To be a relevant player in the future power mix, coal power efficiency and costs must improve, and technologies in the realm of research and development promise to do just that.
Although most experts agree that coal will remain a dominant source of fuel for baseload power over the near-term in several regions, the coal power sector’s struggle to remain economically relevant in the face of serious market disruptions and environmental concerns has been widely chronicled. The industry’s response to the myriad issues affecting the sector have been multi-pronged. Common approaches implore action on regulatory reform or seek recognition of the existing coal fleet’s contribution to energy reliability and security.
Of late, many stakeholders are also strengthening calls for increased investment in coal generation technology through research and development (R&D), demonstration, and deployment. In early October, for example, recommendations endorsed by the National Coal Council, a U.S. nonprofit organization that serves as an advisory group to the Energy Secretary, urged more investment in technology to achieve a lengthy list of objectives.
Across the world, gains promised by technological advancements are as widely sought, said Dr. Lesley Sloss, an expert at the Clean Coal Centre, a technology collaboration the International Energy Agency (IEA) established in 1975 to provide independent information on how coal can balance the “energy trilemma” of security of supply, affordability, and environmental issues. “The move to more efficient and cleaner production of power is a universal goal,” and governments and industry stakeholders want to “ensure that the coal power generation systems of the future are high-efficiency, low-emissions [HELE] technologies,” she explained.
But Sloss, who is preparing a detailed report for the center on the technology readiness of advanced coal-based power generation systems (that will be published in early 2019), cautioned the success of current and future energy projects will largely be determined by how they fit into prospective new energy mixes. “For the most part, those systems, which offer flexibility, reliability, and the use of indigenous fuel supplies whilst helping to mitigate CO 2 emissions, will be at a distinct advantage,” she said. Today, several technologies are emerging that fit many sought-after characteristics: They can use coal, frequently of low quality, to produce flexible power and/or alternative chemical products and often have a capacity for carbon capture and storage (CCS). “However, whilst these technologies would indeed be in demand, if available, many are at the developmental stage and, as such, may be considered expensive or risky investments,” Sloss said.
Potential at Existing Coal Power Plants
In their fifth fossil energy technology “roadmap” issued in July 2018, the nonpartisan U.S.-based Electric Power Research Institute (EPRI) and the Carbon Utilization Research Council (CURC, an industry coalition focused on technology solutions to keep fossil fuels in a “balanced” U.S. power portfolio) identified several technologies that could help coal be cost-competitive with other sources of electricity under future market conditions between 2025 and 2035. The identified technologies “are readying for large-scale pilot testing and a few are preparing for commercial demonstration,” the joint initiative noted.
Water Technologies. By 2020, the roadmap suggests advancements should be achieved for near real-time process monitors/analyzers for trace metal concentrations used in wastewater treatment systems, along with pilot project testing for flue gas moisture recovery technologies, advanced hybrid-cooled, and direct air-cooled technologies. By 2025, gains may be made in advanced hybrid cooling, as well as for water management with improved pre-treatment, advanced membrane and/or thermal treatment system, and encapsulation of wastewater and pollutants by solids fixation and stabilization.
Materials. Development and research to improve fabrication and repair of advanced, high-temperature tolerant, and stronger materials is ongoing and could be achieved by 2035.
Flexibility. “Flexibility is so important that every program in EPRI’s Generation Sector is examining it in some way,” noted EPRI Senior Program Manager Mike Caravaggio in July. EPRI is exploring novel treatments that produce protective coatings for components, attempting to improve boiler life and availability, investigating how to better manage fatigue, and studying steam flow. By 2020, integrated instrumentation and control approaches, flexible operations simulators, and improved pollutant control systems (capable of flexible operations), should be available, the CURC-EPRI Roadmap suggests. And by 2025, a large pilot using “advanced flexible operation technology” could be underway. Efforts are also underway to improve reliable operation for units operating in “cycle mode” by developing improvements in welding and component fabrication using new materials, and by providing improved diagnostic techniques, including better sensors and controls for early identification of wear-and-tear problems.
Advanced Ultrasupercritical System Advancements on the Horizon
About 250 GW of ultrasupercritical capacity is currently online—90% (224 GW) is in Asia (where another 88.2 GW is under construction, mostly in China and Japan), and most of the remaining 10% is in Europe (19.2 GW)—and efficiency improvements continue, as Dr. Andrew Michener, general manager of the IEA’s Clean Coal Centre, noted in November. The Waigaoqiao No. 3 ultrasupercricital plant in Shanghai, China, for example, increased its original efficiency from 43% to more than 47%, “which is a tremendous achievement,” Minchener said. Meanwhile, testing is underway on nickel superalloys that could help achieve the 700C steam target in advanced ultrasupercritical (AUSC) systems (Figure 1)—and boost efficiency to beyond 50%—in the U.S., Europe, Japan, and China; and India has committed “significant funding” to AUSC technology.
