Technologies for limiting emissions can be integrated into business operations, but some first require further development.

CAROLA HANISCH

     "Two years ago, capture and storage could easily be dismissed as something researchers [were] just dreaming of," said Paul Freund, project director at the International Energy Agency's (IEA) Greenhouse Gas R&D Program in Cheltenham, England. Now more and more, researchers see it as one possible option to achieve long-term stabilization of carbon dioxide concentrations. "This is the impulse from Kyoto. Suddenly, things come up that were unthinkable a couple of years ago," explained Baldur Eliasson, head of the Energy and Global Change section of ABB Corporate Research, Ltd., in Baden, Switzerland.

     Projects that offer economic benefit, such as using captured CO₂ for enhanced oil recovery or enhanced coalbed methane recovery, are being actively pursued. In Norway, advanced membrane absorption techniques for capture of CO₂ from offshore gas turbines are being developed. Financial benefit is being achieved by circumventing the country's high carbon taxes. A similar capture technique, which aims to separate CO₂ from cogeneration power plants and then to sell the gas to greenhouse owners, is being explored in The Netherlands.

     The most prominent new development project in power generation technology is under way in Norway. The huge energy, chemicals, and metals conglomerate Norsk Hydro is planning a 1300-megawatt (MW) installed capacity hydrogen power plant. Almost three times the power-generating capacity of a standard European power plant, it will produce 10% of Norway's electricity. The facility will be built at Karmy, on the country's west coast.

     Underground storage of CO₂ is currently the most advanced storage option. On the basis of two years' experience with CO₂ injection into an aquifer under the Norwegian North Sea, an international European research project is establishing guidelines for regulators--a best-practices manual to help them make decisions about future injection projects. Less mature storage options, such as ocean storage, are being investigated further through field experiments and computer simulations.

Hydrogen power looks promising
The Norsk Hydro project will produce hydrogen from natural gas in a reforming process, which is a technology similar to that used for ammonia production. CO₂ is produced as a waste product. It will be separated using a conventional chemical absorption process and then pumped into the offshore Grane oilfield for use in enhanced oil-recovery operations. Over a period of 15 years, 4-5 million metric tons of CO₂ will be injected at the disposal site. The remaining hydrogen-rich gas stream will serve as a fuel in a combined-cycle power plant, producing electricity without emission of any CO₂. The main emission of the power station will be water vapor. Some technical adjustments of existing turbines will be performed to accommodate this use of the hydrogen-rich fuel.

     "What we have here is the idea [that] instead of capturing CO₂ from exhaust gases, you do it before you burn," explained Olav Kaarstad, researcher at the Statoil R&D Center in Trondheim, Norway. This is much easier to do because CO₂ in the precombustion gas stream is more highly concentrated than in the postcombustion exhaust gases, and no oxygen is present that could degrade the liquid absorbant used to separate the CO₂ at this stage of the process.

     Harry Audus, project manager at the IEA Greenhouse Gas Programme, and Olav Bolland, from the Norwegian University of Science and Technology in Trondheim, calculated that the efficiency of a process similar to the Norsk Hydro project would be 49-50%, which is 9% lower than that of a natural gas-fired, combined-cycle power plant without CO₂ capture (1, 2). Audus expects the cost of electricity to rise from about 2.5 cents per kilowatt hour to 3.4 cents per kilowatt hour, the increase reflecting the cost of avoiding carbon emissions.

     Why is Norsk Hydro engaging in such a project? There is a need for more electricity production in Norway. For two years the country has had to import more electricity than it exports. Moreover, Norsk Hydro is among the biggest consumers of electricity in Norway--it also produces aluminum and fertilizer and is very dependent on a stable power supply. "We have been holding back investment projects because of the lack of sufficient long-term [power supply] capabilities," explained Tor Steinum, from the Norsk Hydro press office.

     Despite pressing power supply needs, the Norwegian government is very reluctant to allow construction of regular gas-fired power plants, because the additional emissions of such plants would render it even more difficult for the country to meet its Kyoto convention goals. An emissions-free power plant, however, is likely to be approved by the authorities.

     Another possible reason for the Norsk Hydro initiative is the country's carbon tax. Today, the tariff mainly applies to offshore operations, because no onshore power production from fossil fuels exists; however, if a substantial amount of CO₂ emissions were produced from land-based generation, the tax might be extended to cover that source, too. The operators of a CO₂-free plant would not have to worry about that possibility. "For Norsk Hydro, this is a very important project, and we are presently putting huge resources into it," said project vice president Niels Schweigaard.

