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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 F Case Studies for the Fossil Energy Program To facilitate and rationalize the assessment of the Office of Fossil Energy (FE’s) R&D benefits, the committee divided the fossil energy technologies into four categories: (1) coal and gas conversion and utilization, (2) environmental characterization and control, (3) electricity production, and (4) oil and gas production. These are logical groupings of fossil energy technologies recurring in the Office of Fossil Energy’s research portfolio. Coal and gas conversion and utilization subsume the following technologies: Coal preparation for cleaner coal production, Direct liquefaction, Atmospheric and pressurized fluidized-bed combustion (FBC) for electricity production, Gas-to-liquid fuels (GTL), Indirect liquefaction, and Integrated gasification combined cycle (IGCC) for fuel and electricity production. The environmental characterization and control group encompasses the following: Environmental control technologies (flue gas desulfurization and NOx emissions control), Mercury and other air toxics emissions, and Coal combustion waste management and utilization. Electricity production includes the following three technologies: Advanced turbine systems (ATS), Stationary fuel cells, and Magnetohydrodynamics (MHD) electricity production. The oil and gas production category comprises the following technologies: Enhanced gas production from coal-bed methane, Well drilling, completion, and stimulation, Downstream fundamentals, Enhanced gas production from Eastern gas shales, Enhanced oil recovery, Field demonstrations of extraction technologies, Fuel production from oil shale, Seismic technology, and Enhanced gas production from Western gas sands. The case studies are treated in this appendix in the same order they are listed here. COAL PREPARATION Program Description and History Enhancement of coal quality by different forms of pretreatment such as washing or flotation to remove sulfur and other minerals has important implications for improving the heat value of the fuel, as well as for its combustion emissions. Coal washing and beneficiation have been used commercially for some years at mines and power plants where coal quality has been of concern. A continuing interest in coal preparation has been the search for deep cleaning to maximize removal of impurities and to maximize the recovery of purified coal from the solvent wash with high coal throughput. The latter is of particular concern in recovering the fine pulverized coal fraction. Since the conventional methods of coal cleaning are low in cost and well established in the industry, the interest in advanced coal preparation has declined in recent years. Funding and Participation Since 1978, DOE has invested nearly $300 million in advanced technologies for coal preparation. Most of the fund-
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 ing was committed prior to 1991; funding since that time has declined to about $5 million annually (OFE, 2001a). DOE’s program in coal preparation devoted a major effort to the deep-cleaning process through the early 1980s, but the focus on postcombustion technologies for pollution control and the shifts in the coal market toward low-cost modest-quality fuel supplies shifted DOE’s emphasis in the late 1980s to recovery efficiency objectives. DOE’s program has contributed to the development of advanced cleaning processes for demineralization, including flotation, recovery of the fine particle fraction of pulverized coal, coal dewatering, and coal processing system simulation. At one point, interest developed in the cleaned, ultrafine fraction of pulverized coal that, if suspended in air or other fluids, could be used directly—for instance, for injection into turbines. This application has not been pursued, because natural gas (or coal gas) is now the preferred fuel. DOE’s current program has declined to a relatively low priority “maintenance” level, with interest and support from the coal industry in continuing studies of cleaning and material-handling technologies as a means of training and educating qualified technical people to support the industry. Results DOE’s program has contributed substantially since the 1970s to improving knowledge about advanced preparative treatment of coal. The accompanying process development is estimated to add substantially, however, to the cost of untreated coal. The work also resulted in the commercialization of an advanced (Microcel1) flotation column and the precommercial testing of an air-sparged hydrocyclone for flotation separation. A continuous separation technology involving a packed separation column system has also been tested. To improve the separation and capture of pulverized coal fines, the Granuflow process has been developed and licensed for commercialization. More exotic methods for beneficiation have reached development and testing, including the tribo-electric separation process, which was tested at (formerly) New England Electric’s Salem Harbor and Brayton Point plants, and micronized-magnetite cyclone cleaning for fine pulverized coal. In the current market, however, large-volume sales are directed toward low-cost coals; the added costs of cleaning are not justified. The existing technology for coal cleaning is sufficient to supply requirements for certain Eastern coals to users without additional costs of deep cleaning. Advanced dewatering technologies for the fine particle fraction are being investigated as part of the Solid Fuels and Feedstocks Grand Challenge Program, with a target cost of $1 per ton of coal treated to improve the marketability of the fine fraction. While the advanced technologies have reached at least pilot scale development, they have proven to be expensive alternatives to conventional practice. Discussions with two major coal suppliers and FE representatives suggest that the FE program has had only a marginal influence on coal cleaning technology as practiced today. Coal cleaning generally is not applied to Western low-sulfur coal but remains an element in some Eastern coal processing. Perhaps equally important is DOE’s role in supporting coal preparation technology development in academia, which helps to train technical people for the industry. Benefits and Costs Since coal cleaning and beneficiation add to the costs of pulverized coal supplies, there evidently is no current economic benefit for the application of the advanced technologies developed by DOE. However, as natural gas and oil prices increase, greater demand for deep-cleaned coal supplies may increase, and the use of DOE’s technology options may expand. However, the present high-volume market for coal focuses mainly on a low-cost supply. The market for high-quality or washed coal fills niches in the marketplace but does not represent a large segment by volume (mass). The benefits matrix for coal preparation (Table F-1) indicates that economic benefits exist in the options and knowledge categories, but in the near term, the application of available optional technologies is not anticipated. The benefits in the knowledge category have led to spin-off applications of the Microcel flotation column for mineral recovery operations—for example, applications to copper, kaolin, and graphite processing. The Microcel column technology has been installed in about 70 plants worldwide for processing coal and other mineral resources. Other spin-off s of the DOE technology include mineral processing, application of the air-sparged hydrocyclone to fiber de-inking, and copper ore processing using the continuous packed column separator. The tribo-electric separator has been applied to unburned coal separation from fly ash used in cement production, as well as waste plastic recycling. With increased environmental concerns about the collection and sequestration of ash, minerals, and sulfur from coal, deep coal cleaning may one day be used to separate waste material prior to combustion. This may become particularly important for removal and sequestration of heavy metals, including mercury. To account for this contingency, industry continues to support at least a minimal academic-style program in the coal preparation area. 1 Microcel is a novel froth flotation column cell for cleaning finely ground coal. The Microcel process uses microbubbles in a water-filled flotation column to separate mineral impurities from coal. It is particularly effective in cleaning very fine coal particles, typically smaller than grains of sand, that are often discarded in coal waste ponds. The University Coal Research Grant to Virginia Polytechnic Institute licensed it to Mineral Technologies International, Inc. There are 70 to 80 units installed worldwide.
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 TABLE F-1 Benefits Matrix for the Coal Preparation Programa Realized Benefits/Costs Options Benefits/Costs Knowledge Benefits/Costs Economic benefits/costs DOE costs: $292 million Industry costs: unknown, but probably minimalb Benefits: Nonec Micronized-magnetite cycloning and advanced fine-coal dewatering technologies Development of cleaning processes for demineralization of pulverized coal, which could be used as one element of a total environmental control system None Environmental benefits/costs None Potential supplies of deeply cleaned coald Coal-cleaning equipment evaluations Developed a variety of concepts to remove contaminants from finely ground coal Security benefits/costs None None None aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000. bFE provided no information on industry costs or cost share; however, private industry interest in this technology was minimal. cSince coal cleaning and beneficiation add to the cost of pulverized coal supplies, there is no current economic benefit to the application of the technologies. FE provided no discussion or estimates of economic benefits. dIf conventional coal use is reduced owing to real or perceived environmental, health, or other concerns, then demand for the traditional coal products would also be expected to decrease; at the same time, the demand for deeply cleaned coal with very low ash, sulfur, and trace element content using advanced technologies developed via coal preparation R&D might increase. Lessons Learned This program is another good example of a technology option that has lost its motivation because of shifting environmental requirements and fuel preferences guided by changing energy policy. The program has a history of 22 years or more in DOE with productivity in technology development. At the beginning it was aimed at environmental protection by improving the quality of coal and the precombustion removal of undesirable constituents of coal for sequestration as solid waste. This approach was one favored option for retaining Eastern coals as a fuel option in the early stages of pollution control. However, there has been little or no motivation to wash low-sulfur Western coals. Air quality requirements and the switching of electricity generation to low-sulfur, low-cost coals and natural gas made this approach obsolete by the late 1980s. Given the changes occurring in the electricity generation industry with the advent of natural-gas-fired gas turbine designs and IGCC applications for future coal options, combined with deregulation of the electricity industry, FE has moved this program to a low priority. At the same time, there remains industry support to press on with some basic R&D effort in this area so as to continue developing a reservoir of knowledge about coal beneficiation. The lack of commercial interest in technologies in the coal sector indicates that the market for the foreseeable future will not be amenable to adding costs to coal supplies. While the spin-offs from separation technologies have found commercial application in the other industries, they do not warrant according this area a high priority. DIRECT COAL LIQUEFACTION Program Description and History The DOE direct liquefaction program in the 1970s and early 1980s consisted primarily of large-scale demonstration projects with broad industry participation in response to the energy crisis perceived at that time. Since U.S. coal reserves are huge and coal prices were judged likely to remain relatively modest, the DOE and participants from the electric power and oil industries set out to demonstrate the best-available technology for directly converting coal to liquid fuels. A smaller-scale, more fundamental R&D process improvement program with less industry participation followed these demonstrations through most of the 1980s and the 1990s. After a series of budget reductions, the direct liquefaction R&D program was eliminated in 2000. Over 88 percent of the expenditures in direct coal liquefaction since 1978 occurred prior to 1983. This pattern is generally consistent with the rise and fall of projected crude oil prices and with the change in the administration’s view of government energy R&D following the elections in 1980. This case study is based on information provided by DOE to the committee in a meeting held June 21, 2000, and in a more detailed written response by DOE to committee questions transmitted on January 18, 2001, as well as technical and economic information contained in the NRC report Fuels to Drive Our Future (NRC, 1990). In the direct liquefaction technology pursued by the DOE and industry participants, hydrogen is added to coal in solvent slurry at elevated temperatures and pressures. This gen-
