New coal-fired generating plants are not showing up in the U.S. Elderly plants are retiring in large numbers. But other parts of the world continue to develop coal generation. Advances in combustion and emissions cleanup are part of the reason.

Battered in the U.S., coal is holding its own in the rest of the world. That’s the finding in the latest BP Statistical Review of World Energy, a highly-regarded annual assessment of global energy. BP analyst Spencer Dale said, “Coal consumption increased by 25 million tonnes of oil equivalent (mtoe) since 2013. Consumption growth was driven largely by India (18 mtoe), with China consumption also up slightly (4 mtoe) following three successive annual declines during 2014–2016.”

While burning coal to generate power has well-known environmental issues—conventional pollutants such as sulfur dioxide, oxides of nitrogen, and mercury, as well as new concerns about carbon dioxide and global warming—advanced coal technologies, both on the combustion side and with emissions controls, suggest that coal-fired generation is far from doomed.

Ultrasupercritical and CFB Technology

In much of the world, including most of Asia, advanced coal technologies—ultrasupercritical combustion, circulating fluidized bed (CFB) combustion, and coal gasification—have been the focus. In the U.S. and much of the developed world, the target for advanced coal has been removing CO 2 from flue gas, either from conventional technology or coal gasification.

Ultrasupercritical and CFB technologies also play a role in reducing CO2 emissions. They increase the efficiency of the plant, meaning more power for a given amount of coal. The U.S. focus on carbon capture (and storage either for use in enhanced oil recovery, or sequestered in geologic repositories on land or deep under the sea) targets CO2 directly.

A paper from the Department of Energy’s (DOE’s) National Energy Technology Laboratory lays out the advantages of ultrasupercritical coal plants. “Increasing the temperature and pressure of steam improves the efficiency of boilers and turbines that use steam as a working fluid. These higher efficiency boilers and turbines require less coal and produce less greenhouse gases.” Ultrasupercritical boilers produce steam in the 1,200F to 1,400F range, compared to about 1,100F in supercritical plants.

The National Coal Council, a DOE advisory group, says, “As steam pressure and temperature are increased above 3,208 psi and 706F, the steam becomes supercritical; the water and steam form a single-phase mixture,” producing significantly increased efficiency. A typical subcritical coal-fired steam electric plant in the U.S. operates at about 32% efficiency, according to the coal council.

Two years ago, the Power Technology website reported, “General Electric (GE) is pioneering ultrasupercritical technology at the RDK 8 coal-fired power plant in Karlsruhe, Germany, with considerable success. Operated by German utility EnBW, the plant achieves 47.5% net thermal efficiency while producing 912 MW of electricity, making it one of the world’s most efficient hard coal-fired steam power plants.”

Fig 1_Isogo coal plant

1. High efficiency, low emissions. The Isogo Thermal Power Station’s ultrasupercritical 600-MW Unit 2—located in the heart of Tokyo Bay, Japan—is equipped with regenerative activated coke technology, or ReACT, helping it achieve very low emissions rates. Courtesy: J-POWER

Meanwhile, Denmark’s Nordjylland power station Unit 3, owned by Vattenfall, reported net electrical efficiency of 47%. Unit 2 at the Isogo station near Yokohama, Japan, reached 45% efficiency (Figure 1). “Combined,” said Power Technology, “the facilities emit 50% less sulfur, 80% less nitrogen, 70% less particulate, and 17% less carbon dioxide than the previous subcritical units.”

This summer, GE announced it will provide the boiler and steam turbine for Pakistan’s first ultrasupercritical plant near Karachi. The 660-MW Luck Electric plant is expected to come online in 2021. It will burn local lignite. GE’s Sharim Sheikh, chief executive for Pakistan, Iran, and Afghanistan, said the plant “also helps to lower emissions. The turbines will generate up to 660 MW to help the country bridge the gap between electricity demand and available supply.”

CFB technology is also making a place for itself, particularly in China. Fluidized bed combustion technology has deep roots going back to the 1960s. Over the years, the technology has evolved. A recent article in the journal Clean Energy notes that the technology is well-suited to a wide variety of coals, including low-grade coal with high ash content. That describes China’s diverse domestic coal supply. “By 2016,” the article reports, “over 3,000 CFB boilers were in commercial operation with a total installed capacity of over 90,000 MW among which over 100 units are 300 MW.”

The Clean Energy article said, “CFB technology has developed rapidly in recent decades due to its fuel flexibility, effective NO x formation control and high-sulfur capture efficiency.” Recently, Chinese researchers “developed a new 600 MW supercritical CFB boiler,” which went into service in Sichuan Province in 2013.

Carbon Capture and Coal Gasification

In the U.S. and Europe, the aim of advanced coal technology has been to capture and store CO2 from flue gases, and coal gasification, sometimes together and sometimes separately. So far, the record has not been good.

U.S. government-funded projects have aimed at gasifying coal, burning the synthetic natural gas in combined cycle plants, and capturing and storing the CO2. Also, the DOE has supported projects aimed at burning coal conventionally, then capturing the carbon emissions for storage or use in enhanced oil recovery. Both thrusts have resulted in spectacular, multi-billion-dollar failures. Still, the private sector and government are moving ahead to try to tame this technological tiger.