     The economics of the hydrogen plant are still unclear. The sale of CO₂ for enhanced oil recovery will provide some commercial benefit, and the electricity generated by the new Norsk Hydro power plant might partly replace demand for power from offshore gas turbines, thereby avoiding carbon taxes and contributing to a lowering of CO₂ emissions. However, despite these benefits, some researchers, such as Erik Lindeberg of IKU Petroleum Research Institute in Trondheim, do not believe that the company will realize a profit from the use of the process. "In my opinion, they are doing it for some other reason. This is a strategic decision. They are accepting that in the future the cost of fossil energy is going to be higher, so they adapt now," he said.

     Norsk Hydro is currently working out the technical details of the project. They must file an application with government authorities who must then decide whether to approve the project. Once the project is approved, commercial negotiations can begin. The owners (Norsk Hydro, Exxon, and Statoil) of the Grane oil field must be convinced to purchase the CO₂, and the purchase of natural gas, as well as the sale of electricity, must be negotiated. The final decision on the construction of the plant is expected to be made in April. The hydrogen power station could start production in 2002 or 2003.

CO₂ management incentives
There are practical reasons for wanting to capture CO₂--Norway will be the first to use CO₂ from a power plant for enhanced oil recovery. CO₂ obtained from a coal gasification plant in the United States will be used for the same purpose. In the United States, CO₂ is commonly used for enhanced oil recovery (EOR). About 60 million cubic meters per day (since mid-1998) of pure CO₂ are being injected at 67 commercial EOR projects, mostly in west Texas--50% stays in the reservoir, and the remaining 50% comes up with the oil during recovery (3). This gas is collected, compressed, and reinjected. In this way, the majority of the greenhouse gas remains permanently stored underground.

     In most cases, however, CO₂ from natural sources is used, such as CO₂ from natural gas processing. In June 1997, PanCanadian Petroleum, Ltd, of Calgary, agreed to buy CO₂ from the Great Plains coal-gasification plant in Beulah, N.Dak. Beginning in late 1999, approximately 5000 metric tons per day of the greenhouse gas will be pumped through a 330-km pipeline to the Weyburn oil field in the Canadian province of Saskatchewan (3). Through enhanced oil recovery, the lifetime of the oil field will be extended by as much as 25 years.

     At the synthetic fuels plant operated by the Dakota Gasification Company, 16,200 metric tons of lignite coal are converted daily into 3.54 million cubic meters of pipeline-quality natural gas, 900 metric tons of anhydrous ammonia, and other byproducts. Revenues from byproducts exceed those realized from sale and use of the synthetic natural gas. Capture of CO₂ and its utilization for enhanced oil recovery represent a further diversification of the company's byproducts business.

     Besides enhanced oil recovery, another commercially interesting use of captured CO₂ is emerging: injection into deep coal seams to enhance methane recovery. Initial results from the world's first pilot project show this new technology to be technically and economically feasible, according to Scott H. Stevens, vice president of Advanced Resources International, Inc., in Arlington, Va. Since 1996, Burlington Resources has sequestered over 57 million cubic meters of CO₂ in coal seams at its Allison Unit production pilot, located in the northern San Juan basin in New Mexico (4). The CO₂ gas is absorbed on the coal surface, thereby replacing and freeing methane. Two molecules of CO₂ are trapped for every molecule of methane released.

     Stevens estimated the worldwide sequestration potential of CO₂ in deep coalbeds, using the Allison Unit pilot test results as a benchmark. He calculated that 5-15 Gt (metric ton units) of CO₂ could be sequestered, generating a net profit at $15 per metric ton; 60 Gt may be sequestered at moderate costs of under $50 per metric ton; and 150 Gt (metric ton units) could be sequestered at costs of $100-$120 per metric ton.

     Although naturally occurring CO₂ is currently used in the pilot project, researchers believe the process might be used in future commercial applications--for null-greenhouse-gas-emission power plants. Bill Gunter, group leader of Applied Geochemistry at the Alberta Research Council in Edmonton, envisions a cycle in which power plants are fueled by methane that originates from coal beds at the same time that waste CO₂ is injected into the coal reservoirs to produce more methane, thereby closing the cycle (5). The Alberta Research Council is also leading another pilot project for enhanced coalbed methane recovery in Alberta, supported by Canadian and U.S. government organizations and industry partners.

Membrane technology options
Currently, CO₂ capture and sequestration applicationsare limited to special projects that offer commercial benefits, because capture is a very energy-intensive procedure that requires large--and expensive--equipment. New membrane technologies, however, might allow further applications of CO₂ capture technology (6). Kvaerner, a Norwegian company, has developed a novel membrane absorption process that is small and compact (see photo on previous page). This process will be used on offshore gas turbines. These facilities are categorically a major emitter of CO₂ in Norway and pay very high (carbon) taxes.