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 eral liquefaction concept was first commercialized using inefficient, very high-pressure reactors in Germany and England to provide liquid fuels during World War II. After the OPEC embargo in 1973 and 1974, a variety of process concepts were examined on a small scale, and three so-called second-generation processes were demonstrated on a large scale: SRC-II (solvent-refined coal) in Tacoma, Washington; EDS (Exxon donor solvent) in Baytown, Texas; and H-Coal (single-reactor hydrogenation) in Catlettsburg, Kentucky. The DOE provided 65 percent of the funding for these demonstrations, which were technically successful but not commercialized because the oil price increases projected during the 1970s did not materialize. The DOE led and funded 83 percent of the more fundamental process improvement R&D program that followed the large-scale demonstrations. The Advanced Coal Liquefaction R&D facility in Wilsonville, Alabama, became the focus of U.S. coal liquefaction process R&D until the mid-1990s, when it was shut down, leaving the Hydrocarbon Research, Inc. (later, Hydrocarbon Technologies, Inc.) (HRI/ HTI) multistage coal liquefaction unit the only operating facility in the United States. Funding and Participation As shown in Table F-2, from 1978 to 1999, the DOE budgeted $2.3 billion (constant 1999 dollars) for direct liquefaction of coal. Industry cost sharing over this period was $1.15 billion. From 1978 through 1982, the DOE budgeted slightly over $2 billion for direct liquefaction technology demonstrations, and industry participation in the demonstration programs was over $1 billion. The industry participants consisted of the major oil companies (Exxon, Mobil, Chevron, Amoco, Conoco, Gulf, and others) and the electric power industry (notably EPRI and Southern Co.) There was no cost sharing from the U.S. coal industry. The DOE budget dropped sharply in 1983 after the demonstration projects ended and continued to decline gradually over the next 5 years; then it increased modestly for 4 years, at which point it began a steady decline lasting 8 years until the program was terminated after 1999. During the process-improvement period, the DOE budgeted nearly $270 million, with cost TABLE F-2 DOE Appropriations and Industry Cost Sharing for Direct Liquefaction (millions of 1999 dollars) Years DOE Industry Demonstration projects 1978 to 1982 2035 1096 Process-improvement R&D 1983 to 1999 267 54.8 Total 1978 to 1999 2302 1150.8 SOURCE: Office of Fossil Energy. 2001b. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Direct Coal Liquefaction. January 8. sharing (mainly from the electric power industry) of $55 million (OFE, 2001b). Results The demonstration projects, with plant sizes up to 200 tons/day (tpd), proved the technical feasibility of direct liquefaction with successful operation of process equipment such as ebulated bed reactors, letdown valves, de-ashers, and preheaters of sufficient size to permit scale-up with reasonable confidence. The program also identified problems typical of coal processing, such as corrosion, erosion, and fouling, that needed further study. The economics of the processes demonstrated were unattractive as a result of low yields, poor product quality, and high capital costs, among others. For example, DOE estimates liquid products produced from H-Coal cost about $65/barrel (bbl) on a crude-oil-equivalent basis (in constant 1999 dollars). The DOE estimates the cost for technology developed from process-improvement R&D to be half that of H-Coal. The committee estimates that industry would require crude oil prices above $45/bbl to commercialize this technology in the United States. If environmental concerns such as the high level of CO2 produced per product Btu and the aromatic nature of the resulting liquid fuels are addressed, this cost will increase. The improvement in economics over H-Coal is attributable to an accumulation of small improvements over the years rather than a major breakthrough. Key cost reductions include the following: (1) controlled precipitation was developed that eliminated an expensive filtering step; (2) the portion of recycled product liquid used to slurry the feed coal was bypassed around the solids removal unit, increasing the efficiency of the process; (3) catalytic reactors were added in series to improve control of the liquefaction chemistry; (4) improved catalysts were developed; and (5) less complex reactors were developed. In addition, materials of construction and improved designs were found to solve the processing problems identified in the demonstration projects. The combination of these process improvements led to lower capital cost, increased liquid yields, improved product quality, more effective hydrogen utilization, and greater reactor throughput. Further reductions in costs can be achieved if coal is mixed with heavy crude oil or refinery bottoms in a coprocessing configuration. Benefits and Costs There are no realized economic benefits, because the direct liquefaction technology developed in the DOE/industry program has not been commercialized (Table F-3). Direct liquefaction technology is a possible option for the future. Use of this option in the United States will likely require additional improvements in environmental impacts and economics (further cost reduction and/or higher crude oil prices). The current conventional wisdom is that indirect liq-
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 TABLE F-3 Benefits Matrix for the Direct Liquefaction Programa Realized Benefits/Costs Options Benefits/Costs Knowledge Benefits/Costs Economic benefits/costs DOE R&D costs: $2.3 billion Industry costs: $1.2 billionb Technology has not been commercialized Developed to the point that with some scale-up risk, may be commercially viable if the price of oil increases sufficientlyc Technology can be used for heavy and extra-heavy petroleum processing Enhanced base of chemistry, catalysis, product, design, and processing knowledge developed relating to coal and petroleum residuumd Demonstrated successful operation of key pieces of process equipmente Environmental benefits/costs None None None Security benefits/costs No benefits, since technology has not been commercially deployed Fuels from coal would displace oil use None aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000. bThere was no investment in the technology by the coal industry, but there were substantial investments by the petroleum industry and by the electric power industry, mainly through EPRI. cA variety of process concepts were examined on a small scale, and three were tested on a large scale in the late 1970s and early 1980s: SRC-II (solvent-refined coal) in Tacoma, Washington; EDS (Exxon donor solvent) in Baytown, Texas; and H-Coal in Catlettsburg, Kentucky. Following the demonstrations, the Advanced Coal Liquefaction R&D facility in Wilsonville, Alabama, and the HRI/HTI pilot facility were used to develop process improvements. The cost of direct hydro-liquefaction of coal was reduced by about 50 percent. The committee estimates that crude oil prices of at least $45/bbl are required for industry to commercialize in the United States. China is considering the option of importing U.S. technology for coal processing. dSuch as supported dual-pore catalysts and improved ebulated-bed reactors, letdown valves, and preheaters, and operating know-how related to corrosion, erosion, and fouling. eSuch as ebulated-bed reactors, letdown valves, and preheaters. The program also demonstrated ways to overcome problems typical of processing coal, such as corrosion, erosion, and fouling. uefaction technology is favored over direct liquefaction. This is because, although more expensive, indirect liquefaction has been commercialized and represents less risk. Further, the main components of the indirect liquefaction process, gasification to syngas and syngas conversion, are continuing to be improved for integrated gasification combined cycle (IGCC) and natural-gas-to-liquids processing, respectively. On the other hand, China seems to be seriously considering the direct coal liquefaction option. HTI has a signed a trade agreement with the Shenhua Group. The Chinese State Planning Commission has apparently narrowed the technology choices to the United States (HTI) and Japan (New Energy Development Organization). HTI claims the U.S. process is superior and estimates a project to produce diesel and gasoline in China will result in an 18 percent return on investment with its process. Improved reactor designs and improved catalysts resulting from the direct liquefaction program are also options for improved processing of heavy oil, such as from Canadian oil sands and the Orinoco belt in Venezuela. Other benefits from the direct coal liquefaction program are contained in the knowledge base created in coal chemistry, catalysis, and the operating experience from process demonstration. This knowledge will be valuable should R&D begin in this area in the future. Lessons Learned In retrospect, technology development in direct coal liquefaction and other synthetic fuels programs during the 1970s and early 1980s was not handled well by the government or industry. Technologies were targeted for major demonstration expenditures before they were well understood. The impact of high petroleum prices on worldwide exploration efforts and the positive impact of new technology on finding and producing crude oil were not fully accounted for. Another reason for the premature demonstration programs was the lack of a suitable ongoing long-term R&D program when the energy crisis began. It is expensive and ineffective to start and stop large, complicated R&D programs, especially in a rush created by crisis. A related lesson learned from the program that followed the demonstrations is that steady application of R&D over an extended period can significantly reduce costs, improve process operability, and improve product quality. FLUIDIZED-BED COMBUSTION Program Description and History The fluidized-bed combustion (FBC) program consists of two related but different technologies: (1) atmospheric bub-
