point of the base metals, and advanced coatings and cooling technologies are what enable that part to do its job while providing a reliable service life.”

On improving the efficiency of existing coal-fired assets, Gradoia says: “We can help enhance the efficiency of existing units by retrofitting the steam turbines with the latest blading and sealing technology.”

Similarly, B&W is looking at developing technologies and techniques to enable units to operate more efficiently at reduced load.

The US low-carbon future

More than 25 US states have already set energy efficiency targets, and more than 35 have set renewable energy targets. Meanwhile, it is evident that the DOE will pursue additional constraints on carbon.

Ryan says: “In terms of where we think it’s going at some point down the road, it’s hard for me to imagine that higher levels of carbon capture, up to and including 100 per cent, aren’t going to be required.”

He concludes: “I think it’s a matter of time, we just have to keep working on development and getting it to a commercial state.”

David Appleyard is a freelance journalist focused on the energy, technology and process sectors.

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