Industry Market Trends
Harvesting CO2 from Carbon Storage for Power Generation Is Potent Idea
December 19, 2013
Carbon capture and storage technology has had a rough, short life so far. It was hailed as a way to maintain our energy-hungry economy at manageable carbon emission levels and championed by the coal industry -- and for a while by the federal government in the form of FutureGen. Whereas before there were measures to put carbon emissions into the ground rather than the atmosphere, there is now work being done to extract value out of underground CO2. The FutureGen project began in 2003 with a lot of fanfare under the Bush administration, got increasingly quiet over time due to three factors. First, the more that was learned about it, the more expensive it got. Second, the concept was still unproven at scale. Finally, ways of generating clean energy moved to the forefront. But the death of carbon capture and storage (CCS) has proven to be premature. That's because the federal government has recommitted to CCS technology, pledging $1 billion to FutureGen 2.0. A technique called oxy-combustion will be applied to a coal-fired power plant in Meredosia, Ill., with a goal of capturing 90 percent of the facility's emissions. The CO2 will be piped several miles away to a remote location (several sites are being considered). As that is happening separately, there is now an even bigger idea: in addition to capturing carbon emissions, produce additional clean power in the process. In an article called "If We Can Bury Carbon Dioxide, Why Not Use It to Make Electricity?" Kevin Bullis describes research into the use of CO2 as a "geofluid" to be used as a heat-transfer agent, pulling heat up from a geothermal site so it can be used to drive a geothermal power plant. The research, which is largely attributed to professors Martin Saar and Jimmy Randolph, both in the Department of Earth Sciences at the University of Minnesota, consists entirely of computer simulations at this point. They show that by using CO2 instead of water to draw the heat up, there are three distinct advantages. First, supercritical CO2 has liquid-like density but gas-like viscosity and thus transfers heat more easily through porous rock than water does. Second, because supercritical CO2 expands much more upon heating than water does, it becomes much more buoyant than water upon even slight heating. This drives a thermosiphon that allows the CO2 to rise buoyantly to the surface through a production well without the need for pumps, which are typically required for water-based geothermal systems. Finally, using CO2 would enable the use of CO2 turbines, which are more efficient than the steam turbines that are being used today. All three factors combine to improve the efficiency of a CO2-based geothermal power generation system to roughly twice that of a traditional water-based geothermal power plant, all else being equal. Because of these higher efficiency factors, this approach might allow geothermal energy to be harvested from areas that were thought to be difficult. It might, for example, allow power to be generated with lower-temperature sources than conventional technology. Cost is a factor as well, since the deeper one has to drill to find the necessary heat, the higher the cost of electricity produced. A paper written in 2000 by Kevin Rafferty of Oregon Institute of Technology, states that the lowest suitable temperature for geothermal power generation is 220°F. Power plant efficiencies are generally 10 percent or less. The use of CO2 as a heat transfer fluid could potentially improve both of these numbers. That was followed by work at Los Alamos National Laboratory, a U.S. Dept. of Energy affiliate, that suggested using supercritical CO2 for geothermal. Detailed modeling began six years later at Lawrence Berkeley National Laboratory at the University of California, a Dept. of Energy national lab. But it was Saar who first proposed adding geothermal energy extraction to existing plans for carbon capture and storage. He suggested that doing so could "yield additional value out of operations that already pump supercritical CO2 (i.e., enhanced oil recovery) into deep saline aquifers for storage, or into oil and gas formations to accelerate production." EOR operations inject CO2 underground to pressurize oilfields in order to facilitate the flow of oil. The technique, which is usually applied to declining fields, can make a significant difference. In the Wasson Field's Denver Unit, the use of EOR was responsible for an additional 120 million barrels of oil being produced over a 15-year period. Speaking to IMT, Saar said the CO2 that is injected underground forms a plume that is geothermally heated in the underground saline (and thus otherwise unusable) aquifer. At this point, the CO2 is in a high-temperature, high-pressure, supercritical state, where it is neither a liquid or a gas. A second pipe reaches down into the plume to draw off a portion of the CO2, which is then fed into a turbine that has been specifically configured to run on CO2. After the CO2 has been expanded through the turbine, it is reinjected underground. Therefore, no CO2 is released to the atmosphere in the process. Depending on heat recovery, the process could continue indefinitely, although at some point, when the aquifer reaches capacity, carbon storage will need to be halted. A water-based geothermal system could theoretically be operated as low as 220°F, but more typical numbers are above 300°F. Carbon dioxide, however, due to its higher heat transfer characteristics in this environment, can run at temperatures as low as approximately 160°F, though temperatures above 200°F are preferable. Today's steam systems run anywhere from 5 to 11 percent efficiency, while a CO2-based system can be expected to achieve between 8 and 15 percent. Given that the average continental underground geothermal gradient runs roughly 115°F per mile (it could be quite a bit higher out West), a water-based system might require a three-mile deep well, while a CO2-based system could produce an equivalent amount of electricity with a well two miles deep or less, which means it will be less expensive to build and operate. Besides hot rocks underground, permeable formations are needed for working fluid to pass through. This is another advantage for CO2, since it can be used in less permeable formations. Saar said a company called Heat Mining Company LLC has been formed, and it is in the process of obtaining funding for construction of a pilot plant. The company hopes to complete design and planning next year and have an operational plant the following year. No specific site has been determined, though the plant will require access to a CO2 source, such as a coal-fired power plant. Unlike the research project being planned at Berkeley Lab that will set up a capture loop at an existing CCS site and simply measure the amount of heat that can be extracted, this plant is promised to produce a commercial level of electricity through demonstration and testing of a CO2-powered turbine.