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 bling and circulating atmospheric fluidized-bed combustion (AFBC) and (2) pressurized and advanced pressurized fluidized-bed combustion (PFBC). The technologies utilize similar combustion principles; however, one operates in atmospheric pressure (AFBC) and the other under pressure (PFBC). FBC technology was developed in the mid- to late 1960s by the Department of the Interior’s Office of Coal Research to produce a compact coal boiler that could be pre-assembled at the factory and shipped to a plant site at lower cost than conventional technology. In the 1970s the government’s R&D was driven by rising costs of petroleum and natural gas, by pressures to reduce oil imports, and by a desire to capture sulfur compounds during the combustion process (OFE, 2000a). As a result, research focused on use of the technology as a substitute for primarily oil-fired industrial boilers and to improve FBC efficiency and environmental performance. Some work was done on using anthracite culm in Pennsylvania as a feedstock for the technology. In the 1980s, the program focused heavily on demonstration of AFBC technologies and development of advanced pressurized fluidized-bed combustion systems. The latter, built on research begun in England (some of which had been done in collaboration with DOE), was developed primarily for energy security reasons (i.e., utilization of domestic energy resources) and growing environmental pressures. EPA was also involved in the early development of FBC technology. By 1990, first-generation atmospheric FBC technologies were commercial. The emphasis of the AFBC program turned to special applications for the technologies (e.g., low-cost, low-valued fuels such as medical wastes, waste tires, and petroleum coke), with much of the work being conducted on commercial products. PFBC technology development became focused on improving its energy efficiency and environmental performance and on reducing its capital cost to allow it to compete against the use of coal in IGCC systems. Both AFBC and PFBC technologies were (and continue to be) demonstrated in the Clean Coal Technology (CCT) demonstration program. However, it is the view of the committee, based upon discussions with representatives of the private sector, that the market potential for FBC will be limited by continued tightening of environmental requirements, continued technical issues, and the high capital costs in comparison with other electric power options. Funding and Participation From 1978 through 1999, DOE invested a total of $843 million (in constant 1999 dollars) on FBC research, development, and demonstration (RD&D); $298 million on AFBC systems; and $545 million on PFBC systems. Of this amount, it invested approximately $39 million in AFBC and $118 million in PFBC to demonstrate the technologies in the CCT demonstration program. Cost sharing for the program came primarily during the demonstration phase of the program, with industry providing $408 million ($223 million for AFBC and $185 million for PFBC) (OFE, 2000a). Although information is quite limited on other private sector investments in the development and demonstration of the technologies, it is expected that the investments are very significant. Expenditures on AFBC R&D (excluding demonstration) were $259 million. The major subprograms of the AFBC program included the following: Early industrial and utility demonstrations, $227 million; Advanced concepts, $12 million; and Advanced research, $7 million. DOE has not been allocated money for AFBC RD&D since 1993. Expenditures on PFBC R&D (excluding demonstration) were $427 million. The major subprograms of the PFBC program included the following: Test rigs and pilot plants, $96 million; International Energy Agency (IEA)/Grimethorpe (collaborative RD&D with Great Britain and Germany), $82 million; Advanced concepts, $61 million; Wilsonville test facility, $50 million; and Hot gas cleanup, $46 million. The current PFBC program, funded at approximately $15 million, revolves around testing of advanced system configurations, including hot gas cleanup at the Wilsonville test facility in support of Vision 21. Results AFBC technology is now commercially available. Every U.S. boiler manufacturer (and many foreign boiler manufacturers) offers the system in its product line. Over 400 modern, industrial-scale AFBC boilers are in operation throughout the world, 170 of them in the United States, primarily using low-cost fuel and waste as their feedstocks. DOE estimates that more than $6 billion in domestic sales and nearly $3 billion in overseas sales have resulted from the public and private investment in AFBC technology. Demonstrations up to 300 MW are under way to prove the technology for coal-based utility applications (Robert Wright, DOE, e-mail communication, January 4, 2001). For dispatch and availability reasons, most operators prefer AFBC systems to be between 250 and 400 MWe. The ability of AFBC systems to meet future environmental requirements and remain economically competitive may hamper commercial use of the technology for utility applications. However, it will continue to play a
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 role in using low-cost and waste fuels for smaller-scale operations if the technology can economically meet environmental requirements. PFBC technology is still in the early demonstration stage. Three 80-MW demonstrations have been conducted in the United States and Europe to demonstrate the technical viability of the first generation systems. Scale-up to 157 MWe in the United States and 350 MWe in Japan are under way. Although there were some technical successes in the first demonstration plants, the first-generation systems suffer from high costs that will inhibit widespread utilization of the technology. In addition, first-generation systems do not offer efficiency and/or economic advantages over conventional technology and are larger emitters of air pollutants than the IGCC and gas turbine combined-cycle technologies. Second-generation systems are in their infancy. Although demonstration of a system is part of the CCT demonstration program, the committee is of the opinion that serious concerns exist over the ability of the turbines to withstand alkali vapors from the PFBC and to meet stringent future environmental requirements without costly add-on control systems. Both concerns may hamper commercial applications of the technology. Both concerns were confirmed by interviews with private sector PFBC experts (M.Marrocco, Renewable Energy and Advanced Power Systems, American Electric Power, personal communication, February 2001; D. Wietzke, Babcock & Wilcox, personal communication, November 9, 2000). DOE’s involvement in developing both AFBC and PFBC technologies was critical to their technological development. Conversations with private sector FBC vendors and utility technology managers indicate broad acceptance of the critical role played by DOE in the advancement of the technologies. Without DOE’s involvement, AFBC technology would have lagged by several years. Without DOE’s involvement, PFBC technology may not have ever advanced to its current stage because of the high technical risks and high costs associated with its development. Benefits and Costs The benefits and costs of the FBC program are shown in Table F-4. The realized economic benefits of DOE’s FBC RD&D programs are estimated to be moderate. PFBC technologies have not been used commercially and therefore have provided no realized economic benefits thus far. Considering the high costs and significant competition facing first-generation PFBC systems, the committee questions whether realized benefits will ever be realized. Likewise, considering the extremely difficult technical and economic challenges facing second-generation PFBC systems, the committee questions the potential of this technology as well. In addition, compared with the next-best alternative, pulverized coal boilers with stack gas cleanup, AFBC systems using coal offer no economic advantages. However, when using low-value fuels that pulverized-coal technology cannot efficiently and economically burn, AFBCs have an economic advantage (estimated to be $0.25/MMBtu in fuel cost). Therefore, realized economic benefits can be assigned to TABLE F-4 Benefits Matrix for the Fluidized-bed Combustion (FBC) Programa Realized Benefitsb/Costs Options Benefits/Costs Knowledge Benefits/Costs Economic benefits/costs DOE RD&D costs: $843 million, 1978–1999 Industry costs: $408 million Benefits from combustion of Pennsylvania culm banks: $750 millionc Realized benefits result from AFBC, not PFBC AFBC is available as an option for alternative feedstocks; PFBC is not Development of new information on in situ sulfur recovery, waste fuel preparation, feeding, combustion, and hot gas particulate removal technology and materials Environmental benefits/costs Benefits from excess NOx reductions: cumulative 900,000 tonsd Cleanup of unwanted wastes currently disposed of in landfills Use of waste products as a fuel FBC wastes neutralize coal field acid water runoff Expands the potential to use waste fuels at lower NOx emission levels Mine acid neutralization, utilization of FBC wastes for roadbed materials and cement aggregates Security benefits/costs None None None aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000. bBenefits based on a comparison of FBC with a market-based PC steam generator. cTotal benefits are estimated at $1.5 billion, one-half of which are allocated to DOE, since it played a significant role in FBC development. dThese represent one-half of the total NOx reduction.
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 early (1978 to 1983) DOE RD&D investments that allowed anthracite culm to be used as the feedstock for producing power and heat. Six FBCs using 8.4 million tons of anthracite culm were in operation in 1996. These and FBC anthracite culm plants planned to be built by 2005 are the basis for realized economic benefits. Assuming a 30-year life cycle, these projects are estimated to save $1.5 billion in cumulative fuel costs (constant 1999 dollars). Attribution of these benefits to DOE is difficult to determine. However, since DOE did play an influential role in developing the technology, the committee believes that it is reasonable to attribute one-half of these ($750 million) savings to it. The committee believes that realized environmental benefits may also be attributed to DOE’s AFBC RD&D investment. Many of the AFBC combustors built in the United States prior to 1995 (i.e., 5200 MW) inherently emitted significantly less NOx than required by law. DOE calculates that NOx emissions from AFBC plants were approximately one-half those from conventional pulverized coal plants that probably would have been used as the next-best alternative had AFBC technology not been available. Because DOE played such an important role in development of the technology, one-half of the NOx reduction benefits (900,000 cumulative tons) is attributed to DOE’s research. The committee believes that especially when using low-rank coals, AFBC systems provide economic and environmental benefits as options to pulverized-coal boilers with flue gas desulfurization systems, the other technologies that can service the specialty industrial market. When using low-cost, low-valued fuels, AFBC systems can show economic advantages over the next-best alternative, small combined-cycle or simple-cycle gas turbine plants. These AFBC systems using waste fuels also emit less NOx than alternatives that burn waste fuels. Other environmental benefits result from the cleanup of unwanted wastes that are currently disposed of in landfills. PFBC systems do not offer these benefits, since they will compete with IGCC and large-scale gas turbine combined-cycle gas plants that are being evaluated and which should have better economic and environmental performance. In addition, PFBC is not commercially available at this time and therefore does not fit the committee’s definition of an option. The committee is of the opinion that RD&D conducted by DOE in both the AFBC and PFBC areas added significantly to the knowledge base. Knowledge benefits include important new information on the following: Basic coal science; In situ sulfur recovery; Waste fuel preparation, feeding, and combustion; Mine acid water neutralization (utilizing FBC wastes for neutralizing coal mine acid water runoff); Utilization of FBC wastes for roadbed materials, cement aggregates, and other uses; and Hot gas cleanup technology and materials that can be used for many industrial applications in addition to PFBC. No security benefits are attributed by the committee to DOE’s RD&D on FBC since they do not meet the security criteria defined by the committee. Lessons Learned In the opinion of the committee, DOE’s FBC RD&D program is a good example of a successful public/private sector partnership to develop technology for a variety of applications. DOE’s involvement in the conceptualization and early proof of concept attracted industry to conduct its own research and to provide significant cost sharing to DOE as the technologies advanced to pilot and demonstration scales. The program also illustrates the long period of time and significant costs required to develop coal-based technology and bring it to market (25 years in the case of AFBC). Over the many years that are required to develop and demonstrate such technologies, market conditions change, creating either opportunities or disappointments. In the case of FBC, tightening environmental requirements and the development of competing technologies reduced the market potential considerably. However, the availability of low-cost opportunity fuels that could be economically combusted in AFBCs while meeting environmental requirements has created market opportunities for the technologies domestically and internationally. In the committee’s opinion, the PFBC program also illustrates a DOE initiative that was initiated to support industry efforts to meet important national needs, namely environmental requirements (especially as an alternative to reduce SO2 emissions from coal-fired power generators) and as a hedge against rising oil and gas prices. However, it is an example of a research program that may have been supported too long. Over the life of the program, environmental concerns changed, as did the factors that drive electric utility generation decisions. At the same time, other more promising technological options that meet the same national needs advanced. The basic PFBC technology has been demonstrated at a reasonable scale. Research over the last several years is viewed to have valuable knowledge benefits but will probably not ever have realized economic benefits, even if current research goals are met. This is an example of a program that would have benefited from a critical peer review before significant expenditures were made on full-scale demonstrations. GAS-TO-LIQUIDS TECHNOLOGY Program Description and History The Gas-to-Liquids Technology program is part of the Natural Gas Processing and Utilization program, which has
