A proposed power plant in Southern California that would turn coal and waste petroleum into cleaner-burning gas has garnered support from the state and stimulus funds from the federal government.
Hydrogen Energy International LLC -- a partnership of BP Alternative Energy and Australian miner Rio Tinto Hydrogen -- is proposing the plant for Kern County near Bakersfield. The 250-megawatt facility is designed to filter out 90 percent of its carbon dioxide for permanent underground storage in an adjacent oil field. An additional 100 megawatts would be available for peak-hour generation to help integrate more intermittent wind and solar power into the California grid.
The plant was recently awarded a $308 million grant from the $787 billion American Recovery and Reinvestment Act (E&ENews PM, July 1). It is the largest grant yet from the Department of Energy's Clean Coal Power Initiative and one of the largest single awards in President Obama's stimulus package.
"These new technologies will not only help fight climate change, they will also create new jobs and position the United States as a leader in carbon capture and storage technologies for many years," said a statement from Energy Secretary Steven Chu, who hailed the plant's state-of-the-art gasification technology as a "major step forward" in the fight to eliminate CO2 emissions using carbon capture.
The plant's technology would convert petcoke, coal, biomass or a combination of each into a synthetic, flammable gas. Chemical "scrubber" reactions would filter out pollutants like sulfur and CO2, leaving behind pure hydrogen to power a set of turbines similar to jet engines.
Carbon captured from the plant would be piped to the adjacent Elk Hills oil field for use in enhanced oil recovery, a technique used to extract crude left behind by traditional production processes. Occidental Petroleum plans to purchase the CO2 at a fixed rate during the life of the plant, said HEI spokeswoman Tiffany Rau.
The plant is part of a growing trend of proposals seeking to use gasification and CCS technologies to sell CO2 to nearby oil fields. Gasification plants are also in the works in Texas and Illinois, both of which intend to sell captured CO2 to oil-field operators in the Gulf of Mexico region.
"Both the DOE and Hydrogen Energy recognize that this project may become the model for new power generating facilities throughout the world," said Lewis Gillies, CEO of HEI, in a statement.
Congress recognized the technology's potential, too, when it passed a comprehensive energy and climate bill last month that includes major incentives for "first movers" to deploy CCS. The bill, sponsored by Reps. Henry Waxman (D-Calif.) and Ed Markey (D-Mass.), includes provisions that would award new or retrofitted power plants up to $90 per ton of carbon dioxide emissions that are trapped and stored underground.
"The technology we're going to use is proven today," said Rau, noting a separate gasification plant HEI is designing in Abu Dhabi, United Arab Emirates, in the Persian Gulf. "We're not taking any risks."
Delivering full-scale carbon capture
Coal gasification technology has been used successfully since the 1980s in North Dakota at Basin Electric Power Cooperative's Great Plains Synfuels Plant, which sends 3 million tons of captured CO2 a year to oil fields in Canada's Saskatchewan province.
But so far, no commercial-scale power plant has been able to capture 90 percent of its CO2. The Great Plains plant captures 50 percent of its CO2 at full output, while the proposed FutureGen plant in Mattoon, Ill. -- a public-private development touted as the most advanced coal-fired power plant under development in the United States -- would initially capture 60 percent of its CO2 waste, with the technological capacity to capture 90 percent in the future.
FutureGen, which would use a gasification technology similar to HEC's, was scaled back amid fears of "technical risks" and the need to cut project costs, which are currently estimated to be $2.4 billion, said Lawrence Pacheco, a spokesman for the FutureGen Alliance. DOE has pledged just over $1 billion for the project but is waiting until early 2010 to finalize the offer.
Rau said the California plant's cost will be in the ballpark of $2 billion, but HEI is waiting to complete a front-end engineering and design study before offering an exact price figure. The $308 million grant will be used for planning, permitting and possibly some of the construction costs, Rau said.
Financing the plant's commercial-scale technology in tough economic times will be a significant challenge. Developers said they won't make any final decisions to pursue the project until it receives regulatory approvals from the state.
Is there a market for it?
Even if Hydrogen Energy California is approved by regulators and built, there is no guarantee there will be a market for its product.
California's annual growth in power demand is expected to be just over a half-percent through 2020, largely because of expectations that all cost-effective energy-efficiency measures will be pursued first. Also, state lawmakers are expected to pass an updated renewable energy standard of 33 percent by 2020, forcing utilities like Southern California Edison to gravitate even more toward wind, solar and geothermal power contracts.
"The key question is whether the power can be sold at competitive prices," said Arthur O'Donnell, executive director at the Center for Resource Solutions, a San Francisco nonprofit environmental group. "The new resource picture in California is complicated."
The plant's developers say they expect a growing market for dependable, baseload and peak power to balance the grid when the wind or sun is unavailable. Grid operators say they will need an additional 10,000 megawatts of "peaking" power from plants like HEI's to respond to sudden power drops or surges in demand.
"Wind power doesn't always blow on peak when we need it most," said Gregg Fishman, spokesman for the California Independent System Operator, which regulates the state's power grid. "Finding resources that can respond to those fluctuations is important."
More uncertainty remains over what will happen to more than 20,000 megawatts of power plants that must be either retrofitted or retired after the state passed a ban on "once-through cooling" systems that discharge thermal pollution off California's coasts. Grid operators expect about 12,000 megawatts of that power will need to be replaced for reliability purposes.
"There will still be a need for this kind of power plant," Fishman said.
Environmental, cultural obstacles could derail proposal
HEI applied for an operating permit with the California Energy Commission in May and expects the review process to be complete by May 2011. But approvals of such plants are somewhat rare in California, which has not seen a new commercial-scale coal or petroleum plant in decades. Of the 25 power plants under review at the agency, HEI's is the only one that does not call for natural gas or renewable energy.
"California is notoriously tough on siting of fossil-fueled power plants," said O'Donnell, of CRS. In addition to meeting some of the toughest air quality standards in the United States, "these developers will need to get strong community buy-in," he said.
Locally, at least, the plant has captured support from business leaders and is under evaluation by the Kern County Planning Department for its effects on air quality and road traffic. The plant would generate an estimated 1,500 construction jobs and create up to 100 permanent "green collar" jobs in various operation positions. Construction would generate about $5 million in tax revenues, and the plant would yield $1 million annually to local governments, HEI estimates.
Kern County is also no stranger to big energy. The county has been producing oil since it was discovered locally in the 1800s and today represents 10 percent of the nation's oil production, according to the Kern Economic Development Corp. If it were its own state, Kern would be the fourth-largest oil producer in the United States.
Rau said the county's existing energy infrastructure, which includes three coal-petcoke facilities, plays into the hands of the new plant by minimizing some of the financial and environmental costs associated with transporting raw materials.
"It makes the coal that we're importing incremental to what's already being imported," Rau said. "It's not as if we're bringing a whole new rail spur of coal into California for the first time."
Parts of the environmental community seem to be on board, too. While stopping short of endorsing the HEI proposal, the National Resources Defense Council says the plant's design, known as "integrated gasification combined cycle," is one of the most promising technologies available for burning fossil fuels with CCS.
Moreover, much of the petcoke produced in the United States is currently shipped abroad to places like China, where it is burned as raw fuel for power production. Power plants like the one in Kern County would offer cleaner uses for the fuel and prevent most of its carbon from ever reaching the atmosphere.
"It looks as if [IGCC] is the most advanced and economically the most favorable," said George Peridas, a climate scientist at NRDC's San Francisco office.