Kvaerner Oil & Gas and W. L. Gore & Associates GmbH have initiated a joint industry research and development project that will remove CO₂ from flue gas using gas-liquid membrane contactors. For comparison purposes, the pilot unit shown here, which is located at Statoil K-lab, Kårst, Norway, has been designed with both membrane absorber and desorber, as well as conventional columns. (Courtesy Kvaerner Oil & Gas)

     Total Norwegian offshore CO₂ emissions were approximately 11 million metric tons per year in 1998. The contribution from offshore gas turbines is approximately 83%, which could be reduced by 30% if the new CO₂ removal process were installed on suitable platforms. Currently available CO₂ capture process technology cannot be used on offshore platforms because the equipment is too big and too heavy. It consists of absorption towers 20-40 meters high, in which exhaust gas is bubbled through an amine solution that is used as an absorption liquid. In an additional desorption tower, as needed, the CO₂-loaded liquid is heated to free the gas.

     In the new process, the exhaust gas flows through small Teflon membrane fibers, which are surrounded by the absorption liquid. CO₂ passes through the membrane and is carried away by the liquid. The huge membrane surface area results in a highly efficient absorption process, thereby reducing the size of the equipment that is used by 78% and the weight by 66%. Kvaerner is planning to build the first commercial capture unit in 2000 or 2001.

     The Dutch TNO Institute of Environmental Studies in Apeldoorn, The Netherlands, is developing a similar membrane gas absorber that can be used for CO₂ capture in cogeneration plants. This would be an environmentally friendly way of delivering both heat and CO₂ to greenhouse growers. Currently, in The Netherlands, greenhouse growers often burn natural gas in small boilers to produce CO₂ and heat. This is very inefficient; they need CO₂ during the day and heat during the night. A cogeneration plant that produces electricity, waste heat, and waste CO₂ would be a much better use of fossil resources. However, regular CO₂ capture equipment is again too expensive, and absorption tower height is a problem. "In a flat country like The Netherlands, in many areas you are not allowed to erect structures more than 15 meters high," explained project manager Paul H. M. Feron, of TNO. He explained further that the membrane gas absorber is only 2 meters high (7) and that the CO₂ available from application of the membrane technology would be 20% cheaper than that produced by just burning gas.

     In contrast to Kvaerner, TNO uses commercially available polypropylene membranes. They cannot be used with the conventional amine absorption liquid, so Dutch engineers had to develop a new type of liquid to absorb the gas. The principle of the process, however, is similar to Kvaerner's. In four or five years, a full-scale plant is expected to be constructed. Feron estimated that a market exists for 10 cogeneration plants in The Netherlands that use membrane-based CO₂ capture, thus supplying 10% of the country's total greenhouses with CO₂.

Ocean and aquifer storage
Even as new capture and sequestration options are being developed, the world's first project of this kind is well under way in the Norwegian North Sea (see photo at right). "After a few small disturbances in the beginning, the Sleipner project is running fine," said Tore Torp from the Statoil Research and Development Center in Trondheim, Norway. He noted that scientists and an environmentally engaged public are interested in what happens when CO₂ is spread out in a salt water layer. He explained that this is why Statoil, several industrial partners, and European research institutes started an international monitoring project last November.

As part of an ongoing project, CO₂ is being separated from natural gas and pumped into a huge aquifer 800 meters below the ocean floor off the coast of Norway in the North Sea. Information obtained from this undertaking will guide the development of a best-practices manual for similar future projects by other companies to limit uncontrolled emissions of CO₂. (Courtesy Øyvind Hagen, Statoil)

     Project researchers want to learn where and how the CO₂ bubble moves in order to validate computer simulation models. Investigators are using seismic and gravimetric measurements to collect data needed to put the models on a firm basis. At the end of this three-year, European Community (EC)-supported project, they want to put together a best-practice manual for future CO₂ injection projects. Torp explained, "This is supposed to help regulators set up guidelines. They need to decide on what terms CO₂ injection should be allowed, for example, what research exploration should be done in advance, what models should be used, what methods can be relied on, and what documentation should be presented."

     Meanwhile, ocean storage, a less mature storage option, is being explored further. In December 1997, Japan, Norway, and the United States signed a project agreement for collaboration on a pilot-scale field experiment for the Climate Technology Initiative of the Framework Convention on Climate Change. Since then, Canada and ABB, a Swiss company based in Zurich, have joined the project. The experiment will take place off the Kona coast of Hawaii in the summer of 2000. A pipeline will be laid on the seafloor, and liquid, buoyant CO₂ droplets will be released at a depth of 1000 meters (8). So far, researchers have gained all their knowledge on ocean disposal from laboratory and theoretical work; they need validation with real-world results.