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 the goal to support the development of advanced gas upgrading and conversion processes to bring low-grade gas up to pipeline standards and to convert stranded gas in the United States to more readily transportable high-value liquid fuels and feedstocks. Commercial technologies to convert gas to liquids are well known (NRC, 1990). The major processes are Fischer-Tropsch, methanol, and methanol to gasoline. The gas-to-liquids portion of this program has the primary objective of lowering the cost of the existing Fischer-Tropsch process for converting natural gas to liquid hydrocarbons. During the mid-1980s, emphasis was on basic research on gas conversion to fuels and chemicals. In the early 1990s, the program focused more on process development to make chemicals and fuels by partial oxidation, oxidative coupling, and pyrolysis. Currently, the program focuses on novel technologies to generate synthesis gas and improved gas conversion to fuels with emphasis on monetizing stranded natural gas in Alaska and deep offshore. Funding and Participation Table F-5 shows investments in the Gas-to-Liquids Technology program over the last 22 years (constant 1999 dollars). The program has been well supported by industry, which averaged about 50 percent cost sharing. Over the years, industry contributed 20 percent for basic research, a minimum of 50 percent for pilot and demonstration projects, and about 65 percent for some large-scale projects. Table F-6 focuses on the current Gas-to-Liquids Technology program technology mix. Results Synthesis Gas Production Research work has been directed toward improved methods for producing synthesis gas from natural gas. For example, ceramic membrane technology is being developed to TABLE F-5 DOE Investments in the Gas-to-Liquids Program, FY 1978 to FY 2000 (millions of 1999 dollars) Program DOE Investment Synthesis gas production 25 Fischer-Tropsch synthesis 4 Liquefied natural gas 3 Novel conversion technology 33 Oxyhydrochlorination 1 System and economic studies 3 Total 79 SOURCE: Office of Fossil Energy. 2000b. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Gas-to-Liquids Technology, December 4. TABLE F-6 DOE Investments in the Gas-to-Liquids Program, 1999 (millions of 1999 dollars) Program DOE Investment Liquefied natural gas 0.8 Novel conversion 0.5 Systems and economic studies 0.6 Total 1.9 SOURCE: Office of Fossil Energy. 2000b. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Gas-to-Liquids Technology, December 4. separate oxygen from air to reduce the cost of synthesis gas manufacture. Fischer-Tropsch Synthesis Research has been directed toward laboratory and pilot plant studies on novel iron-based Fischer-Tropsch catalysts and new reactor concepts. Liquefied Natural Gas Research work is directed toward the development of a thermoacoustic Stirling hybrid engine to produce refrigeration that would improve the efficiency of the liquefied natural gas liquefaction process. Novel Conversion Technology Research work is directed toward the use of an electric field to activate and enhance methane conversion. Oxyhydrochlorination Research work was directed to a novel process for converting natural gas to liquid fuels and chemicals, in which methane is chlorinated in the presence of oxygen and hydrogen chloride. Research work was terminated due to unfavorable economics. Systems and Economic Studies System studies have been carried out to evaluate how gas-to-liquids technologies compare with other options. Benefits and Costs The program is a mix of effort, from exploratory research projects (such as the use of an electric field to activate methane) to scale-up studies (such as Fischer-Tropsch reactor
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 TABLE F-7 Benefits Matrix for the Gas-to-Liquids Programa Realized Benefits/Costs Options Benefitsb/Costs Knowledge Benefits/Costs Economic benefits/costs DOE R&D costs: $45 million Industry costs: $45 millionc No realized benefits None Research on novel methods to produce syngas, to activate methane, and to liquefy natural gas R&D on improved methods for producing synthesis gas from natural gasd Laboratory and pilot plant studies on novel iron-based Fischer-Tropsch catalysts and new reactor concepts Development of a thermoacoustic Stirling hybrid engine to produce refrigeration to improve efficiency in the LNG liquefaction process Research on the use of an electric field to activate and enhance methane conversion R&D on oxyhydrochlorinatione Systems and economic studiesf Environmental benefits/costs None None None Security benefits/costs None None Noneg aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000. bFE claims substantial options benefits for gas to liquids, especially after 2005, including $24 billion in energy savings, increased domestic production of liquid transportation fuels, avoidance of the need to build an LNG pipeline from Alaska, and the possibility of CO2 sequestration. However, industry experts believe that the assumption that any significant quantity of natural gas in the United States could ever be valued (relative to oil) low enough to justify conversion to liquid fuels by conventional gas-to-liquids technologies is questionable. Also, the recent increase in gas prices has even made the gas in the Alaska North Slope sufficiently valuable that the oil industry is now considering moving it via a new pipeline into the lower 48 states. Thus, the options benefits for gas to liquids are negligible. cThe program has been well supported by industry. It has averaged about 50 percent cost sharing with industry, reflecting 20 percent for basic research, a minimum of 50 percent for pilot and demonstration projects, and about 65 percent for some large-scale projects. dFor example, ceramic membrane technology is being developed to separate oxygen from air to reduce the cost of synthesis gas manufacture. eResearch was conducted on a novel process for converting natural gas to liquid fuels and chemicals, in which methane is chlorinated in the presence of oxygen and hydrogen chloride. However, the research was terminated due to unfavorable economics. fSystem studies have been conducted to evaluate how gas-to-liquids technologies compare with other options. gResearch on improving conventional gas-to-liquids technologies may improve our ability to convert truly stranded natural gas in other parts of the world to liquid fuel. While this may not reduce U.S. dependence on imports, it could diversify the supply base. An earlier example of this was work supported by the DOE predecessors to convert natural gas to methanol to gasoline using novel zeolite catalysts for the methanol to gasoline conversion. While this technology was never commercialized in the United States because of the high cost of natural gas, it was commercialized in New Zealand and for many years supplied one-third of the New Zealand gasoline supply. It reduced the demand for crude oil in the world market, albeit in a small way, thereby increasing supply and reducing price. A Fischer-Tropsch plant is currently operating in Malaysia on natural gas. design). To date there have been no economic benefits (Table F-7). One of the underlying assumptions in this program is that upgrading stranded natural gas to liquid products, particularly to high-quality diesel fuel, by Fischer-Tropsch synthesis will at some future time be feasible in the United States. Cited prominently in the DOE justifications is the potential for conversion of stranded natural gas from the North Slope of Alaska to a liquid fuel, allowing its transport to the lower 48 states in the existing pipeline. The assumption that any significant quantity of natural gas in the United States could ever be valued (relative to oil) low enough to justify its conversion to liquid fuels by conventional gas-to-liquids technologies seems questionable. This doubt stems from the low thermodynamic efficiency (less than 65 percent) for conversion of gas to liquids. An earlier NRC study recommended modest funding for gas-to-liquids technologies and that it be limited to fundamental and exploratory research (NRC, 1990). Also, the recent increase in gas prices has made the gas in the Alaska North Slope sufficiently valuable that the oil industry is now considering moving it via a new pipeline into the lower 48 states (Bloomberg Press Release, 2000). While the upgrading of natural gas to liquid fuels in the United States is unlikely, the exploratory work on novel methods to produce synthesis gas, novel ways to activate methane, and novel methods to liquefy natural gas add to our
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 nation’s store of knowledge and may eventually lead to domestic economic benefits. Also, research on improving conventional gas-to-liquids technologies may improve our ability to convert truly stranded natural gas in other parts of the world to liquid fuel. While this may not reduce our dependence on imports, it could diversify our supply base. An earlier example of this was work supported by DOE predecessors to convert natural gas to methanol to gasoline using novel zeolite catalysts for the methanol-to-gasoline (MTG) conversion. While this technology was never commercialized in the United States because of the high cost of natural gas, it was commercialized in New Zealand and for many years supplied one-third of New Zealand’s gasoline. This reduced the demand for crude oil in the world market, albeit in a small way, increasing supply and reducing price. A Fischer-Tropsch plant is currently operating in Malaysia on natural gas. Lessons Learned The DOE programs are focused in part on high-risk and exploratory research, which is appropriate considering that a major breakthrough is needed to justify the conversion of gas to liquids in the United States. On the other hand, programs focused on marginal improvements in existing technologies are unlikely to get enough of a cost reduction to make them domestically viable. DOE needs to critically assess the economic assumptions underlying the program. One is the above-mentioned availability of stranded low-cost gas in the United States. The other is inherent in the Ultra Clean Transportation Fuels program, which assumes that Fischer-Tropsch synthesis would be a more economic route to clean fuel than hydrogenation of conventional diesel fuel. Currently, neither of these assumptions seems warranted. IMPROVED INDIRECT LIQUEFACTION Program Description and History The primary goal of the improved indirect liquefaction program is to produce clean hydrocarbon fuels and/or oxygenated compounds such as methanol from coal. This is part of the DOE Clean Fuels Program conducted jointly by the Office of Fossil Energy and the Office of Energy Efficiency and Renewable Energy. Currently, technologies exist for the indirect liquefaction of coal. Coal is first converted to synthesis gas, carbon monoxide, and hydrogen. The carbon monoxide and hydrogen can then be converted to Fischer-Tropsch liquids or to methanol using commercially