|1. “The efficiency increases result from increasing the steam temperatures from subcritical process—where the maximum steam temperature would be 540C—to a supercritical system—where we’d be looking at right about 580C maximum—to ultrasupercritical, which is the state-of-the-art at present, where we’d be looking at 620C, maybe towards 640C; and then advanced systems, which are still at the development and demonstration stage, where we are looking at steam temperatures of about 700C or higher in some cases,” explained Dr. Andrew Minchener, general manager of the International Energy Agency’s (IEA’s) Clean Coal Centre. The global average efficiency of coal power plants is about 35%, he noted. Courtesy: IEA Clean Coal Centre, “HELE Coal Power Plants Worldwide,” November 14, 2018|
Research gains are already making their way to market. GE’s new SteamH technology, for example, uses nickel superalloys, including HR6W and Inconel, in its commercially available 650C–670C system. GE says the technology is capable of a 49.1% (net) efficiency, and so far, at least two companies that are pioneering AUSC projects have selected its SteamH offerings: Yildirim for its 2 x 800-MW Karaburun Imported Coal Project in Turkey, and Huaibei Shenergy Power Generation Co. for its Pinghsan II plant.
However, according to Sloss, advancement of AUSC still poses challenges. “The advanced metals and alloys required to cope with the stresses of high-temperature and -pressure combustion are becoming available, but for utilities to invest in a full-scale plant, further testing and proof of suitability and reliability is required,” she said. Still, the CURC-EPRI Roadmap anticipates that a large-scale AUSC demonstration plant, either greenfield or retrofit, with steam temperatures of 760C could be operational by 2025, and a commercial plant online by 2035.
New Inroads for Gasification?
A handful of commercial plants worldwide already employ processes to gasify coal and produce a syngas that can be burned in a combustion turbine coupled to a combined cycle steam turbine for power generation—or integrated gasification combined cycle (IGCC). “This type of system can work with a large range of coals, including low-quality coal and lignites; it has lower water usage than most conventional plants, and the gas that’s produced at the end is relatively clean and suitable for a bit of processing to get it ready for CCUS,” said Sloss. “However, the majority of demonstrations have proven expensive and problematic.”
Meanwhile, most new projects in the proposal or developmental stages are currently delayed or on hold. Of 20 IGCC projects proposed in 2013 for China, only three appear to be moving forward, Sloss said, noting that IGCC’s “teething issues” indicate steep cost reductions must be achieved. “Advantages of IGCC are often considered not sufficient enough to offset the increased cost and risk.” IGCC’s key advantage over state-of-the-art ultrasupercritical technology is its suitability for CCUS, but addition of carbon capture technologies could decrease net IGCC efficiency by 7% to 11%, she said.
Among other components that could benefit from technology innovations are air separation units (which get oxygen to the combustion zone), which are both costly and can be a significant source of parasitic power. Efforts also continue to upgrade gasifier systems for hot-gas cleanup, corrosion reduction, and advanced turbines, she said.
Concerted efforts in Asia to improve IGCC “could help pull this technology out of the ‘Valley of Death,’ ” which Sloss describes as the treacherous area between demonstration and commercial deployment in which technology becomes mired because it is too problematic or expensive for investors to consider. R&D also continues on polygeneration, which provides flexibility owing to its capacity to produce chemicals as well as power, and small-scale demonstrations are underway in Germany and Poland. However, polygeneration’s success will depend on the right market that will reward both dispatchable power and production of chemicals, Sloss said.
Oxyfuel Combustion Gains Steam
More than 15 small-scale projects to pilot or demonstrate oxyfuel combustion have been carried out since 1980, but the process to remove nitrogen from air cryogenically and perform the combustion of fossil fuels with oxygen and recycled flue gas hasn’t taken off, despite its promise. The CURC-EPRI Roadmap notes the approach “results in higher efficiency from latent heat recovery from the flue gas at a temperature useful to the cycle and reduced auxiliary power; potentially lower capital costs due to smaller equipment; and a flue gas that allows easier capture of CO 2 for use or sequestration.”
Sloss attributes the technology’s slow uptake to a “lack of funding” in the U.S. and UK. In China, hurdles have “more to do with the perceived risk of projects,” she said. These include complexity, high costs, and power demands of gas processing systems, including for the air separation unit and the CO 2 processing unit, she noted. Research with wide potential continues. The U.S. Department of Energy (DOE), for example, recently awarded San Antonio–based Southwest Research Institute (SwRI) $1 million to pursue a large pilot design that will integrate flameless pressurized oxy-combustion technology into a 50-MW pilot power plant. Phase 1, during which researchers will collect environmental information and secure a site, is slated to be wrapped up in July 2019.
Chemical Looping Combustion Pushes Forward
Chemical looping combustion (CLC) technology typically includes two fluidized-bed reactors and uses metal oxide or limestone as a carrier that is oxidized in an air reactor and then delivers oxygen for fuel combustion in the fuel reactor—and its key benefit is that it efficiently produces oxy-combustion without cryogenic air separation.