     Up to 1 kilogram per second of CO₂ will be injected into the ocean, an amount that is roughly equivalent to 1% of the CO₂ exhaust from a 500-MW coal-fired power plant. The behavior of the injected CO₂ plume will be monitored with the help of instruments mounted on a remotely operated vehicle and on the seafloor. "We want to learn the physics and the chemistry of the CO₂-seawater interaction," explained Eric Adams, senior research engineer at Massachusetts Institute of Technology in Cambridge. Collected information can then be fed into computer models to scale up and simulate biological impacts.

     James C. Orr, researcher at the Laboratoire des Sciences du Climat et de l'Environnement/Commisariat a l'Energie Atomique in Gif sur Yvette, France, is trying to address the question of how long the injected CO₂ might stay isolated from the atmosphere. Orr is coordinating a project called GOSAC (Global Ocean Storage of Anthropogenic Carbon), which has just started and is funded by the EC and the IEA Greenhouse Gas R&D Program. The GOSAC effort includes a comparison of seven European general ocean circulation models to estimate the time for injected CO₂ to be lost back to the atmosphere.

     Orr's preliminary results reveal a negative feedback, due to indirect effects, which reduces the effectiveness of permanent ocean sequestration (9). After a 200-year simulation of a permanent sequestration scenario, he found that the approach was only 80% efficient compared with a business-as-usual reference scenario with no CO₂ capture. The reason is that, in the permanent sequestration scenario, there is a lower atmospheric concentration of CO₂ than in a scenario with no CO₂ capture. Ocean uptake of CO₂ is reduced compared with a situation in which a higher CO₂ atmospheric concentration exists. In reality, not all injected CO₂ would remain in the ocean. Orr simulated two scenarios, one with CO₂ sequestration at 1500-meters depth and the other at 3000-meters depth. His results show that after 200 hundred years, 18% of the CO₂ injected at 1500 meters is lost to the atmosphere, and 8% of the CO₂ injected at the greater ocean depth escapes after that period.

     Researchers agree that more studies are necessary to determine the effectiveness of CO₂ sequestration, to learn about biological impacts and other environmental risks, and to lower costs. Then, they say, it is up to the politicians, the lawyers, and the public to decide whether CO₂ capture and storage should be applied on a broad scale or whether alternatives are necessary.

References

(1) Audus, H.; Kaarstad, O.; Skinner, G. CO₂ Capture by Pre-Combustion Decarbonisation of Natural Gas. Presented at the Fourth International Conference on GHG Control Technologies, Interlaken, Switzerland, Aug. 1998.

(2)  Bolland, O.; Undrum, H. Removal of CO₂ from Gas Turbine Power Plants: Evaluation of Pre- and Postcombustion Methods. Presented at the Fourth International Conference on GHG Control Technologies, Interlaken, Switzerland, Aug. 1998.

(3)  Hattenbach, R. P.; Wilson, M.; Brown, K. R. Capture of Carbon Dioxide from Coal Combustion and Its Utilization of Enhanced Oil Recovery. Presented at the Fourth International Conference on GHG Control Technologies, Interlaken, Switzerland, Aug. 1998.

(4)  Stevens, S. H.; Kuuskraa, V. A.; Spector, D.; Riember, P. CO₂ Sequestration in Deep Coal Seams: Pilot Results and Worldwide Potential. Presented at the Fourth International Conference on GHG Control Technologies, Interlaken, Switzerland, Aug. 1998.

(5)  Gunter, W. D.; Gentzis, T.; Rottenfusser B. A.; Richardson, R.J.H. Energy Convers. Mgmt. 1997, 38(Suppl.), S217-S222.

(6)  Dannströem, H.; Sbye, M.; Grnvold, M.K.S. Development of Absorption Process for Separation of Carbon Dioxide from Offshore Gas Turbine Exhaust. Presented at the Fourth International Conference on GHG Control Technologies, Interlaken, Switzerland, Aug. 1998.

(7)  Feron, P.H.M.; Jansen, A. E. Technoeconomic Assessment of Membrane Gas Absorption for the Production of Carbon Dioxide from Flue Gas. Presented at the Fourth International Conference on GHG Control Technologies, Interlaken, Switzerland, Aug. 1998.

(8)  Adams, E.; Akai, M.; Golmen, L.; Haugan, P.; Herzog, H.; Masuda, S.; Masutani, S.; Ohsuma, T.; Wong, C. S. An International Experiment on CO₂ Ocean Sequestration. Presented at the Fourth International Conference on GHG Control Technologies, Interlaken, Switzerland, Aug. 1998.

(9)  Orr, J. C.; Aumont, O. Exploring the Capacity of the Ocean to Retain Artificially Sequestered CO₂. Presented at the Fourth International Conference on GHG Control Technologies, Interlaken, Switzerland, Aug. 1998.

Carola Hanisch is a freelance writer based in Freiburg, Germany.