available technologies. The Fischer-Tropsch liquids can be refined into high-quality diesel fuel and gasoline. Methanol can be used as a fuel or chemical directly or converted to gasoline using the MTG process. In 1981, DOE started a program to improve the indirect liquefaction technologies. One goal of the program was to improve the Fischer-Tropsch process by improving the catalysts used and by improving the reactor design by utilizing the concept of a slurry bed. Another goal was to reduce the cost of methanol synthesis by using a liquid slurry bed approach similar to that developed for use in the Fischer-Tropsch process. Another goal was to study the feasibility of coproducing fuels and electricity to minimize costs. Funding and Participation The total R&D expenditure by DOE from 1981 to the present is $176 million in as-spent dollars and $224 million in constant 1999 dollars. Cost sharing amounted to about 17 percent of total project costs. Expenditures were about $7 million in 2000 (OFE, 2000c). In addition to the R&D expenditures, $96 million (constant 1999 dollars) was provided for the Liquid Phase Methanol Clean Coal demonstration project from 1993 to 1998. Cost sharing of the demonstration project amounted to 57 percent of the total cost of the project. Results Fischer-Tropsch Hydrocarbons Novel Catalysts. Considerable effort was put into the development of iron-based catalysts to improve the conversion of coal-derived synthesis gas, which typically has a low H:CO ratio. Iron-based systems are able to perform the water gas shift reaction so that the required stoichiometric ratio of H and CO can be achieved without external shift. Also, iron-based catalyst systems are less expensive than the cobalt-based systems otherwise used and produce valuable olefins as a by-product. Reactor Development. Hydrodynamic studies were run to understand the complex interactions of the three-phase slurry-bed reactor system. The studies included diagnostic analysis of hot and cold slurry streams and modeling of the hydrodynamics. Large-scale testing of both Fischer-Tropsch catalysts and slurry-bed reactor system components was undertaken at DOE’s Alternative Fuels Development Unit in LaPorte, Texas. Oxygenates/Chemicals Methanol. A major success of the indirect coal liquefaction program was the development of the liquid-phase methanol process. The principal feature of this new technology is the use of a slurry-phase reactor in which synthesis gas is converted to methanol over catalyst particles suspended in an inert liquid medium. The use of the slurry-phase reactor offers substantially improved heat management and operational versatility over the conventional gas
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 TABLE F-29 Benefits Matrix for the Improved Enhanced Oil Recovery Programa Realized Benefits/Costs Options Benefits/Costs Knowledge Benefits/Costs Economic benefits/costs DOE R&D costs: $177 million Industry costs: $47 million Benefits: $700 millionb Reserve growth from existing fields and recovery of larger amounts of movable oil Improved waterflooding and wettability Research on understanding and control of CO2-based enhanced oil recoveryc Fundamental research on miscibility of multicomponent systems New technologies for thermal-based enhanced oil recovery Development of microbial enhanced oil recovery Research on chemical methods, gas flooding, microbial methods, heavy oil recovery, novel methods, and reservoir stimulation Knowledge of geological and engineering parametersd Recognition of the importance of reservoir characterization in the deployment of EOR strategies Changed view of reservoirs and fluid behaviore Environmental benefits/costs Application of chemical EOR technology to water control problems, reducing water disposal and water pollution Microbial technology used for cleanup and remediation None Research on CO2 sequestration in geologic reservoirs Security benefits/costs Reduced oil imports None None aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000. bFE contends that its program is responsible for maintaining a critical mass of technology innovation in EOR and transferring this technology, particularly to independents. A net revenue value of 17.5 percent of sales revenues, equal to $3.50/bbl when the domestic price is $20/bbl, was used to convert incremental production to benefits. Net revenues were set at 17.5 percent of sales revenues and were linked to changes in domestic crude oil prices. FE R&D was allocated 2.8 percent of annual EOR production, which equals about 20,000 BPD of additional oil production in 2000 and 167 million barrels of cumulative additional oil production from 1978 to 2005. According to FE, this resulted in $625 million in industry savings and $87 million in incremental federal and state revenues, for a total of about $700 million. The estimates were developed using the Total Oil Recovery Information System (TORIS) and the Gas Supply Analysis Model (GSAM). cEspecially development of chemicals and foams for mobility control. dThe most significant information resulting from these early experiments with EOR was the knowledge that the geological and engineering parameters of individual fields were insufficiently known. eThe virtual failure of the early EOR field demonstrations in terms of direct benefits was extremely important to a changed view of reservoirs and fluid behavior. In addition, this early experience allowed redirection of the EOR program from field demonstrations to a more research-focused effort so that as complex reservoirs are understood well enough for effective deployment of EOR methods, better techniques will be at hand. tation of CO2-based EOR technology to CO2 sequestration in geologic formations. Lessons Learned The principal lesson learned from DOE’s activities in EOR programs stemmed from the marginal results obtained by the early EOR field demonstration programs. The conclusion drawn was simply that reservoirs were much more geologically complex than had previously been believed. Enhanced oil recovery techniques that worked well in the laboratory were difficult to deploy effectively in complex reservoirs. This led to programs in field demonstration that would substantially enlarge the ability to characterize complex reservoirs and the important finding that as much as half of the unrecovered oil in complex reservoirs could be recovered without expensive EOR techniques, if the reservoir and its fluid behavior could be properly understood. Consequently, reserve growth from exisiting fields with the recovery of larger amounts of movable oil has become a major element in U.S. production and in the projected resource base. For example, the Department of the Interior now estimates a resource base for oil and gas such that future reserve growth exceeds future new field discovery by 3 to 1
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 in the case of oil. The virtual failure of the early EOR field demonstrations in terms of direct benefits was critical to a changed view of reservoirs and fluid behavior. In addition, this early experience allowed redirection of the EOR program from field demonstrations to a more research-focused effort so that as complex reservoirs are understood well enough for effective deployment of EOR methods, better techniques will be at hand. FIELD DEMONSTRATION PROGRAM Program Description and History The Field Demonstration program, as the name implies, seeks to test different technologies and concepts at the field level. Such tests will result in incremental production and be classed as successful or they will fail. Field tests can also be technical successes but commercial failures. The Field Demonstration program has had a long and varied history, reflecting changed views about how reservoirs and the fluids within them behave, the evolution of different deployable technologies, and, of course, varying oil prices. The original Field Demonstration program was begun by the Bureau of Mines in 1974 and transferred to DOE in 1978. It was designed to test the efficacy of different EOR technologies. The conventional wisdom of the time, shared by government and industry, was that oil remaining in reservoirs after conventional primary and secondary recovery was residual or immobile oil, that is, the reservoir or the fluids within the reservoir must be either physically or chemically modified to render the oil mobile and recoverable. This was acknowledged to be an expensive process due to the cost of EOR techniques, but oil prices were historically high at the time and widely expected to be much higher. Twelve of the original field projects tested chemical floods, five involved CO2 injection, and six were thermal/heavy oil projects. The projects directly involved industry with substantial cost sharing. While some incremental oil was produced from some of the projects, most were uneconomic, especially those with chemical floods, and to a lesser extent, those involving steam and gas injection. These early EOR field tests were to show dramatically that the geological and engineering parameters of individual fields were poorly understood. Most reservoirs, especially those containing large volumes of unrecovered oil, were much more complex geologically than had been expected. This recognition, plus the policies of the incoming administration in the early 1980s, led to a substantial reduction and redirection of the program. In the early 1980s, analyses by the Texas Bureau of Economic Geology of the 450 largest reservoirs in Texas were to show that about half of the oil remaining in existing reservoirs and classed as unrecoverable was, in fact, mobile oil and that the volume of remaining unrecovered mobile oil was directly related to complexity or heterogeneity of reservoirs (Galloway et al., 1983). That complexity was shown to be primarily related to the architecture of the reservoir, which in turn resulted from its depositional origin. Improved understanding of the geological and engineering parameters of reservoirs could lead to increased recovery of mobile oil by advanced secondary recovery techniques, but without adequate understanding of the heterogeneity of a reservoir, deployment of advanced recovery technologies was likely to be ineffective. The Texas study also showed that a large universe of reservoirs could be grouped into plays based on common depositional origin and common fluid behavior. Thus, the knowledge of a fully characterized reservoir could be directly extrapolated to other reservoirs in the play. DOE adopted the play concept, applied it nationwide, and instituted in the mid-1980s the Reservoir Life Extension Field Demonstration program, which would be called the Reservoir Class Program in the early 1990s. This was also a time of low to very low oil prices, when a large number of reservoirs were in danger of premature abandonment. In the 1990s it was also clear that the domestic oil industry was being operated by a larger percentage of independent producers than now. Funding and Participation The cost of the Field Demonstration program from 1978 to 1999 was $259 million (1999 dollars) plus the industry cost share of $368 million (see Table F-30). Approximately one-half of the budget was spent on the initial 23 EOR field demonstrations and the other half on some 39 projects of the Reservoir Class Program (OFE, 2000q). Results Using its TORIS (Total Oil Recovery Information System), DOE calculates that the Field Demonstration program will result in 1291 million barrels of incremental oil production and 1736 Bcf of incremental gas production from 1996 to 2005. It also assumes that net revenues will amount to 17.5 percent of sales revenue, that 4 to 6 percent of production will come from federal lands; and that state severance taxes will average 4.55 percent. These conditions applied to the calculated volume of increased incremental production give net revenues to industry of $4462 million (1999 dollars). The DOE expenditure for the program from 1978 to 2000 amounts to $259 million (1999 dollars) with an industry cost share of $368 million (1999 dollars). This yields a benefit to cost ratio of 17.2 to 1, or 7.1 to 1 if the industry cost share is included. DOE calculates $758 million (1999 dollars) from federal royalties and additional state severance taxes due to displacement of imports. In addition, improved screening models and a number of software programs have been developed and are now being used by industry and researchers.