While the CURC-EPRI Roadmap envisions a first-of-a-kind commercial project starting in 2027, Sloss noted that the technology is still in the “theoretical stage,” though promising developments could result in major gains over the next decade. Japan is looking to establish its CLC technology, which has a target net thermal efficiency of 46% with CO 2 capture, for plants of between 100 MW and 500 MW by 2030. Babcock and Wilcox is also working to complete a feasibility study of a 10-MW direct CLC pilot plant at the Dover Light and Power facility in Dover, Ohio, which could be operational by 2020.
A Buzz Around Supercritical CO 2 Power Cycles
Two versions of supercritical CO 2 power (sCO 2) cycles have garnered much interest of late: an indirect-fired version that obtains heat in the conventional way from a combustion process via a heat exchanger for a sCO 2 power island, and a direct-fired version that uses oxy-combustion within the cycle to generate a sCO 2 and water stream that drives a power turbine. Both processes use sCO 2 as a working fluid as well as more compact turbomachinery (due to the high power-density of CO 2), which can lower plant capital costs. Additionally, the technologies offer higher net plant efficiencies than conventional power cycles. And they can both capture carbon: indirect cycles can do post-combustion carbon capture or oxy-combustion, and direct cycles inherently create a stream of CO 2 at pipeline pressure for use or sequestration.
The CURC-EPRI Roadmap is optimistic that a large-scale demonstration of an indirect-fired sCO 2 system for coal will be operational by 2035. Some key projects are underway. Armed with DOE funding, Echogen Power Systems, Siemens, and EPRI are teaming to develop a large-scale coal-fired sCO 2 pilot plant, though the details of what that project entails and when it will begin are unclear. This October, meanwhile, SwRI, along with the Gas Technology Institute, GE Global Research, and the DOE, broke ground at the 10-MW Supercritical Transformational Electric Power pilot plant that will reportedly use a GE-developed “desk-sized” sCO 2 turbine (Figure 2).
|2. The Supercritical Transformational Electric Power (STEP) pilot plant, which broke ground on October 15, 2018, is a $119 million first-of-its-kind 10-MW supercritical carbon dioxide (sCO2) facility. Because of the efficiency of sCO2 as a thermal medium, STEP turbomachinery can be one tenth the size of conventional power plant components, providing the potential to shrink the environmental footprint as well as the construction cost of any new facilities. A model “desk-sized” sCO2 turbine, which can power 10,000 homes, is shown here. Courtesy: Gas Technology Institute|
Meanwhile, the University of North Dakota Energy and Environmental Research Center is also leading a project to build a direct-fired sCO 2 cycle pilot plant, which would further technology development of the coal-based Allam Cycle. The fairly new Allam Cycle is the basis of NET Power’s much-watched 25-MWe (50-MWth) natural gas–fired demonstration under construction in La Porte, Texas, a project that could be operational by 2020 and promises an efficiency of about 58%. However, as Sloss noted, customizing the Allam Cycle for coal could require “bolting on of a gasification plant to produce syngas,” which exposes it to similar risks faced by gasification technologies. “The biggest challenge is going to be the advanced recuperative gas turbines and the heat exchangers,” she added.
Coal-Based Systems Integrated with Fuel Cells
The advent of utility-scale gas-fired fuel cell power plants, like the 2014-opened 59-MW Gyeonggi Green Energy molten carbonate fuel cell park in South Korea, are helping to spur fuel cell technology forward. The use of solid coal in fuel cells is “currently at bench scale,” Sloss said, adding, however, that integrated gasification fuel cell (IGFC) systems “show the most promise.” The technology essentially integrates a coal gasification process with high-temperature fuel cells to create ultra-high-efficiency, low-emissions power generation systems. Experts note a simple IGFC system is similar to an IGCC system, but the gas turbine power island is replaced by a fuel cell island.
The first IGFC demonstration plant with CCS is currently under development in Japan and could be operational by 2021. Launched in April 2012, the IGFC project at the 166-MW Osaki CoolGen IGCC plant (Figure 3) is funded by Japan’s New Energy and Industrial Technology Development Organization and run by Osaki CoolGen Corp. (a joint venture of J-POWER and the Chugoku Electric Power Co.). Osaki CoolGen is seeking to demonstrate IGFC with CO 2 separation and capture technology in three stages: verification of scaled-up EAGLE gasification technology; additions of carbon capture equipment to the IGCC system; and incorporation of the fuel cell system. The goal is for the IGFC system to have an efficiency of 55%.
|3. The Osaki CoolGen oxygen-blown integrated gasification combined cycle project in Hiroshima, Japan, began operating in 2016. The project is now integrating a carbon capture system, and by 2021, it seeks to demonstrate a coal system integrated with a fuel cell system. Courtesy: Osaki CoolGen Corp.|
However, Sloss noted, “moving to test and pilot scale of these IGFC systems is dependent on the success of the current IGCC plants on which they will be based; IGFC systems are extremely expensive to build and risky, considering the technology is so new.” Still, she added, “By switching IGCC plants to IGFC, significant costs will be offset and should also offer the potential for the plants to revert to IGCC should the IGFC process prove untenable.” ■
—Sonal Patel is a POWER associate editor.