Fig 2_Kemper County IGCC

2. Kemper County energy facility. Originally designed as an integrated coal gasification combined cycle power plant, Mississippi Power suspended operations and startup activities on the gasifier portion in June 2017, choosing instead to operate the facility as a natural gas plant. Courtesy: Mississippi Power

Southern Co., the giant investor-owned utility holding company based in Atlanta, Georgia, undertook the most ambitious project to advance new coal technology through its Mississippi Power subsidiary. The Kemper County project—gasification of local lignite, a combined cycle gas generating project, and carbon capture and storage to supply enhanced oil recovery—was planned in 2006 and started construction in 2010. The initial cost estimate for the 582-MW generating plant (Figure 2) was $2.4 billion, with an in-service date projected for 2014.

After years of cost overruns and schedule delays, the utility suspended the gasification portion of the project in 2017. Costs ballooned to more than $7 billion. Mississippi regulators pulled the plug. Southern Co. shareholders ended up eating $6.4 billion in losses. The DOE, starting in 2006, funded the project with more than $500 million.

Coal Gasification Isn’t New

Coal gasification has been in use for more than a century. In the U.S. in the 19th and early 20th centuries, gasified coal provided heating and lighting in many markets. The Nazi government in Germany during World War II gasified coal using the Lurgi process and then turned the synthesis gas into gasoline and jet fuel using Fischer-Tropsch chemistry.

Facing worldwide sanctions in the 1980s for its racist apartheid regime, South Africa, through its state-owned Sasol company, developed a major program to turn coal into liquid fuels through coal gasification and Fischer-Tropsch technology. It worked well, although the government never fully disclosed the economics of the process.

In the U.S., Basin Electric Cooperative in the 1970s spearheaded the development of a project, with a $240 million Department of Energy (DOE) loan guarantee in 1980, for a project to gasify North Dakota lignite into pipeline quality natural gas. The project used the venerable Lurgi gasification technology. DOE later upped the loan guarantee to $1.8 billion. The plant began producing synthetic natural gas in 1984.

In 1988, the cooperative created the Dakota Gasification Co., which continues to operate the gasification plant. Today, given the low prices for natural gas, which undercut the Dakota Gas costs, as well as plentiful wind power, the company is looking to use the methane from the project as a feed stock for other products, such as urea, an important chemical in North Dakota’s dominant agriculture economy.

The company attempted to install a DOE-developed gasification technology, known as Transport Integrated Gasification (TRIG). It never worked as promised, although older technologies were readily available (see sidebar). The development of the project coincided with the rise of fracked, low-cost natural gas, undermining the economics of the coal project.

The carbon capture technology at Kemper worked and the plant is generating power from pipeline gas and supplying CO2 to enhanced oil recovery markets.

Then there’s Duke Energy’s 2006-proposed Edwardsport integrated gasification combined cycle (IGCC) plant. In 2007, Duke began construction of the 600-MW IGCC project at an existing coal-fired plant in southwest Indiana. It was touted to be the first of its kind to generate electricity from coal without CO 2 emissions. The initial price tag was $1.9 billion. DOE funding of $135 million supported the project. Over the next decade, the plant experienced predictable cost overruns and construction delays, bringing the revised cost estimate to $3.5 billion.

One of the major problems was carbon capture. It turned out the site wasn’t able to store CO 2 underground. It had to be moved by a pipeline to another storage site. Ultimately, Duke dropped carbon capture entirely, leaving it with a coal-to-gas generator that was not economically competitive with straight natural gas generation. Also, the project ran into severe ethical problems, leading to the firing of the top state utility regulator and the sacking of a key Duke executive.

Edwardsport eventually got built. It runs on natural gas produced from coal at a cost considerably higher than pipeline gas.

Another failure was DOE’s FutureGen project, a 275-MW IGCC joint venture between DOE and a consortium of coal companies and electric utilities set for Illinois. Planned in 2007, the project collapsed in 2008, a result of cost escalation from the original $1.6 billion to about double that.

Heading in the Right Direction?

How to fix the failures? The answer might be found 25 miles southwest of Houston, Texas. That’s where NRG Energy’s Petra Nova project is located. The winner of POWER’s Plant of the Year award in 2017, Petra Nova is a $1 billion project (built on time and on budget) that captures flue gas CO2 from a 240-MW slice of a 3.7-GW coal-fired station. The captured CO2 goes to nearby oil fields. Petra Nova appears to be able to take emissions from existing coal-fired technology, capturing and using the CO2.

In a little-noticed section of the 2017 tax law, Congress enacted Section 45Q. It increases tax credits for carbon capture and storage. Pushed by a coalition of business, labor, and environmentalists, it hikes an existing tax credit worth $10/ton for enhanced oil recovery up to $35 by 2024. A $50/ton credit for carbon capture and storage is for geological formations, reflecting increased costs of injecting the gas into rock formations where it can later be recovered for oil injection.

Brad Crabtree of the Minneapolis-based Great Plains Institute says the tax credits provide “an incentive policy for a technology that is proven and can be brought into the marketplace and deployed at scale.” ■

Kennedy Maize is a long-time energy journalist and frequent contributor to POWER.