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 TABLE F-30 Benefits Matrix for the Field Demonstration Programa Realized Benefits/Costs Options Benefits/Costs Knowledge Benefits/Costs Economic benefits/costs DOE R&D cost: $259 millionb Industry costs: $368 million Estimated benefits of $2.2 billionc None Postmortems of enhanced oil recovery and thermal recovery processes suggest directions for future applications and future research Enhanced recovery screening models and software programs for use by industry Reservoir characterization and class definitiond Determined that the geological and engineering parameters of individual fields were poorly understoode Data used to predict domestic industry productivity and potentialf Mobilized the technical expertise of domestic industry to improve efficiency and made it widely available Environmental benefits/costs Reduced air emissions, surface footprints, and waste volumes Reduced water productiong Demonstration of technologies with minimal impact in harsh and sensitive environments Subsurface imaging and chemical treatments that could be applied to near-surface or surface environmental problems Security benefits/costs Increased U.S. oil production Maintenance of U.S. oil industry infrastructure and ability to increase production if required None aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000. bApproximately one-half of the budget was spent on the initial 23 EOR field demonstrations and the other half on 39 projects of the Reservoir Class program. cFE estimates using TORIS (Total Oil Recovery Information System) that the Field Demonstration program will result in 1291 million barrels of incremental oil production and 1736 Bcf of incremental gas production from 1996 to 2005. It assumes that net revenues amount to 17.5 percent of sales revenue, that 4 to 6 percent of production comes from federal lands, and that state severance taxes average 4.55 percent. These conditions applied to the estimated volume of increased incremental production yield estimated net revenues to industry of $4462 million. FE also estimates that the program will generate $758 million from federal royalties and additional state severance taxes due to displacement of imports. Based on the above, the committee assigned a benefit to DOE of $2.2 billion. dIn terms of direct economic benefits, the Reservoir Class program predicated on reservoir characterization and play or class definition was dramatically more successful than the original field demonstration, where the tested reservoirs were not well characterized, and it is generally regarded in industry and the research community as one of DOE’s most successful programs. eThe program demonstrated that about half of the oil remaining in existing reservoirs classified as unrecoverable was, in fact, mobile oil and that the volume of remaining unrecovered mobile oil was directly related to the complexity or heterogeneity of reservoirs. It showed that oil and gas reservoirs, with very few exceptions, were much more complicated than previously believed. It also proved that most reservoirs, especially those containing large volumes of unrecovered oil, were much more complex geologically than expected, and that effective deployment of any reservoir technology depends on thorough geologic characterization of the reservoir. fData for evaluation of the industry capabilities are collected throughout the life of the projects, and these data can be used to predict domestic industry productivity and potential. gThis results from better reservoir management and better well placement attributable to improved technology. Benefits and Costs Based on the above, the committee assigned a benefit to DOE of $2.2 billion (see Table F-30). Lessons Learned The basic lesson learned early on was that oil and gas reservoirs, with very few exceptions, were much more complicated that previously believed. With that recognition came the important lesson that effective deployment of any reservoir technology depends on thorough geologic characterization of the reservoir. The best recovery technology deployed into a poorly understood reservoir is ineffective, or if by chance it is effective, the operator will not know why and will not be able to repeat the success. In terms of direct economic benefits, the Reservoir Class program predicated on reservoir characterization and play or class definition was very much more successful than the original field demonstration, where the tested reservoirs were not well character-
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 ized, and it is generally regarded in industry and the research community as one of DOE’s most successful programs. Another important lesson learned in the program was the need to reflect changed perceptions of the nature of unrecovered oil and to adjust to wide swings in oil and gas prices. OIL SHALE Program Description and History Long before DOE’s creation in 1977, the tremendous potential of the Rocky Mountain oil shale deposits led to industry and government interest in researching their possible use. Every time a crude oil shortage threatened in the 20th century, interest in oil shale would be renewed, only to ebb as the threat diminished. The energy crises of the 1970s were the most recent instance of looking to oil shale to expand our energy supply base. The strong industry interest over the years is evidenced by private sector expenditure of over $3 billion on oil shale R&D. In contrast, total federal spending is estimated at about $400 million. Since its creation in 1977, DOE has spent about $273 million ($447 million in constant 1999 dollars) on oil shale R&D. Only minor amounts have been spent since 1993, when it became clear that crude oil shale production was not close to being economic. Several technologies are involved in using oil shale, including mining and comminution, direct use for power generation, retorting for the recovery of oil or gas from shale, the upgrading/refining of recovered oil, and processing for specialty by-products. Environmental R&D has been another significant component, because recovering shale oil would create many environmental challenges. DOE has supported efforts in each of these areas, with some being emphasized more than others. Mining and comminution. Issues here related to how to mine and crush the mined shale. DOE has supported waterjet-assisted mining projects, blasting patterns for mining, and ways to control crushing of shale. Power generation. Other countries, such as Estonia and Israel, have used or tried to use shale oil to generate power. From 1978 to 1982, DOE had a memorandum of understanding with Israel to develop technologies for the utilization of Israeli shale oil. Retorting. Shale oil can be retorted on the surface or in situ. Surface retorting requires mining the shale and bringing it to a retort facility on the surface. In situ retorting involves various approaches to creating a retort situation within the site or below surface. DOE supported both types of retort efforts. Efforts supported included the Paraho project, which tested, with some DOD funding, the suitability of using shale oil for military fuels, and the Occidental oil shale vertical modified, in situ process. DOE also supported testing of true in situ technology, where no mining preparation was done, and the use of in situ techniques on Eastern oil shale, both of which were unsuccessful. The government also supported the Unocal project through a Treasury Department price guarantee for each barrel of oil produced. Before project termination in 1991, 4.7 million barrels of oil (total) were produced. The high cost of a project modification for an external carbon combustor led to termination of the Unocal project. Upgrading/refining. A critical refining issue for Western shale is the removal of nitrogen. Given the shale recovery issues, DOE has not done much in this area, although some bench-scale tests have been done on nitrogen removal. Specialty by-products. From 1978 through 1982, DOE did some research on adding high-nitrogen-content Green River shale oil to paving asphalt binder to achieve a longer-life asphalt pavement. Small contracts have been used to examine ways to extract high-value nitrogen compounds from Green River oil shale. Tests have also been done on using spent shale as a support layer for asphalt pavement, as a way of reducing spent shale disposal costs. Environmental. Almost one-third of DOE R&D funding for oil shale involved environmental studies because of the potential impacts on air quality, water quality, and soil revegetation. Funding and Participation DOE’s funding history for oil shale is shown in Table F-31. As Table F-31 shows, more DOE funds were spent in TABLE F-31 Funding for the Oil Shale Program Year Actual $ Constant 1999 $ 1978 28.9 62.8 1979 45.2 90.7 1980 28.2 51.8 1981 33.0 55.5 1982 19.1 30.2 1983 12.2 18.6 1984 16.2 23.7 1985 14.8 21.0 1986 12.6 17.6 1987 11.0 14.8 1988 9.6 12.4 1989 10.5 13.2 1990 9.1 11.1 1991 9.2 10.8 1992 5.9 6.8 1993 5.4 6.0 NOTE: In 1997 about $500,000 and in 2000 less than $100,000 in oil shale funds were provided for a contractor to do work on extracting nitrogen from Green River oil shale. SOURCE: Office of Fossil Energy. 2000r. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Oil Shale Technology, December 12.
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 the late 1970s and early 1980s, close on the heels of the energy crises. When the crises abated, funding was reduced until it was essentially terminated after 1993, when Congress passed a bill amendment eliminating support for oil shale R&D. This amendment passed after decisions by Exxon, Unocal, and Occidental to cancel their oil shale projects. As discussed in the program history section above, industry has long been interested in oil shale potential and over the long term has spent over an estimated $3 billion. A significant amount of DOE funds supported various retorting projects and environmental studies. Other much smaller amounts supported mining and comminution and specialty by-products R&D. Industry cost-shared on some of the projects at the 50 percent level (New Paraho SOMAT technology, Occidental VMIS technology, super-heated steam in situ, and Sohio refinery modification). The Department of Defense provided a $15 million cost share for a project testing shale oil as a military fuel. Viewed from another perspective, DOE estimates that the funding breakdown was about 16 percent basic research, 56 percent applied research, and 28 percent technology demonstration. About 40 percent of total funding flowed through the national laboratories and universities. Results Although oil shale R&D was essentially terminated after 1993, the DOE program and industry efforts provided much information should the nation’s energy situation and the economics of shale recovery refocus attention on its potential as a domestic energy source. DOE involvement shortened the time for some of the retort technology demonstrations. Without DOE involvement, the water-jet-assisted miner would not have been tested. Work on Eastern shale provides an initial base of understanding of the issues related to its potential development and use. Work on true in situ technology is an example of a negative result, having demonstrated that the approach will not work. In the specialty by-product area, DOE uncovered the potential for paving with asphalt derived in part from shale oil. DOE continues to believe oil from shale has great potential for future use. Benefits and Costs As shown in Table F-32, all of the benefits of oil shale R&D are in the options and knowledge columns. The ultimate use of knowledge gained or options identified will depend on international events and domestic energy and economic developments and on our ability to find ways to deal with the environmental problems associated with oil shale development. While most of the program attention has been on using shale oil as a refinery feedstock to alleviate U.S. reliance on foreign oil, its potential use in asphalt for highway paving, should it prove economic, could lead to substantial realized benefits. Lessons Learned DOE is not alone in supporting R&D to find ways to economically use the nation’s vast oil shale resources. Over the years, private industry has spent much more than DOE and the federal government in total. When (if ever) oil prices and our energy situation create the need to once again turn to oil shale, the R&D gives us considerable knowledge about what technologies might or might not work. Oil shale R&D also demonstrates the sometimes surprising ways in which spin-offs of the research occur. The potential for using shale oil to create longer-life asphalt pavement was discovered when researchers noted that the road to a retort facility was remarkably free of potholes and began to do laboratory tests to determine why. The road was built with asphalt from shale oil because of its ready availability, and the tests confirmed that the nitrogen compounds in the shale oil served to chemically link and strengthen the asphalt. DOE believes that any use of shale oil for refinery feedstock is not likely to occur until after 2030. It also believes there is a strong possibility that shale oil will be used in asphalt paving before 2010. SEISMIC TECHNOLOGY Program Description and History The remarkable advances in digital computation capability over the past several decades have resulted in tremendous improvements in the acquisition and processing of reflection seismic data. With more precise, higher-resolution imaging of the subsurface, success rates in oil and gas exploration have improved substantially; in some areas, such as the offshore Gulf of Mexico, 50 percent exploration success is common, and in some areas, rates are even higher. High-resolution, three-dimensional (3D) seismic shots over old existing fields show that reservoirs generally are much more complex and compartmentalized than had previously been thought, allowing strategic infield drilling and substantial increases in oil and gas recovery or reserve growth. Time-lapsed 3D seismic (so-called 4D seismic) allows assessing fluid movement and behavior in a producing reservoir, an assessment that permits greater and more efficient recovery. The principal results have been to reduce significantly the cost of finding hydrocarbons and to situate wells for optimum productivity. The advances in seismic technology have been developed mostly by industry, although certain aspects of the DOE program have improved seismic technology. Seismic technology development became a major focus for DOE in 1988 with the creation of the Oil Recovery Technology Partnership, designed to bring the scientific expertise of the national laboratories to bear on to the challenge of improving oil recovery. The producing industry involved in the partnership established that seismic technology, particularly cross-well
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 TABLE F-32 Benefits Matrix for the Oil Shale Programa Realized Benefits/Costs Options Benefits/Costs Knowledge Benefits/Costs Economic benefits/costs DOE costs: $448 millionb Industry investments: $3 billionc No realized economic benefits—technology not commercialized Oil shale technology available if economic conditions permit exploitation of U.S. shale oil resourcesd R&D on mining and comminutione Research on retortingf R&D on specialty by-productsg The blasting models developed are widely used for blasting operationsh Development of the water-jet-assisted mineri Development of information and databases necessary to facilitate productionj Environmental benefits/costs None SOMAT paving would reduce emissions in highway maintenance, but overall the challenge will be to eliminate the environmental impacts of oil shale recovery Extensive environmental R&Dk Security benefits/costs None Less imported crude oil aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000. bThe funding breakdown was 16 percent basic research, 56 percent applied research, and 28 percent technology demonstration, and 40 percent of the funds flowed through universities and the DOE labs. cMost of this was spent independently by Exxon, Unocal, and Occidental. dU.S. oil shale resources are larger than Middle East oil resources, and shale oil can be converted to substitute for imported crude oil. While FE anticipates that use of oil shale for refinery feedstock is not likely prior to 2030, the program established the potential of shale oil to replace crude oil. eIssues here relate to how to mine and crush the mined shale, and FE has supported water-jet-assisted mining projects, blasting patterns for mining, and ways to control crushing of shale. fShale oil can be retorted on the surface or in situ, and FE has supported both types of retort efforts. gFE conducted R&D on adding high-nitrogen-content Green River shale oil to paving asphalt binder to achieve a longer-life asphalt pavement, examined ways to extract high-value nitrogen compounds from Green River shale, and tested the use of spent shale as a support layer for asphalt pavement. hThe blasting models developed by Sandia National Laboratory are widely used in blasting operations and facilitate the size and placement of explosives and the sequencing of their detonation to achieve desired blasting results with controlled effects and minimum explosive cost. iFE support accelerated development of the water-jet-assisted miner. jThe program provided substantial information on the technology and economics of shale oil recovery, and DOE involvement accelerated the retort technology demonstrations. Work on Eastern shale assessed its potential, while work on in situ technology demonstrated that it will not work. kApproximately one-third of all R&D costs were for environmental studies covering air quality, water quality, soil revegetation, and other potential environmental problems. seismic, should receive the most program attention. Further impetus for the application of seismic technology came with the Reservoir Class program, in which the various field projects began to adopt seismic technology for the reservoir characterization phase. The Seismic Technology program has also involved the development of new processing algorithms written to resolve some of the problems inherent in 3D subsalt imaging and a project in 4D seismic with the Lament Doherty Earth Observatory. The initial justification for DOE’s role in the Seismic Technology and Technology Partnership was to provide the oil industry, especially independent operators, with a mechanism to access expertise, facilities, and technology at the national laboratories. This was followed in 1995 by the Advanced Computational Technology Initiative to increase industry access to seismic technology and to the high-performance computational power established by the national laboratories for defense purposes. Funding and Participation The Seismic Technology program expended $106 million (1999 dollars) from 1989 to 2000 and plans to expend $161 million (1999 dollars) more through 2005 (see Table F-33). Funds to date have been distributed to industry ($4.9 million), to universities ($5.6 million), to DOE national laboratories ($32.6 million), and to the Class Reservoir program ($62.5 million). Outside cost sharing amounted to $109 million (1999 dollars), with $850,000 coming from industry, $2.2 million from universities, $29.1 million from the DOE laboratories, and $76.8 million from the Reservoir Class program (OFE, 2000s). Results The Seismic Technology R&D program has developed a series of products that have become commercially viable.
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 TABLE F-33 Benefits Matrix for the Seismic Technology Programa Realized Benefits/Costs Options Benefits/Costs Knowledge Benefits/Costs Economic benefits/costs DOE R&D costs: $106 millionb Industry cost share: $3 millionc Benefits of $600 milliond Produced incremental oil and natural gase None Knowledge base of reservoir propertiesf Knowledge base of seismic acquisition, processing, and interpretationg R&D on 3D/3C and 4D seismich,i Algorithm development Environmental benefits/costs Fewer wells drilled, reducing potential environmental impacts and reduced water production from drilling None Development of technology to reduce environmental impact and costs of future oil exploration and drilling Near-surface and deeper seismic imaging may be applied to resolve environmental problems Security benefits/costs Reduced oil imports As technologies are shared with other nations, oil supplies and reserves could be increased, prices stabilized, and U.S. oil imports diversified None None aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000. bThe funds were distributed to industry ($4.9 million), universities and colleges ($5.6 million), the national laboratories ($32.6 million), and the Class Reservoir program ($62.5 million). cThe cost shares were industry, $850,000; universities and colleges, $2.2 million; the DOE laboratories, $29.1 million; and the Class Reservoir program, $76.8 million. dFE estimated that the cumulative program benefits through 2005 total $27.3 billion, with a public sector return of $8.3 billion. FE utilized a four-step process to estimate these benefits. First, actual project results were used to determine the benefit of new technologies. Second, the portions of the benefits attributable to DOE R&D and to industry R&D were estimated, and three estimates were modeled: no new technology, industry technology only, and DOE and industry technology from R&D. The incremental benefits of the DOE programs were estimated by subtracting the industry-only benefits from the DOE + industry benefits. Third, estimated benefits due to DOE R&D were estimated for oil production, natural gas production, and dollars saved owing to increased efficiency. Finally, the total program benefits and public sector return were estimated. Total program benefits were based on oil and gas production times oil and gas price tracks, and include cost savings from improved efficiencies for exploration, production, and refining operations. Public sector benefits were estimated using average effective federal, state, and production and severance tax rates. However, FE’s benefits estimates are probably much too high, especially since private industry discounts the importance of the FE seismic R&D program. Nevertheless, the benefits of this program were large and greatly exceeded the R&D costs. A net benefit of $600 million is assigned to DOE based on a benefit to cost ratio of 2.4 to 4.9. eFE estimates incremental production of 360 million bbl of crude oil, 113 million bbl of natural gas liquids, and 780 Bcf of natural gas. fDerived from seismic to target exploration and field development potential. gThe program provided a strong national knowledge base, aggregated the technical expertise of domestic industry to improve efficiency, and made it available to all of industry. hThe research related 3D/3C and 4D seismic more directly to reservoir rock and fluids distributions through attribute analysis in order to more accurately image the reservoir and high-potential regions. iThe 3-Component (3C) Vibratory Borehole Source technology is a powerful, nondestructive, fieldable vibratory seismic source used as a high-force, wide-bandwidth, three-axis seismic source. Resolution of the tool is about 10 times greater than conventional technology. The technology is currently commercial and is used for cross-well, reverse vertical seismic profiles, and single-well seismic surveys. This technology may capture a large share of the potential U.S. borehole seismic technology market, which is estimated to be $1.45 billion. An advanced three-component, multistation borehole seismic receiver was introduced in 1992 and is available through OYO-Geospace or as a service through Bolt Technology. New seismic processing algorithms have been written to help resolve some of the problems inherent in 3D subsalt imaging. In addition, 4D seismic technology developed through Lament Doherty Earth Observatory is now marketed by Baker Hughes. In addition, DOE support of seismic technology in various field projects has led to better reservoir characterization and improved oil production. Benefits and Costs DOE estimates the overall benefit to industry of seismic technology to be $6 billion per year. Industry spending on seismic applications and technical services is high, although there is some spending for R&D. Of the total estimated benefit from seismic technology, DOE calculates its contribution in the range of 4 to 6 percent based on modeling analysis. Industry spends about $1.5 billion per year on all research, and DOE estimates that the industry spends about $180 million per year on basic and long-term research. DOE
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 funding for seismic projects has averaged $5 million per year (exclusive of Field Demonstration projects), or 3 percent of industry’s spending on long-term research. On this basis, the DOE contribution to seismic technology has a benefit of $2.2 to $4.4 billion. The investment in the program is $161 million, which would yield a gross return on investment between 14:1 and 28:1. Applying the 17.5 percent net to gross revenue ratio that was applied to other resource-based programs, the DOE Seismic Technology program would have a benefit/cost ratio of between 2.4 and 4.9. That gives a benefit of about $600 million (Table F-33). In another calculation of benefit/cost ratios, DOE credited the Seismic Technology program with 3 percent of total domestic oil production and 1 percent of total domestic natural gas production. With an average net revenue at 17.5 percent of sales revenues, a realized economic benefit of $4145 million (1999 dollars) was calculated using a benefit/cost ratio of 39. The range 2.4 to 4.9 is more nearly consistent with calculated ratios of other resource-based programs and yet represents a very good return on investment for the program. Lessons Learned The principal lesson learned from the DOE Seismic Technology program is that even with a technology in which the private industry has invested massively, federal government funding geared to certain niche areas—for instance, crosswell seismic, utilization of special expertise and facilities such as the high-performance computing capabilities of the national laboratories, or the support of seismic surveying for independent operators with the capability of processing seismic data—is a useful adjunct to a major private sector activity. WESTERN GAS SANDS PROGRAM Program Description and History The early 1970s recorded peak production of natural gas in the United States at a time when demand had been increasing significantly for 20 years. After peaking, most projections showed conventional gas production to decline steadily. The Natural Gas Policy Act, which Congress passed in 1977, restricted or prohibited certain uses of natural gas. With the widespread view that conventional sources of natural gas were dwindling, attention turned to so-called nonconventional sources—natural gas from coal beds, methane dissolved in geopressured waters, and natural gas in low-permeability, or tight, formations. Heretofore, these occurrences of natural gas were not included in estimates of the U.S. natural gas resource base. The Western Gas Sands program was designed to accelerate the development of domestic gas resources. It was directed at the development of new and improved techniques for recovering gas from low-permeability (tight) gas reservoirs that at the time of initiation of the program could not be economically produced. The purpose of the program was to encourage and supplement industry efforts to develop technology and demonstrate the feasibility of producing from tight reservoirs. The initial federal effort to explore the potential of low-permeability sands was undertaken by the Bureau of Mines in 1974 with a Single Well Test program to deploy massive hydraulic fracturing of tight sands. Fracturing was generally successful in uniform, blanket sands but poor in lenticular reservoirs, whose character was not understood. Congress established the Western Gas Sands program in 1978, and the initial effort was to better characterize the low-permeability formations through an extensive coring and mapping program. This led to the Multiwell Experiment (MWX), conducted from 1981 to 1988 in the Piceance Basin in western Colorado, aimed at characterization of reservoirs. The goal was to investigate how fracturing technology could be deployed in the context of a characterized reservoir. Previous experiments had been conducted on 640- or 320-acre spacing of wells, appropriate if the reservoir was uniform but too widely spaced to evaluate the continuity of lenticular reservoirs. The MWX experiment was designed with a closely spaced three-well pattern (110- to 125-ft spacing) and was the basis for better understanding hydraulic fracture growth and gas production mechanics in lenticular sands, where most of the western U.S. resource occurred. Once the MWX was in place, the Western Gas Sands program focused on resource assessments establishing the reservoir properties of the massive volumes of gas in place in the basin-centered formations; reliable hydraulic fracture diagnostics technology; and technology for predicting and finding the naturally fractured “sweet spots” in tight gas reservoirs. Funding and Participation DOE expenditures in the Western Tight Gas Sands program from 1978 through 1999 amounted to $185 million (1999 dollars) (see Table F-34). The program peaked in 1981, when the annual budget was $20.8 million (1999 dollars) and was the lowest in 1992 at $3.6 million; since it then has averaged a little over $5 million annually. From 1983 to 1988, most of the budget was used to fund basic research and sample analysis through the national laboratories. When the project emphasis changed from basic research to applied research in 1989, more funds were directed to actual procurements with private research companies and industry. Prior to 1992, the program was funded entirely by DOE. As the program became more product-oriented, a larger percentage of funding came from industry. By the late 1980s, most of the research money was being spent in actual field demonstration projects. In the basic and applied stages of the program, DOE expenditures led industry by 2 to 1; in the
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 TABLE F-34 Benefits Matrix for the Western Gas Sands Program (WGSP)a Realized Benefits/Costs Options Benefits/Costs Knowledge Benefits/Costs Economic benefits/costs DOE R&D costs: $185 million Industry costs: $9 millionb Benefits: DOE made substantial contribution to $800 million in increased net revenues, royalties, and cost savingsd Incremental natural gas produced from the five Rocky Mountain foreland basinsf Potential for large volumes of marginal resources to be added to the resource base Development of new and improved techniques for future gas recovery from low-permeability (tight) gas reservoirse R&D on tight gas science, technology, and development Theoretical work on natural gas fracturesc Improved characterization and extraction technology Tailoring of well spacing to specific reservoir geometriesg Characterizations of basin-centered accumulations throughout the western United States Advanced the understanding of complex, lenticular reservoirs and how fracturing is deployed in such reservoirs Environmental benefits/costs Reduction in the number of wells required to produce a given gas supplyh None None Security benefits/costs None None None aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000. bPrior to 1992, the program was funded entirely by DOE, but as it became more product-oriented, a larger percentage of funding came from industry. By the late 1980s, most of the research money was being spent on field demonstration projects. In the basic and applied stages of the program, DOE expenditures led industry by 2 to 1; in the demonstration stage, industry led DOE by nearly 3 to 1. In addition, FE acknowledges analogous R&D efforts by GRI and private industry over the time period in question but provides no information on these efforts. cProvided the foundation for the emerging natural fracture detection and prediction methodology. dFE estimates $1626 million in increased net revenues and cost savings to gas producers in the Rockies; inclusion of the industry cost share in the program would reduce the benefits credited to DOE. FE further estimates $591 million from royalties on federal lands and from increased state severance taxes due to displacement of imports, and it credits 70 percent of the increased gas production in the Rocky Mountain gas basins since 1987 to WGSP. The basis for estimating the realized economic benefits for the WGSP is the enabling of production of natural gas at prices that would not have been possible without the program. Overall, WGSP is credited with developing technology and stimulating 35 percent of the tight gas produced from the Rockies from 1978 to 2005. With a 35 percent DOE share, a net benefit of about $800 million is assigned to DOE. The remaining 65 percent is assigned to industry, GRI, and Section 29 tax credits. eFuture application of WGS technology in emerging plays and basins will substantially enlarge this part of the resource base. By 2005, production should approach 800 Bcf. In addition to increased production, the program has significantly advanced understanding of complex lenticular reservoirs and how fracturing is deployed in them, and a much larger part of the vast in-place resource in the basin-centered gas formations of the Rocky Mountain basins is economically accessible. fWGSP has contributed increased gas supplies at lower cost. Tight gas production from the Rocky Mountain gas basins was only 162 Bcf in 1978, at the start of the program; 10 years later it stood at 224 Bcf, and in 2000 exceeded 700 Bcf. gWGSP demonstrated the importance of tailoring development of well spacing to the specific geometries of reservoir heterogeneity related to natural fracturing in tight gas sands. hThe application of resource assessments, natural fracture detection and prediction technology, and advanced drilling and stimulation will enable less than half as many wells to be drilled in the future to yield the same volume of reserves. demonstration stage, industry led DOE by nearly 3 to 1 (OFE, 2000t). Results The Western Gas Sands program has contributed increased gas supplies at lower cost. Tight gas production from the Rocky Mountain gas basins was only 162 Bcf in 1978 at the start of the program; 10 years later it stood at 224 Bcf and in 2000 production exceeded 700 Bcf, a fourfold increase. By 2005, production should approach 800 Bcf. In addition to increased production, the program has significantly advanced understanding of complex, lenticular reservoirs and how fracturing is deployed in them. A much larger part of the vast in-place resource in the basin-centered gas formations of the Rocky Mountain basins is now considered economically accessible. Benefits and Costs DOE credits 70 percent of the increased gas production in the Rocky Mountain gas basins since 1987 to the Western Gas Sands program. Overall, the program is credited with developing technology and stimulating 35 percent of the
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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 tight gas produced from the Rockies from 1978 to 2005. The remaining 65 percent is assigned to industry’s activity, GRI’s R&D program, and Section 29 tax credits. In return for a DOE R&D investment of a little over $180 million (1999 dollars) to date and $200 million through 2005, DOE calculates $1626 million (also in 1999 dollars) in increased net revenues and cost savings to gas producers in the Rockies, with a benefit to cost ratio of 8.9; inclusion of the industry cost share in the program would reduce that ratio somewhat. DOE further calculates $591 million (1999 dollars) from royalties on federal lands and from increased state severance taxes due to displacement of imports. With a 35 percent DOE share, a net benefit of about $800 million is assigned to DOE (see Table F-34). Future application of tight gas sand technology in emerging plays and basins will substantially enlarge this part of the resource base. Tight gas production in the Rockies should reach 950 Bcf in 2010, providing an environmentally clean fuel and greater domestic supply. The application of resource assessments, natural fracture detection and prediction technology, and advanced drilling and stimulation, means that less than half as many wells will need to be drilled to yield the same volume of reserves. Lessons Learned A significant part of the success of the Western Gas Sands program was its successful transition from a basic research program supported entirely by government to an applied research and demonstration program in which industry took over increasing support of the program. Coupled with governmental tax credit incentives under Section 29 of the Natural Gas Policy Act, this targeted research program brought an important source of natural gas into the national supply stream earlier and cheaper than it would otherwise have been brought in. REFERENCES Bloomberg Press Release. 2000. ExxonMobil, BP and Phillips Plan Alaska Gas Pipeline. Environmental Protection Agency (EPA), Office of Air Quality Planning and Standards. 1998. Study of Hazardous Air Pollutant Emissions from Electric Steam Generating Units: Final Report to Congress. EPA-453/R-98–004a. Washington, D.C.: EPA. Galloway, W.E., et al. 1983. Atlas of Texas Major Oil Reservoirs: Bureau of Economic Geology. University of Texas at Austin Special Publication. Austin, Tex.: University of Texas. National Energy Technology Laboratory. 1999. Vision 21 Program Plan: Clean Energy Plants for the 21st Century. Morgantown, W.Va.: National Energy Technology Laboratory. National Research Council (NRC). 1990. 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OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: NOx Control Program, December 4. OFE. 2000g. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Mercury and Other Air Toxics Program, December 6. OFE. 2000h. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Waste Management/Utilization (Coal Combustion Byproducts) Program, December 6. OFE. 2000i. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Turbine Systems Technology Area, November 22. OFE. 2000j. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Stationary Fuel Cells Program, December 6. OFE. 2000k. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Enacted Appropriations for the Stationary Fuel Cells Program, November 11. OFE. 2000l. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Magnetohydrodynamics Program, November 27. OFE. 2000m. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Drilling, Completion, and Stimulation Program, December 4. OFE. 2000n. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Downstream Fundamentals Area Research, December 6. OFE. 2000o. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Summary of Benefits and Costs of DOE/NETL’s Eastern Gas Shales Program, December 4. OFE. 2000p. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Enhanced Oil Recovery Program, December 18. OFE. 2000q. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Field Demonstrations of Technology and Processes, December 6. OFE. 2000r. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Oil Shale Technology, December 12. OFE. 2000s. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Seismic Technologies, December 4. OFE. 2000t. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: NETL Gas Supply Projects Division, Western Gas Sands Technology Area, December 6. OFE. 2001a. 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Energy Research at DOE was it Worth it?: Energy Efficiency and Fossil Energy Research 1978 to 2000 efits of DOE R&D in Energy Efficiency and Fossil Energy: Coal-bed Methane Program, January 10. Spencer, D. 1995. A Screening Study to Assess the Benefit/Cost of the U.S. DOE Clean Coal R/D/D Program. SIMTECHE, informal report for the Office of Fossil Energy . Washington, D.C.: Department of Energy. Robert, Wright, DOE, e-mail communication, January 4, 2001. BIBLIOGRAPHY Department of Energy (DOE), National Energy Technology Laboratory. 2000. Response to the National Research Council Questionnaire Fluidized-Bed Combustion (FBC) Technology Area, November 22. Office of Fossil Energy (OFE). 2000. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Reservoir Efficiency Processes, Enhanced Oil Recovery, Production Research, December 4. OFE. 2000. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Fossil Energy Congressional Budget Request and Enacted Appropriations, November 27. OFE. 2000. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Oil and Natural Gas Environmental Technology Area, December 4. OFE. 2000. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Overview of Accomplishments and Benefits of DOE R&D Programs in Oil and Natural Gas, December 5. OFE. 2000. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Attachment 1: Individual Program Summaries, December 18. OFE. 2001. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Coal Preparation Program (update), Successful Results of the DOE Coal Preparation/Solid Fuels and Feedstocks R&D Program. February 9.
Representative terms from entire chapter: