National Academies Press: OpenBook

Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000 (2001)

Chapter: Appendix F: Case Studies for the Fossil Energy Program

« Previous: Appendix E: Case Studies for the Energy Efficiency Program
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

phase fixed-bed reactor. This technology was selected for commercial-scale demonstration under round three of the DOE’s Clean Coal Technology program in an agreement between DOE and the Air Product Liquid Phase Conversion Company, a partnership formed by Air Products and Eastman in 1989. The demonstration project is being conducted in the Eastman Chemical manufacturing complex in Kingsport, Tennessee. The Kingsport project, which has a capacity of 260 short tons per day of methanol, is now in the fourth year of successful operation with availability exceeding 98 percent.

Other Oxygenates. Studies were carried out of the synthesis of other oxygenates, such as dimethyl ether; however, no novel leads were found.

Coproduction of Fuels and Electricity

The production of fuels and electricity simultaneously from coal offers economic benefits over producing fuels alone.

Benefits and Costs

This program was a mix of R&D projects, such as catalyst research, and process and reactor development. It also scaled up the liquid-phase methanol process to a 260 tpd demonstration unit. Although there were substantial technical achievements, there were no realized economic benefits (Table F-8).

The scale-up of the liquid-phase methanol process makes it a technological option for the conversion of coal to methanol when economic conditions become favorable. Methanol could then be used directly as a fuel, converted to gasoline or dimethyl ether, or used as a chemical.

While not yet having any benefit, the coproduction of fuels and electricity appears to be a more promising option than converting coal to fuels alone.

Indirect liquefaction has the additional advantage of having a highly concentrated stream of CO2 available from the synthesis-gas-generation section, which could be sequestered to minimize CO2 discharge into the atmosphere.

TABLE F-8 Benefits Matrix for the Improved Indirect Liquefaction Programa

 

Realized Benefits/Costs

Options Benefits/Costs

Knowledge Benefits/Costs

Economic benefits/costs

DOE RD&D costs: $320 millionb

Industry cost share: $164 millionc

No realized economic benefits

Improved state-of-the-art technology could be deployed when economics are favorable and the price of oil increases sufficientlyd

Plant integration to coproduce fuels and electricity improves economics

Liquid Phase Methanol Process demonstratede

Enhanced knowledge of novel catalysts and reactor designs

Advances in gas separations, Fischer-Tropsch synthesis, carbon sequestration technology, and reductions in process contingencies

Advances relating to petroleum hydroprocessing

Environmental benefits/costs

No benefits

If CO2 is sequestered, total fuel cycle emissions are less than for petroleum, and there are potential significant carbon savings compared with other conventional coal and gas options.f

Can produce gasoline and diesel fuels that exceed proposed EPA tier 2 sulfur specifications

Development of knowledge base to produce clean fuels from coal in an environmentally acceptable manner

Security benefits/costs

No benefits

Fuels from coal would displace oil use

None

aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars.

bTotal includes $224 million in R&D funds and $96 million for the Liquid-Phase Methanol Clean Coal Demonstration Project.

cTotal includes $38 million in R&D funds (17 percent cost share) and $126 million for the Liquid-Phase Methanol Clean Coal Demonstration Project (57 percent cost share).

dFE estimates that, assuming successful integration of all process components at the commercial scale, coproduction plants producing electric power and ultraclean fuels may be competitive at a world oil price of about $33/bbl, and that, with appropriate technical advances, coproduction with CO2 sequestration may be competitive at a world oil price of about $25/bbl. However, knowledgeable experts question whether the technology would be competitive with oil at that price.

eA demonstration project has been successfully operating at the Eastman Chemical manufacturing complex in Kingsport, Tennessee, since 1997 and is scheduled to be completed in 2003.

fFE gives these numbers but provides no documentation or sources for them.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Lessons Learned

The lesson learned in this program is that continued investment in technology development on research, development, pilot-plant, and demonstration-plant scales are needed to improve this technology. It will then be a better option if and when the time comes that the United States needs to rely on coal as a source of liquid fuels. The R&D program appears to be a good mixture of shorter- and longer-range programs. Because of the long lead time and high risk required to develop coal-based technology and because of the uncertain economics due to the relatively low price of petroleum, this appears to be an appropriate expenditure of government funds.

INTEGRATED GASIFICATION COMBINED CYCLE

Program Description and History

The development of an integrated coal gasification combined-cycle (IGCC) system has been an important component of DOE’s FE RD&D program for more than 20 years. Electricity production from IGCC development was a natural outgrowth of DOE-industry gasification and turbine RD&D that began in the 1970s with the national concern for energy supply alternatives. The perceived goals of the IGCC program include the following: (1) provide a high-efficiency, environmentally benign option for electricity production to ensure the viable use of coal and residual petroleum carbon as a stable energy source, (2) enhance U.S. national manufacturing competitiveness for electricity generation systems, and (3) develop the potential for integrating energy production with commercially useful chemical by-products, including liquid fuel production. The IGCC program has not only represented a long-term investment in coal-fueled energy options, but represents an important option in DOE’s Vision 21 program for the development of advanced power generation systems for commercial applications beyond 2015. Basically, the IGCC technology integrates the advances in high-pressure gasifiers with a combination of advanced gas turbine designs and conventional steam turbines to produce electricity at thermal efficiencies at least 10 percent greater than conventional steam power plants. The fuels that can be used include coal, residual oils and tars, and petroleum coke. Though gasification technology has existed for 200 years, pressurized gasifiers producing (combustible) synthesis gas suitable for use in gas turbine combined-cycle applications were not designed until the late 1960s. Also, gas cleanup technology to minimize pollution emissions, as required by today’s environmental regulations, was not effectively coupled with the pressurized gasification process until the mid-1970s.

Aside from the advances in thermal efficiency of the IGCC plants, their operations offer the opportunity to reduce currently regulated air, water, and solid wastes to very low levels, an achievement that cannot be matched with any other fossil fuel technology today. The IGCC processes also produce a relatively large amount of CO2, with the potential for efficient removal and sequestration of CO2 to meet greenhouse gas emission needs foreseen in the early 21st century. These factors, combined with the recent near- or full commercial demonstration of IGCC, make IGCC a highly viable option for continued use of coal in the United States as a primary fuel for electricity generation.

The key to the success of the IGCC technology is the integration of components into an operating system. It is difficult to trace the influence of DOE’s basic and applied research programs on IGCC development, in comparison with the efforts of manufacturing industry, which were built on a long history of petroleum technology and chemical processing matched with gas turbine technology. The electricity supply industry’s interest in IGCC was also stimulated mainly by the private sector and its concern over the viability of coal as a fuel. However, both government and the private sector realized in the mid-1980s that coal continued to be the preferred fuel for electricity production but had to be used in the face of very stringent environmental constraints. This realization led to considerable industrial investment in a variety of coal-based power generation technologies.

As a result of a number of post-World War II material and chemical process component developments, gasifier and advanced gas turbine technology progressed to a point where their integration to produce electricity could be demonstrated. The first IGCC demonstration with commercial potential took place during the 1980s without direct DOE sponsorship. The plant involved was the Cool Water facility in California, a joint effort of Texaco-Southern California Edison (Edison International) -General Electric-Central Research Institute of Electric Power Industry (Japan) -EPRI. This 100-MW plant was operated for several years and laid the groundwork, with the advent of new gas turbines, for scale-up demonstrations at 200- to 250-MW capacity in the 1990s.

The Cool Water experience, combining the Texaco gasification island with advanced gas turbine technology and conventional steam turbines, demonstrated that IGCC could offer efficient coal utilization with minimal environmental impact. With the emergence of new gas turbine technology at the same time (see FE’s Advanced Turbine Systems program), the stage was set for DOE to play a critical role in commercial-scale IGCC development through sponsorship of the scale-up demonstration of three IGCC technologies under the CCT program in the 1990s.

Funding and Participation

Since 1978, DOE has invested more than $2.3 billion (1999 constant dollars) on gasification, mainly using coal as a fuel. Of this, about 50 percent was committed to demonstration and commercialization of technology; $600 million was committed in the 1990s to the demonstration of three

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

near-commercial IGCC technologies within the CCT partnerships. Except for an early $13 million investment supporting the commercial-scale Great Plains gasification facility in North Dakota, the remainder is accounted for by basic component research or by bench-scale or pilot-plant testing of process components. The DOE investment in demonstrations and commercialization has amounted to about half of the cumulative IGCC budget since 1978 (OFE, 2000d).

Industry’s parallel investment in the development of IGCC technology, including the investigation of gasifier options, over approximately the same period is estimated to have been about $2.2 billion (Spencer, 1995). For the recent CCT demonstrations, DOE’s funding amounted to about 50 percent of the capital installation costs, but it is unclear how much DOE contributed to the incremental operating costs at the CCT sites during the time the plants operated. The investment in Cool Water did not include any by DOE; the capital costs for this demonstration were approximately $260 million, or $2600 per kilowatt. With the CCT demonstrations, this cost is projected to be reduced to $1500 per kilowatt or less.

Results

As a result of more than 20 years’ investment on the part of DOE and industry, modern technology for the gasification of coal and other fossil fuels to produce synthetic natural gas has reached a stage of commercializable technology for applications worldwide. The concept of thermally efficient and environmentally benign electricity production from different kinds of coal using a IGCC system also has been demonstrated at the commercial scale using three different gasification technologies. Thermal efficiencies in excess of 40 percent have been obtained, with the prospect of 50 percent for advanced turbine systems. Current efficiencies are well above the 35 percent levels of conventional plants, and emissions of air pollutants are only a small fraction of U.S. New Source Performance Standards, with recovery of sulfur as a commercial by-product. Emissions of air toxic compounds is minimal, contaminated water discharges are negligible, and solid wastes are produced as vitrified material impervious to leaching in storage. The IGCC plants also offer a significant opportunity for the capture and sequestration of CO2, a greenhouse gas. Technologies to achieve this goal are being investigated in DOE’s program.

As a practical matter, coal-based IGCC plants directly compete with combined-cycle natural gas plants. While IGCC represents a primary option for efficient, environmentally compatible electricity production using domestic coal resources, its future application beyond niche markets will depend on natural gas prices, combined with IGCC component price reductions. The latter are likely to derive from continued efforts to increase overall efficiency through the integration of advanced turbine systems (ATS) and, possibly, fuel cell electricity production in the long term.

Currently gasifiers producing a total of 12,000 MW are operating worldwide. There are plans to build at least 20 IGCC plants in the next 5 years using mainly current U.S. and European technology. Perhaps the most extensive market penetration is enjoyed by the Texaco technology. Despite its viability, IGCC systems remain in competition with natural-gas-fired, turbine-based technology and PFBC technologies. While the FBC systems cannot achieve the environmental quality levels of IGCC, they are estimated to be less costly than IGCC plants. The two primary barriers to increased interest in IGCC technology for power production are the ability to compete with natural gas power generation and siting and construction issues. Present costs for IGCC systems are $1000 to $1500 per kilowatt. If natural gas prices remain at or below current levels ($4.32 per Mcf),2 IGCC systems need to reduce costs to the $800 per kilowatt range. The cost reduction is expected to derive from continued development of a number of the integrated components of IGCC systems. DOE expects to share in these developments through investments in the Vision 21 program (NETL, 1999).

Benefits and Costs

A summary matrix of benefits associated with the introduction of IGCC systems is given in Table F-9.

Even though projections call for the implementation of several IGCC systems worldwide, their cost of electric power production in the United States remains higher than that of conventional natural-gas-fired turbine generators at current natural gas prices. For widespread coal-based power generation, DOE has estimated that electricity produced in IGCC plants will remain more costly in the United States than that produced in conventional plants. However, according to DOE projections, the economies may begin to favor IGCC in the next 5 years as a result of added costs for emission controls on conventional pulverized coal-fired plants, rising natural gas costs, and assumed improvements in IGCC performance.

While the present-day economic benefits of IGCC systems are not compelling in themselves as a rationale for DOE investment, the environmental and security benefits need to be considered as well. IGCC system development has served the nation well in providing an almost economically viable, environmentally benign technology option for continued use of coal as a primary means of electricity production through the 21st century. The current level of IGCC development opens the door for major improvements in the thermal efficiency of coal-fired power generation and represents an important option for the reduction of greenhouse gas emissions

2  

Average price to electric utilities for the year 2000. See Energy Information Administration Web site: <http://www.eia.gov/oil_gas/natural_gas/info_glance/sector.html.>.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

TABLE F-9 Benefits Matrix for the Integrated Gasification Combined-Cycle (IGCC) Programa

 

Realized Benefitsb/Costs

Options Benefits/Costs

Knowledge Benefits/Costs

Economic benefits/costs

DOE R&D costs: $1065 million

DOE demonstration and deployment costs: $1281 millionc

Private industry R&D costs: $2200 milliond

No realized benefits; benefits may be realized by 2005 depending on choices for new power production.

Provides a potentially efficient and environmentally acceptable option for expanding electric power production

Provides for flexible developments in chemical processing, including indirect liquefaction, and adds an important dimension to U.S. technology markets abroad

Offers opportunity for continuing improvement in thermal efficiency and environmental performance of coal-based power plants far into the future

Offers the potential for combined power production and chemical processing using synthesis gas

Environmental benefits/costs

Cumulative emission reduction benefits: 267,000 tons of SO2, 275,000 tons of NOx, 48 million tons of CO2e

Preserves the option for coal-based electricity while reducing environmental impact to minimum levelsf

With CO2 capture and sequestration, IGCC can offer worldwide options for electricity production with minimal greenhouse gas emissions.

Provided critical knowledge for improved, cost-effective emission reduction technologies, including hot gas cleanup

Security benefits/costs

None

None

None

aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000.

bAll of FE’s benefit estimates are based on a comparison of an IGCC plant with a state-of-the-art 1990s pulverized coal plant.

cAccording to the committee, private industry has contributed about as much as DOE to the demonstration program (Spencer, D. 1995. A Screening Study to Assess the Benefits/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.).

dSOURCE: Spencer, 1995.

eFE’s estimate is based on the 30-year life cycle of the 1700 MW of IGCC capacity assumed to be in place by 2005. FE estimates that the life-cycle value of excess SO2 and NOx allowances totals $152 million (based on NOx allowance values from Cantor Fitzgerald (OFE, 2000e) and SO2 allowance values from EPA). FE also estimates that the health-based benefits of the SO2 reductions total $3.1 billion (based on an EPA estimate of a health value of $7255/ton of SO2 reduced).

fFE estimates that for IGCC installations through 2020, the life-cycle value of excess SO2 and NOx allowances totals $490 million (based on NOx allowance values from Cantor Fitzgerald and SO2 allowance values from EPA). FE estimates that the health-based benefits of the SO2 reductions total $8.1 billion (based on an EPA estimate of a health value of $7255/ton of SO2 reduced). FE also estimates the cumulative emission reduction benefits from the IGCC capacity in place by 2020 as 1.1 million tons of SO2, 1 million tons of NOx, and 227 million tons of CO2.

through improved efficiency of power production, combined with efficient CO2 capture and sequestration.

IGCC technology also offers important opportunities for the development of coal-based chemical processing as an adjunct to electricity production and significant improvements in petroleum refining and specialized high-temperature gas conditioning. Among the opportunities of interest are the high-pressure and high-temperature gasification and processing of biomass.

Lessons Learned

IGCC development and demonstration provide a good example of a long-term, sustained cooperative public- and private-sector-funded program that has taken important steps to achieving national strategic goals. The benefits of this R&D investment are not yet positive economically, but it does give the United States a practical option for maintaining a coal-based electricity resource while meeting environmental objectives.

The experience gained from the IGCC program points to the need to consider national investment in RD&D at three levels—national strategy, technological priorities, and critical selection of options. At the first level, national strategy, the history of gasification and its application to IGCC shows the results of a wavering and inconsistent national energy policy through the last 30 years. At present, the United States faces most of the same pressures on its energy supply that it did in the 1970s. Yet the nation’s apparent energy policy has reacted with short-term responses to the availability of cheap fuels, dictated by the international marketplace, and to increasingly stringent environmental constraints. The long-term viability of a stable and inexpensive energy supply based primarily on domestic resources has been a low priority. If this objective had remained the top priority, IGCC might well be farther along in its applications.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

In the past, many publicly funded projects were funded on the basis of perceived value in basic and applied component research at the presystem scale. This agenda has proven to be inefficient in the creation of energy production facilities that require inherently large capital investments. Early conceptual recognition of the potential of IGCC systems (which integrate chemical processing technology with thermodynamically staged, advanced power generation) provided a focus on component research specifications. This physical and intellectual integration of researchers and manufacturers served to set priorities for R&D investment early on, enabling a focus on solving key problems.

As development progressed on IGCC systems, it became clear in the early scale-up demonstrations that the technology would leapfrog end-of-stack environmental controls for existing plants and would supersede other generation options based on incremental advances of conventional boiler technologies. Had this been recognized early in the CCT initiatives, the selection of technologies for demonstration might have focused more on the IGCC options than on other options.

The experience gained from IGCC developments indicates that the successful development and demonstration of energy production technologies that require large capital investment are greatly enhanced with public and private partnerships, particularly for accelerating technology development to practice. DOE’s main contribution to IGCC resulted from developing a close working relationship with industry to move the technology through the commercial demonstration stage. This is very critical to commercial acceptance in the electricity production sector, where reliability of technology is a primary consideration. Industry is increasingly averse to using its limited capital funds for precommercial demonstrations of new coal-based energy technologies. A degree of risk sharing, with public funds injected at the scale-up demonstration stage, assures that new approaches to energy production will experience a smooth transition from bench-scale to full-scale commercialization.

EMISSION CONTROL TECHNOLOGIES

Program Description and History

In response to the requirements for stringent emissions limits on fossil-fueled power plants imposed by the Clean Air Act (CAA) and its amendments (CAAA), DOE expanded its RD&D program in the mid-1980s to seek improved options for control technology to control the stack effluents of power plants. The CAA historically focused on the criteria pollutants—particulate matter (PM), sulfur dioxide (SO2) and nitrogen oxides (NOx) —that are relevant to power plant emissions, especially coal-fired plants. Emission control technology has been commercially available for all three of these pollutants since the 1970s. The technologies for PM have been proven with respect to high collection efficiency (based on mass loading) and reliability for some time. However, the early technologies available for flue gas desulfurization (FGD) and NOx reduction could not be applied to all plant configurations and fuels and were low in collection efficiency and unreliable for plant operations. To support the timely achievement of air quality goals, DOE initiated in 1979 a major effort directed toward improvement of FGD and NOx reduction technologies, in cooperation with the electric utility industry and equipment vendors. The DOE activity complemented a parallel effort at EPA.

The perceived goals of the DOE program included the following: (1) accelerate R&D to improve power-plant-related emission control technology options for SO2 and NOx such that the emission goals of the CAA would be met with high collection efficiency, reduced costs, increased reliability, and reduced space requirements for all plant designs and fuel alternatives; (2) demonstrate the commercial viability of advanced emission control technologies for SO2 and NOx for retrofit and new conventional plant applications; and (3) stimulate interest in U.S. emission control technologies for application abroad.

After more than 30 years of experience from RD&D activity and full-scale operations, advanced emission control technologies for PM, SO2, and NOx are now available for essentially all commercially operating, large-power-plant boiler configurations. The technology is available for the range of existing plants in the United States with different boiler and flue gas conditioning designs and site space limitations and using different fuel supplies, especially coals. PM emission control devices using electrostatic precipitators and/or baghouse fabric filters are well established and have been adopted for virtually all U.S. large power plants. Flue gas desulfurization methods include (1) a variety of wet scrubbing configurations using lime or limestone alkali reagent and (2) dry scrubbing, including direct sorbent injection into postcombustion regions of the boiler. NOx emission control has evolved through control of the fuel combustion process, with the addition of reburn/overfire capability above the primary boiler combustion zone. NOx technology also exists for postcombustion treatment of the flue gas using selective catalytic reduction or selective noncatalytic reduction. These technologies react reduced nitrogen compounds such as ammonia or urea with NOx at a high temperature for NOx removal.

Funding and Participation

Since 1979, DOE’s investment in FGD technologies, including basic and applied research and the demonstrations of the Clean Coal Technology (CCT) program has been $179 million,3 which complemented EPA’s investment of ap-

3  

The $179 million figure is in current dollars while the $224 million estimate in Table F-10 is in constant 1999 dollars.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

proximately $100 million. In the mid-1980s, DOE’s CCT demonstration component amounted to $103 million. The industrial counterpart to this investment—including the investments of electric utilities and vendors—is uncertain, especially if one goes back further than 1970. The industrial cosponsorship of the CCT program was $264 million exclusive of the site sharing, in-kind expense. The industrial research component of EPRI’s program alone included more than $12 million for the high-sulfur test facility (HSTF), and a cumulative RD&D budget over a decade exceeding $25 million.

Compared with FGD, DOE’s R&D budget for low-NOx combustion technology and postcombustion NOx reduction technology is $67.2 million (1999 dollars). The large private sector investment in RD&D for NOx reduction is estimated at $107 million (1999 dollars), dating back to the 1970s. This included, for example, Exxon technology development for SCR for petroleum combustion sources.

Exclusive of PM emission control RD&D, the total investment in SO2 and NOx emission reduction technology for large coal-fired boilers amounts to more than $525 million since the late 1970s. These costs of advancing a range of retrofit technology options for use in extending the life of the current fleet of coal-fired power plants were underwritten mainly by the public through government funding and the electricity ratepayer.

Results

The RD&D to produce advanced or second-generation emission control technologies is driven by environmental regulation. The sustained investment of DOE in emission control technologies has supported significant advances in FGD collection efficiencies and reliability at reduced costs over the first generation of equipment. The investment also has provided major improvements in reliable NOx reduction in the combustion process as well as in postcombustion options for a range of U.S. coals and boiler configurations.

Both wet and dry FGD technology matured to internationally commercial status after the 1980s. The RD&D effort in basic and applied research on FGD chemistry, mass transfer rates, corrosion-resistant materials, and design standardization has led to configurations that generally meet the tests of reliability and collection efficiencies exceeding 95 percent with reductions to capital and operating expenses of $200 to $300 per kilowatt installed and 10 to 15 mills per kilowatt-hour, respectively. A key contribution of DOE to wet scrubber technology was its support for the development of forced oxidation limestone technology, paralleling EPA’s R&D on organic additives to achieve high collection efficiencies. In the dry scubbing area, the use of DOE-supported direct reagent injection into the postcombustion regime added a potentially efficient and space-saving capability to the FGD portfolio. Even though reliable FGD technology is available today, many utilities have not exercised this retrofit option to address the 1990 CAAA requirements. Lower costs associated with fuel switching and emissions trading have fulfilled most of the needs for SO2 reduction in the first phase of the acid rain control effort. It remains to be seen what role FGD will play in the second phase of required SO2 reductions after 2000 (OFE, 2000e).

Low-NOx combustion technology has significantly reduced NOx emitted from large utility boilers since the 1980s, with reductions ranging from 40 to 60 percent depending on the boiler design. Important contributions to the advancement of burner technology in the 1980s included basic studies of the fluid dynamics of combustion, bench- and pilot-sale testing that led to designs customized for different boiler configurations, and a computer optimization program supported by DOE and EPRI, GNOCIS.4 The capital costs for burner installation amount to about $9 per kilowatt, with about 0.3 mill per kilowatt-hour operating expenses (OFE, 2000f).

Accompanying the introduction of low-NOx burner technology was the introduction of reburning or overfiring in the 1980s. Fuel staging of the reburning involves primary combustion in a fuel-lean stream, followed by the staged injection of added fuel and air into a lower-temperature region of the boiler to complete combustion. Overfiring involves a fuel-rich primary combustion zone followed by the injection of air into elevated, cooler zones of the boiler. Reburning and/or overfiring can improve the reduction of NOx in the flue gas to levels 65 percent below the levels in a boiler without controls. Added capital costs are $15 to $40 per kilowatt, with 2 to 3 mill per kilowatt-hour added operating costs.

In the 1970s, the requirements for NOx emission reductions exceeding about 60 percent stimulated interest in postcombustion technologies; much of the development of these postcombustion technologies derived from European and Japanese experience. The two classes of technologies, selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR), have been tested extensively and were recently demonstrated commercially for application to U.S. coals. The foreign technology has been advanced with support from DOE and the private sector to investigate basic chemistry, different reduction catalyst and catalyst support performance, minimization of excess reducing reagent, minimization of SO2 oxidation, with removal efficiency for different U.S. coals. Current technology gives a better than 80 percent NOx reduction in effluent gas for SCR, but SNCR has lower removal efficiencies, 60 to 70 percent. SCR and SNCR are considerably more expensive in terms of capital costs and operating costs than combustion technology. Typically, SCR capital costs are $50 or more per kilowatt, with

4  

GNOCIS is an EPRI developed (with DOE support) computer software package for computer control of combustion systems to minimize NOx emissions.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

operating cost of 2.5 mill per kilowatt-hour. SNCR costs will be somewhat less, with lower removal efficiencies.

DOE’s Role

DOE’s role in emission control technologies came relatively late in the development of much of the commercial hardware available in the 1980s; it appears to have been motivated strongly by concerns about acid rain mitigation and the need to develop best available control technology (BACT) and address the new source performance standards called for by the CAA. DOE’s early role was a supporting one, providing basic and applied research activities to resolve technical issues raised in the first generation of hardware. EPA and the private sector, through vendors and EPRI, played a strong leadership role in RD&D for PM, SO2, and NOx reductions through 1980. Other than its support for basic and applied research, including support for extensive developmental effort at EPRI’s high-sulfur test facility (HSTF), perhaps DOE’s most prominent role was the demonstration of a number of SO2 and NOx removal technologies as a major component of the CCT program from the late 1980s through the mid-1990s. The CCT program is significant in that it supplied resources for partnerships to demonstrate commercial technologies that add choices for conventional plant modifications using different U.S. coals and boiler configurations.

DOE assisted in funding three advanced, high-efficiency FGD wet scrubber technology demonstrations and five sorbent injection technologies for SO2 removal. Under the CCT, DOE also cosponsored seven NOx combustion or reburn technology demonstrations and eight postcombustion technologies, including hybrid schemes to simultaneously reduce NOx and SO2. With the exception of the last category, all of the CCT demonstrations have yielded commercially viable technologies, many of which have been sold or are planned for sale to the domestic and international markets.

Mainly through the CCT demonstrations it cosponsored with industry, DOE has established a commercializable portfolio of emission control technologies for reducing SO2 and NOx from conventional coal-fired power plants that will achieve the desired air pollution reduction requirements of the CAA. The emission control options add significant capital costs but relatively minor operating expenses for retrofitting existing plants and for designing and constructing new plants, including AFBC and PFBC systems. However, the investment provides a second generation of control technologies whose deployment can ensure that U.S. pulverized coal power plants comply with air quality objectives through at least 2010 if no additional emission limits are implemented.

In addition to demonstration of several different advanced technologies for SO2 and NOx emission control, DOE has taken at least partial credit for key technological developments associated with flue gas treatment that meet the program objectives, including the following:

  • Working with EPA and EPRI to develop the use in FGD of forced air oxidation and organic acid additives to increase collection efficiency of SO2 to 95 percent and above;

  • Improvements in flue gas absorbent contacting to enhance the mass transfer of SO2 to absorbents, reducing the size and pressure drop in FGD scrubbing units;

  • Development of dry sorbent injection technology as a means of SO2 removal;

  • Optimization of multiple burner array design, combined with overfiring; and

  • Conceptual development of hybrid SO2 and NOx removal technology (one example uses a copper oxide catalyst system).

Benefits and Costs

The benefits associated with DOE RD&D are summarized in Table F-10 for FGD emission control technologies and in Table F-11 for NOx emission controls. Basically, DOE’s RD&D effort is driven by the environmental protection requirements of the CAA. In some sense, the value of advances in low-cost NOx emission controls through CCT and other developments has surpassed that of FGD options in terms of market penetration. The investment in improved reliability and lowered costs of FGD systems resulting from public and private investment is judged to have resulted in a realized benefit of about $1 billion. Partly because of the CCT subsidization and the CAA regulation requirements, NOx control options are judged to have had no realized economic benefits. However, both FGD and NOx have environmental benefits from reduction in emissions, as noted in Tables F-10 and F-11. The advancement of emission control technology preserves the existing emphasis on coal as a viable fuel for power generation using conventional boiler technology or advanced systems like AFBC and PFBC. The demonstration of a variety of second-generation emission control technologies for SO2 and NOx probably accelerated their commercial viability by several years. The investment probably has given the electric power generation industry sufficient options to meet the current requirements of the CAA in a timely manner.

The long-term utilization of U.S. coal reserves is important economically and from an energy security viewpoint. The best alternative to the current practice of the existing fleet of coal-fired power plants, which use technologies that erode thermal efficiency and add cost to electricity, would be to shift to high-efficiency, benign technologies such as IGCC systems, but it is not known when (or if) this shift will occur.

Lessons Learned

DOE’s investment in basic and applied research underlying the development of commercial options for FGD and NOx emission reductions provided useful but not critical sup-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

TABLE F-10 Benefits Matrix for the Improvement of the Flue Gas Desulfurization (FGD) Programa

 

Realized Benefits/Costs

Options Benefits/Costs

Knowledge Benefits/Costs

Economic benefits/costs

DOE R&D costs: $107 millionb

DOE Clean Coal Technology Demonstration costs: $117 million

Private industry R&D costs: $37 million+c

Private industry Clean Coal Technology Demonstration costs: $264 milliond

Estimated benefits: $1 billione

DOE has demonstrated higher removal efficiency than first-generation technology; advanced multipollutant emission control technologies at lower capital cost than the first- generation FGD system

Research conducted in chemistry, thermodynamics, reaction kinetics, sorbent structural properties, and process control instrumentation

Environmental benefits/costs

Technology improvements result in 2-million-ton reduction in SO2f

Second-generation FGD technology has been demonstrated and is ready for full-scale deployment

Advanced FGD technology is available for retrofit, and new plants with 90+% removal efficiency for full range of U.S. coals, as well as some trace toxic species such as selenium, cadmium, and organic compoundsg

Developed advanced technologies for multipollutant emission control at >90% efficiency

Security benefits/costs

None

None

None

aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000.

bIn addition, EPA sponsored approximately $100 million in FGD RD&D from the 1970s through the mid-1980s.

cIncluding the EPRI high-sulfur test center.

dThis is the current dollar total, exclusive of site-sharing expenses.

eFE contends that the cumulative life-cycle economic benefits resulting from reduced FGD capital and operating costs for coal-fired plants that currently use FGD total $4.8 billion.

fFE contends that the cumulative life-cycle value of excess SO2 removal is $841 million (based on the Cantor Fitzgerald SO2 allowance value of $128/ton), that the cumulative emission benefits for the life cycle of FDG installations is 7.1 million tons of SO2, and that the health-based life cycle SO2 benefits (based on a health value of $7255/ton of SO2 removed) total $47.6 billion.

gIn addition, some of the advanced technologies yield valuable by-products that do not have to be landfilled. Both elemental sulfur and sulfuric acid by-products can be produced, and optimized integration into the power plant cycle may reduce ancillary power requirements and further reduce production of pollutants, as well as CO2.

port for these developments. DOE appears to have had relatively little intellectual leadership of the technology development. However, its financial push was important in bridging the economic barrier between the bench- and pilot-scale levels of development and the scale-up to commercial operations. What appears to have been critical is the cost sharing with industry of demonstrations through the CCT program; this cost sharing led to realizing the commercial potential of technologies that have little economic value to the private sector as profitmaking ventures.

Since the completion of the CCT program, FE has continued to fund advanced concepts for emission control technologies applicable to the current fleet of conventional power plants. Ongoing RD&D includes work on the superclean plant concept incorporating very-high-efficiency emission controls and on ways to reduce mercury emissions. This raises a question about the logic of continuing to pursue solutions for coal utilization, since a high-quality, environmentally benign solution (IGCC) has already reached the stage of commercialization.

MERCURY AND AIR TOXICS

Program Description and History

The release of airborne toxic compounds from industrial sources and the combustion of fossil fuels has been a concern for many years and was regulated as hazardous air pollutants (HAPs) —as National Emission Standards for HAPS in the CAAA of 1977. Fossil-fueled power plants were exempt from HAPs regulation until the CAAA of 1990, wherein Congress requested EPA investigate these emissions and determine if further regulation was needed. Separately, in 1990 Congress requested a study of the environmental impact of mercury emissions from coal combustion.

Since the estimates of HAPs emissions from large utility boilers were outdated and known to be imprecise, DOE and EPRI undertook a major emissions characterization effort in the 1990s as an outgrowth of studies initiated earlier by EPRI. The investigation of mercury emissions was included in the broader HAPs investigations. The field sampling program included a range of plant configurations and fuels and

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

took into account the impact of current emission control technologies. These measurement programs greatly improved the basis for estimating HAPs and mercury emissions factors for various designs of large utility boilers employing coal, oil, and gas as fuels.

By the mid-1990s, the HAPs emission studies evolved into a substantial DOE investment in the exploration of emission control technologies that would reduce these emissions. The 1990s emissions testing program indicated that key HAPs were substantially reduced by existing particle control technologies and by the addition of acid scrubbers to plants. The main exception to this result was mercury. Since the mid-1990s DOE has concentrated its air toxics program on mercury emission reduction technologies.

Funding and Participation

DOE R&D costs have been $42.4 million (1999 dollars) for the program. Industry has put up another $6 million. Early DOE participation in the HAPs emissions characterization was significant, with sampling and measurement development and field study of eight plants, complementing EPRI’s sampling program of 35 plants. Later, in the mid-1990s, DOE’s program became a high-profile national effort aimed mainly at seeking methods for mercury emission reduction. Between 1993 and 1995, DOE invested $31 million in this program. Since 1995, its investment has been about $17 million, with 20 to 30 percent cost sharing by industry (OFE, 2000g).

The DOE emission control program has focused on four areas—sampling and measurement development for mercury compounds in stack effluents; mercury sorbent characterization; coal cleaning; and mercury emission control technology, including stabilization in ash.

Results

The DOE/EPRI HAPS emissions program of the early 1990s produced a large database for estimating emissions from more than 600 domestic utility boilers. These data were used in an EPA and parallel industry risk assessment of the significance of exposure to HAPs from power plant emissions. The results of these analyses indicated that the risk of adverse health effects from utility HAPs emissions generally was insignificant and required no regulatory action. The possible exception was mercury as a bioaccumulating toxic

TABLE F-11 Benefits Matrix for the NOx Control Programa

 

Realized Benefits/Costs

Options Benefits/Costs

Knowledge Benefits/Costs

Economic benefits/costs

DOE R&D costs: $18.6 millionb

DOE demonstration costs: $48.6 million

Private industry R&D costs: $107 millionc,d

CAAA-regulation-driven; no direct benefitse

Provide second- generation LNB options to meet CAAA requirements. Estimated 40–60% NOx reductions from 175,000 MW, coal-fired capacity

Estimated SCR installation up to 100,000 MW by 2005 with 90% NOx reduction

Extensive knowledge of optimized combustion configurations, postcombustion technologies, and control instrumentation

Environmental benefits/costs

CAAA-driven—estimated additional cumulative reduction of 25 million tons of NOx over new source performance standards baseline plantf

CAAA-driven; provides options for NOx emissions reductions to meet 1999 standards call and to aim at an emissions standard of 0.15 lb NOx/MMBtu

Advanced burner and air injection achieves NOx reduction of 40–60%; postcombustion technologies available to achieve 90% reduction

Improved knowledge of combustion chemistry, catalyst performance, and computerized optimization for burner design

Security benefits/costs

None

None

None

aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000.

bPrior to 1987, EPA conducted NOx control R&D.

cFE estimates that the average private industry cost share for research was 20 percent.

dFE estimates that the average private industry cost share for demonstrations was 44 percent.

eHowever, FE estimates that the realized economic benefits through 2005 total $17.1 billion. It assumed that the next-best alternative was the SCR technology available prior to the federal development program. Capital costs for the new SCR technology were estimated to be 52 percent less than for the baseline SCR technology. The cost-effectiveness of the baseline technology was estimated to be $3000/ton NOx removed, compared with $1600/ton NOx removed for the new SCR technology. This represents a $1400/ton NOx removed cost savings over the baseline technology—an effective net cost savings of 47 percent.

fFE estimates that total additional NOx reductions, compared with baseline emissions, amount to 25 million tons for hardware installed through 2005, and that the value of this NOx reduction, based on market trading of NOx, totals $8.6 billion. FE did not quantify the public health benefits of the excess NOx reduction but contends that they are likely to be much greater than the allowance-based values.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

species, human exposure to which comes mainly from the consumption of contaminated fish. EPA subsequently focused attention on mercury contamination in natural waters and expects to make a regulatory determination for emission shortly. The DOE/industry program to find a practical means for the removal of mercury from power plant effluents anticipated such regulation: It provided conceptual options for mercury control, such as sorbent injection into flue gas, but will require further development to reduce to practice.

Benefits and Costs

The economic significance of this program lies principally in the avoidance of any costs that might have been imposed for added emission control technology on existing plants to reduce HAPs emissions (Table F-12). These costs could be large if EPA were to determine that the hazard to exposure of HAPs from power plants is of concern. The benefits of the mercury characterization and emission control options accumulate mainly in the knowledge category since the control technology options have not yet been demonstrated at full scale.

Lessons Learned

This program, together with the waste management and utilization program, illustrates well the value of DOE-industry cooperation to generate new or improved information about environmental issues. There are many examples of relatively uninformed regulation that adversely affects the economics of energy production. The extensive studies of HAPs emissions derived from this program were instrumental in lending credibility to industrial measurements that resulted in EPA’s informed analysis precluding further HAPs regulation for large utility boilers. Since EPA’s ability to conduct such field measurements is increasingly limited, the generation of new data and information falls to industry and to the DOE as a third-party assessor. DOE’s programs that are mainly environmental protection-oriented should continue to be coordinated with EPA and should actively support the necessary development of improved, contemporary information about power plant performance.

The mercury emission control technology component of this program also embodies an important principle that could be included in DOE’s R&D planning. From communications between EPA and industry, it became clear in the mid-1990s that mercury emissions were of increasing environmental concern and that there was no practical technology for mercury’s removal from stack gas. New technology will be difficult to develop because of the extremely low concentration of mercury in stack gas and its different speciation. DOE’s sharing of the costs of development in this case represents an investment of public funds as a means of maintaining coal-based energy production while reducing the risk of contamination from a ubiquitous contaminant. DOE’s work with industry to develop such technology will substantially accelerate the availability of such a technology should regulation be forthcoming.

TABLE F-12 Benefits Matrix for the Mercury and Air Toxics Programa

 

Realized Benefits/Costs

Options Benefits/Costs

Knowledge Benefits/Costs

Economic benefits/costs

DOE R&D costs: $42.4 millionb

Industry costs: $6.2 million

No realized benefits

Avoidance of substantial costs that could have been imposed for reduction of air toxic emissions and for disposal of collected wastes designated potentially hazardous

Development of mercury sampling methods

Database for estimating emissions from more than 600 domestic utility boilersc

Environmental benefits/costs

None

Potential for further reductions in mercury and hazardous air pollutant emissions

Improved knowledge of hazardous air pollutant emissions from fossil fuel combustion in large boilers

Improved conceptual knowledge of mercury emission reduction technologies

Security benefits/costs

None

None

None

aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000.

bEPA also contributed substantial R&D funding, which is not included here.

cThese data were used in EPA (1998) and in a risk assessment of the significance of exposures to HAPs from power plant emissions. The results of the analysis indicated that the risk of adverse health effects from utility HAPs emissions was generally insignificant and required no regulatory action.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

WASTE MANAGEMENT/UTILIZATION TECHNOLOGIES

Program Description and History

The use of coal and the operation of power plants produce large volumes of solid wastes that potentially create significant hazards to the environment. These include ash from combustion and sludge from the scrubbers used in flue gas desulfurization. These wastes amount to annual production of hundreds of millions of tons of material, so that their emplacement involves large areas of land or, alternatively, the use of large amounts of mineral material. The disposal of these wastes is regulated under sections of the Resource Conservation and Recovery Act (RCRA). They also represent potentially valuable by-products that are useful for the replacement of cement or gypsum, as soil amendments, and as highway base material and fillers for certain plastic products. Establishing the nonhazardous nature of these high-volume wastes has been particularly important, because a very large cost could accrue to industry if special measures were to be required for sequestering the ash and sludge wastes at power plant sites.

As a continuing effort to ensure the economic and environmental viability of coal use, DOE has invested in studies to characterize the chemistry of the stored or utilized by-products of coal used to produce electricity. The main goal of the DOE program is to ensure that the use of coal for energy production remains viable and is based on the latest information on solid waste chemistry and the technologies for disposal of coal-related solid waste.

The DOE program was initiated in 1979. Since the mid-1980s, this effort has concentrated on four principal activities: (1) sampling and characterizing the compounds present in solid wastes from coal combustion at commercial plants and from advanced combustion technologies and facilities using these technologies, (2) monitoring waste disposal sites to assess risk, (3) decontaminating waste disposal sites (soil attenuation of toxic species), and (4) evaluating disposal methods, including fixation and stabilization and the development of waste-based lining materials. Later, in the 1990s, the program was expanded to include field monitoring of waste disposal sites from CCT programs and to explore ways to expand the use of combustion by-products.

Funding and Participation

DOE has been an active participant in researching waste utilization and management technologies with the coal and electricity industry for many years and has invested a total of about $53 million in current dollars since 1979, with about half having been committed between 1979 and 1984; since then, the budget has stayed between $1 million and $2 million annually. Industry has complemented this expenditure—for example, EPRI committed at least $5 million a year in the 1980s. Since 1991, industry is estimated to have expended about $12 million in this area, compared with DOE’s $19 million investment (OFE, 2000h).

The DOE program has made significant contributions, along with those of the electric utilities, to knowledge about the nature and sequestered behavior of potentially hazardous materials in high-volume wastes in landfills and in mine emplacements, as well as sequestered material from CCT technology developments. The DOE work has also contributed significantly to knowledge about the characteristics of utilized waste material in a variety of applications, including cement products, highway base material, and wallboard manufacture.

Results

The combined efforts of DOE and industry have been crucial in supplying the knowledge that enabled EPA to determine in 1993 that regulatory treatment of coal combustion wastes (CCBs) was unwarranted under Title C of RCRA. Had the CCBs been designated a hazardous waste under Title C, major new efforts would have been necessary to store and sequester these wastes at power plant sites. Further ash and sludge material would have been precluded from use in a number of by-product applications that exist today. The declaration of the nonhazardous character of CCBs resulted in electric utilities across the country avoiding very large sequestration costs. While there are no guarantees that EPA will not reverse its decision in the future, the present regulation ensures that coal continues to be an economically and environmentally viable fuel for electricity production in the United States.

Continuing work on the utilization of CCBs since the 1980s has stimulated CCB-user industries to employ increasing amounts of material for a variety of applications, many of them in cement production. For example, the American Coal Ash Association estimates that production of fly ash from combustion in conventional boilers increased from 83.7 to 107.1 million short tons from 1988 to 1999 and that the proportion of fly ash used increased from 24.6 to 30.8 percent (cited by DOE). Use of fly ash from fluidized-bed combustion also increased, from 1.6 to 5.9 million tons between 1990 and 1995, with fractional use increasing from 62.8 percent to 74.5 percent, according to the Council of Industrial Boiler Operations (cited by DOE). As scrubber sludge becomes increasingly available, it is used more and more as a source of gypsum in preference to the mineral supply mined directly.

Benefits and Costs

The DOE waste management and utilization program obviously has been designed for relatively short-term benefits. In this sense, it has not been aimed at the development of advanced technologies for coal utilization. The knowledge base accumulated in the program has focused on the

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

characterization of solid waste material in an impoundment setting, documenting its mobilization potential. One of the benefits associated with the determination of CCBs as nonhazardous rather than hazardous material in connection with the 1993 RCRA is the avoidance of cost to the coal combustion industry. These benefits are estimated to be very large, amounting to tens of billions of dollars through 2005, and they alone could well justify the expenditures to date by DOE.

Alternatively, the benefits accrued from using CCBs as substitutes for mineral resources that need extraction and processing are also substantial. DOE estimates a CCB utilization value, for example, of $25 billion through 2005. One can debate the assumptions made in creating these estimates, but qualitatively there is no doubt that the benefits accrued from using large volumes of CCB material for building and highway construction amounts to an economic benefit far exceeding the investment in this program.

Environmental benefits from this program are difficult to rationalize, according to DOE. However, qualitatively, the committee recognizes that some value should be placed on the diversion of land use that might have been required for sequestering wastes if they had been deemed hazardous. Further, there is benefit in the displacement of limestone by fly ash in reduction of pollutant emissions from kilns, including NOx and CO2. In the committee’s judgement, an avoided cost of $3 billion can be counted as a realized economic benefit with the assumptions listed in Table F-13.

Qualitatively, there are potential benefits beyond 2005 based on both the assessment of CCBs as nonhazardous and their projected use in the economy. Perhaps equally important is the fact that this DOE program has contributed significantly to environmental acceptability of coal as a fuel. While it is too early to determine if the current program will lead to a practical means of reducing mercury emissions from coal combustion, the effort is still worthwhile because it is the principal cooperative U.S. activity dealing with this emerging issue.

Lessons Learned

As with the case of the DOE Mercury and Air Toxics program, this program exemplifies the importance of DOE/industry cooperative programs to inform the regulatory process. The jointly sponsored investigations characterizing the chemical nature and soil mobility of high-volume solid wastes from coal combustion were crucial to EPA’s determination that the material is nonhazardous. The consequent avoidance of substantial costs in sequestering CCBs has a significant impact on the cost of electricity from existing plants. While programs of this kind in DOE are not necessarily technology-intensive, they are justified by showing a high benefit-to-cost ratio.

DOE plays an important third-party role between the regulator, EPA, and industry by establishing the credibility of new, expensive knowledge from non-EPA studies that inform the regulatory process. The component of DOE’s R&D portfolio that addresses issues of environmental protection is well justified, in terms of both avoided costs of overconservative regulation and added options for addressing environmental concerns.

TABLE F-13 Benefits Matrix for the Waste Management/Utilization Technologies Programa

 

Realized Benefits/Costs

Options Benefits/Costs

Knowledge Benefits/Costs

Economic benefits/costs

DOE R&D costs: $77 million

Industry costs: Approximately $100 millionb

Avoided sequestration costs associated with RCRA nonhazardous determination: estimated at $3 billionc

None

Development of materials utilized from FGD sludge and ash

Characterization of waste material in storage and in utilized material

Environmental benefits/costs

None

Avoided costs of diversion of land for storage of hazardous material

Design manual for clean coal by-product management and landfill design for combustion ash

Security benefits/costs

None

None

None

aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars.

bWhile FE provides no comprehensive estimate of industry expenditures, industry (including EPRI) has expended at least $5 million a year over the life of the program.

cAvoided costs of (1) sequestration and storage of high-volume coal combustion wastes as hazardous material assuming cumulative wastes from 1988 to 2005 at an incremental cost of $100/ton and DOE RD&D contribution of 40 percent, and (2) continued utilization of clean coal by-products as cement or mineral substitutes. Assumes that DOE work saved 3 years of hazardous waste disposal.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

ADVANCED TURBINE SYSTEMS

Program Description and History

As suppliers have increased the efficiency and reliability of gas turbines in recent years, gas turbine combined cycles have become the system of choice for new power generation additions. This power generation system has the advantage of high efficiency, short installation times, and low initial capital costs. These characteristics have been extremely attractive to both the regulated and deregulated portions of the electrical utility industry. Before the mid-1990s, the advances in the gas turbines were based on technology that was derived from the aircraft industry. The aircraft engines evolved with technical assistance from programs funded by the Department of Defense. Many of the performance advances were derived from materials and cooling technology that allow increased combustion gas temperatures entering the gas turbine, thus resulting in higher efficiencies and higher power densities (potentially lower capital costs). The improvement in gas turbine technology through input from aircraft engine experience was extremely significant to the development of this power generation system. However, with the introduction of tighter emissions standards (NOx control) and the desire to control NOx during the combustion process, the direct use of aircraft engine technology in the next generation of industrial/utility gas turbines was no longer possible. The simultaneous desire to meet tight emission standards and still increase the turbine inlet temperatures required the evaluation and development of new gas turbine technology and design concepts.

The Advanced Turbine Systems (ATS) program was initiated by DOE in 1992 to produce 21st-century gas turbine systems that are more efficient, cleaner, and less expensive to operate than today’s gas turbine systems. The program provides the government/industry partnership that facilitates development of these new-generation systems, while maintaining U.S. supremacy in the highly competitive international gas turbine market.

Two classes of gas turbine are being developed under the ATS program. Simple-cycle industrial gas turbines, less than 20 MW in capacity, are being developed for distributed generation, industrial, and cogeneration markets. Gas turbine combined-cycle systems are being developed for large, baseload, central station, electric power generation markets. The technology is designed to be fuel-flexible, allowing a coal-derived gas or a renewable biomass-based gas to be used as well as natural gas. The utility-scale ATS program includes objectives for (1) operation on natural gas to achieve 60 percent efficiency or more in a combined-cycle mode, (2) NOx emission levels less than 9 ppm, and (3) a 10 percent reduction in the cost of electricity. General Electric and Siemens-Westinghouse are conducting the major systems development work. Each is developing its own concept under separate cost-shared cooperative agreements with DOE.

The Office of Fossil Energy (FE) has responsibility for the utility-based systems, and that part of the program will be the subject of this review.

Funding and Participation

The FE and Energy Efficiency turbine program began in 1992 with the ATS program. The ATS program is a multiyear effort, estimated to total (in constant 1999 dollars) $469 million, approximately $315 million of which is the government share (industrial contracts, internal DOE and other laboratories investigations, and DOE overhead expenses) and approximately $154 million of which is cost-shared by industrial participants. Table F-14 shows a breakdown of

TABLE F-14 Funding for the Advanced Turbine Systems Program (Fossil Energy Component) (millions of 1999 dollars)

 

Fiscal Year

DOE Total

Industry Cost Share

Total Cost

Industry Cost Share (%)

Major Subprogram

1992

1993

1994

1995

1996

1997

1998

1999

2000

Innovative cycle development

 

Concept definition

0.3

6.5

13.1

2.1

 

22.0

7.3

29.3

25.0

Utility system development and demonstration

 

Component development

 

33.2

41.8

41.1

16.3

 

132.4

71.3

203.7

35.0

Demonstration

 

30.4

22.4

17.1

69.9

69.9

139.9

50.0

Industry/university

0.5

2.2

4.4

5.0

5.2

5.1

5.1

5.3

5.0

37.8

1.0

38.8

2.7

Manufacturing technology

 

1.1

1.6

2.1

2.1

2.0

2.0

2.0

12.9

0.0

12.9

0.0

Combustion

 

1.1

0.3

0.5

0.5

0.5

0.5

0.5

0.5

4.5

0.5

5.0

10.4

National Energy Technology Laboratory (in-house)

 

1.1

2.6

2.8

3.1

3.1

3.0

3.0

3.1

21.9

0.0

21.9

0.0

Coal applications

 

1.1

2.1

2.1

2.1

2.0

2.0

2.0

13.4

4.4

17.8

24.9

Total/average

0.8

10.9

22.6

47.3

54.9

53.9

59.4

35.2

29.7

314.8

154.6

469.3

32.9

 

SOURCE: Office of Fossil Energy. 2000. 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.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

ATS funding and industrial cost sharing for the FE programs by major subprogram in constant 1999 dollars.

The ATS program is a new R&D model—a model supported by Congress and the administration. At the start of the program, DOE and the major equipment suppliers developed and set stretch performance and environmental goals for the program. DOE selection of the ATS program participants was based on the ability of the organizations to commercialize the results of the program if successful and to provide financial support. The program structure provides for multiple phases, from conceptual development to ultimate full-scale demonstration. The level of cost sharing required from participants increases as the technology risk decreases. The directed exploratory work that was to be carried out in university laboratories was coordinated with major industrial program participants in order to ensure a path for the implementation of the research results. This also ensured that the parallel laboratory work was focused on real technical issues for the major systems that were the objective of the overall program.

Results

The ATS program has been funded since FY 1992. By mid-year 2000, the gas turbines specifically designed as part of the program were ready for commercial orders. These include the General Electric model 7H and 9H machines. These full-scale machines have been evaluated on test stands, and the plans are in place to install both the 50-Hz (9H) and 60-Hz (7H) systems at utility sites. The Siemens-Westinghouse ATS machine is nearing the point when commercial orders will be taken. Although the power generation concepts developed under the ATS program will provide a basis for systems for the 21st century, it is unlikely that the ATS systems will enter commercial service in a significant way until after 2005.

Siemens-Westinghouse is using its model 501G gas turbine as a testbed for the ATS design. Several of the technical results of the ATS R&D have already been incorporated into the commercial offering of the 501G turbine (this is a term system—that is, it does not meet the total ATS goals but has been developed by the industrial partner).

Parallel technology programs have been conducted at universities and/or government laboratories. These programs are focused on development of critical technologies that will support the development of gas turbine power generation systems. Key areas of research currently include the control of combustion instabilities, testing of novel low-NOx combustor designs, investigation of the chemical kinetics of pollutant formation, and development of advanced diagnostics for measuring heat transfer rates, flow velocities, and pollutant concentrations during turbine component testing.

Benefits and Costs

Although the complete ATS system will not go into major commercial service until after the year 2005, there are spin-off technologies that will have an impact on improvements to the gas turbines systems now in commercial service. It is difficult to accurately ascribe realized benefits to the ATS program since the benefits can only occur after these systems are placed into commercial service (see Table F-15 ). The gas turbine combined cycles now in commercial service were established before the ATS program was begun, and DOE had little impact on their development. The ATS development work is properly focused on a critical national energy goal—the more efficient use of fuels and, at the same time, a significant reduction in environmental impact. Although the initial developments in this program are focused on natural gas as the primary fuel source, DOE has maintained a design goal of fuel flexibility. This will permit coal (and other nonclean fuels) to be used in these gas turbines when they are integrated with gasification/gas cleanup subsystems into an IGCC concept. This integrated system will be the most efficient and environmentally acceptable way to use coal for power generation and will be an important benefit for the environment and for the nation as a whole if it is to rely on coal as a major energy source.

Lessons Learned

The ATS program is an excellent example of a government/industrial program focused on achieving a long-term benefit for the country. When the program is complete, its results will likely be used to establish a power generation system for the 21st century that is both efficient and fuel-flexible and that has the lowest possible environmental impact from fossil fuels. The ultimate success of this program will come from the way DOE initially set up the program. It was recognized that in order to meet the future needs for new power generation systems that are both more efficient and more environmentally acceptable, a significant change would be required in gas turbine technology and design. DOE set goals, that, if successful, would result in major benefits. However, it did this in consultation with industry to ensure buy-in of the objectives. The environmental goals were coordinated with EPA to ensure consistency with proposed future emission standards. In the contract award stage, DOE required significant cost participation in the program and selected vendors that had the technical and manufacturing resources to bring the results of the program to a state of commercial acceptability. No matter how technically successful a program is, it has to be implemented on a commercial scale in order to achieve a national benefit. If the vendors do not have the resources to manufacture at a commercial scale, the R&D efforts will have no impact and achieve no national benefit. DOE cannot assume the role of establishing an industrial manufacturing base for new prod-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

TABLE F-15 Benefits Matrix for the Advanced Turbine System (ATS) Program (Fossil Energy Component)a

 

Realized Benefitsb/Costs

Options Benefits/Costs

Knowledge Benefits/Costs

Economic benefits/costs

DOE R&D costs: $315 million

Private industry R&D costs: $155 million (33 percent cost share)

No realized benefitsc

Technology may produce significant economicd and energye savings

Potential integration with gasification/gas cleanup subsystems into an IGCC concept. May help retain coal as a power generation option.

Assisted in the development of new gas turbine cooling concepts

Development of improved turbine blade life, materials for higher operating temperatures, and three-dimensional viscous aerocomputational techniques

U.S. capability to manufacture thin-walled, complex, single-crystal castings for advanced gas turbines

Environmental benefits/costs

No realized benefits

None

New concepts to improve dry, low-NOx combustion

Security benefits/costs

No realized benefits

None

None

aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000.

bFE estimates of realized economic and environmental benefits are based on a comparison of the market-based H gas turbine combined cycle (GTCC) with the market-based 7FA GTCC. However, there is a serious difference of opinion as to the significance of DOE’s role in the technology development and hence its role in any realized or potential options benefits generated. According to FE, its contribution to the advancement of ATS technology has been “pivotal.” However, the committee believes the fundamental technologies of the currently commercial machines were established before initiation of the ATS program and that DOE had no impact on the development of these current machines and systems.

cFE contends that the economic benefits of lower power costs from ATS installations put in place by 2005 will amount to $5.7 billion over a 30-year life cycle. Although the power generation concepts developed under the ATS program will provide a basis for the systems for the 21st century, it is unlikely that the ATS systems will enter commercial service in a significant way until approximately 2005. If this is the case, it is not clear how FE expects ATS systems installed by 2005 to generate $5.7 billion in economic benefits. There could be spin-off concepts, which would be beneficial for the current class of gas turbine combined cycles; however, this is not the goal of the ATS program, and it is extremely difficult to give economic credit to DOE rather than industry for these spin-off benefits.

dFE estimates that the potential economic benefits of reduced power costs from ATS installations through 2020 total $28 billion.

eFE contends that ATS could save 1 quad annually by 2020, compared with today’s best gas turbine technology and assuming that ATS will achieve 50 percent market penetration.

ucts. Instead, it must rely on the industrial partners of such a program to accomplish this critical and capital-intensive step.

The early phases of the program focused on conceptual designs. This permitted both DOE and its industrial partners to assess, in detail, the concepts that would be followed in the program and was critical to ultimate program success since it reduced the potential to follow paths that had little chance for success. Although the early phases of the program focused on technology and component development, DOE provided for program phases that would take the machines through to full-scale demonstration. Full-scale demonstration is the most difficult and costly phase of a program, and DOE’s willingness to participate in this phase will help ensure a commercially acceptable product. DOE also insisted on increasing the industry’s cost share as the program moved through the various stages, with the largest share in the demonstration phases. This ensured that the industrial partners were committed to commercialization of the final program product.

The overall ATS program has elements of focused, applied fundamental research, which is often conducted in university and government laboratories. However, DOE made a major effort to ensure that these more fundamental elements of the overall program enjoyed the involvement of the industrial partners who were responsible for the total ATS system development. Although this was difficult to achieve, the research results will have a higher probability of being successfully employed.

In summary, the ATS program was well conceived by DOE and had (1) good goals with industrial and government buy-in, (2) conceptual assessment before major funding commitments are made, (3) industrial partners that could take the developments to a commercial stage, (4) coordination of applied research with the prime contractors, and (5) program phases that will support the development through full-scale demonstration.

STATIONARY FUEL CELL PROGRAM

Program Description and History

The DOE Office of Fossil Energy has supported fuel cell technologies for electrical generation whereas, traditionally,

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

DOE’s Office of Energy Efficiency and Renewable Energy has supported low-temperature fuel cells (proton exchange membrane, or PEM). FE has funded three types of fuel cells for stationary electricity generation since 1976. The fuel cells can be characterized by the temperatures at which they operate: low, ~200°C; intermediate, ~650°C; and high, ~1000°C. They can also be characterized by their electrolyte (that is, phosphoric acid, molten carbonate, or solid oxide). The phosphoric acid fuel cell (PAFC) has an aqueous electrolyte solution of phosphoric acid. This concept made its market entry in 1992 with the sale of 200-kW units manufactured and marketed by International Fuel Cells (IFC). The attempt to commercialize the fuel cell concept was supported by the DOE’s buy-down program. DOE stopped funding the low-temperature fuel cell after this commercialization attempt. Molten carbonate fuel cells (MCFCs) use a mixture of carbonates that are liquid at the operating temperature. The developer, FuelCell Energy (FCE), is in the demonstration phase of the program, has field-tested a 2-MW system, and is now field-testing a 250-kW, near-commercial system. Solid oxide fuel cells (SOFC) employ an electrolyte that is a solid ceramic material. It remains solid at the operating temperature of 1000°C. The developer, Siemens Westinghouse Power Corporation (SWPC), is in the demonstration phase of the program and is field testing a 100-kW fuel cell system and a 220-kW fuel cell/gas turbine hybrid system. DOE support is continuing for both the intermediate- and high-temperature fuel cell concepts.

A fuel cell is an electrochemical device that produces electric power from a fuel. Fuel (usually a hydrogen-rich gas) is continuously supplied to the anode (negative electrode) and the oxidant (oxygen from air) is continuously supplied to the cathode (positive electrode). The electrodes are separated by an electrolyte that conducts ions. However, for the fuel cell to function as a complete system, it requires several supporting subsystems: (1) a fuel processor to clean and convert the as-delivered fuel to a hydrogen-rich fuel and remove trace contaminants like sulfur and (2) the power section—the fuel cell stacks and the power conditioner—required to convert the produced DC electricity to AC for practical applications. In addition to these critical subsystems, the fuel and oxidant must be handled at the operating temperature of the fuel cell, which may be in excess of 500°C, which is higher than typical temperatures in commercial steam turbines for power generation.

The attractiveness of fuel cells for power generation has been the claim of high efficiencies with reduced environmental impact. However, as with gas turbine combined cycles, these claimed efficiencies can only be achieved in combination with other power generation systems, i.e., combined-cycle operation. Although fuel cells are normally discussed as if they are similar devices, the applications and operational characteristics of the three different types of fuel cells are quite different. Low-temperature fuel cells have the potential for distributed power applications but will be at lower efficiency. High-temperature fuel cells have the potential for higher efficiency but have operational characteristics that would probably limit them to larger-scale applications and will require integration with other power generation systems, e.g., gas and/or steam turbines, in order to achieve competitive efficiencies.

At the beginning of the 1990s, FE, for purposes of commercial demonstration and development, supported two PAFC developers, three MCFC developers, and one SOFC developer. As the decade ended, only three of these developers remained (one PAFC, one MCFC, and one SOFC). However, it now appears that interest in the SOFC technology is increasing, and more industrial organizations are focused on developing support subsystems for this fuel cell concept.

Funding and Participation

Total funding for the Fuel Cell program from FY 1978 through FY 2000 was $1167 million. Table F-16 shows budget line item program elements.

FE required cost sharing from the participants in the Fuel Cell program. The guideline for this program was for a developer to contribute a minimum of 20 percent of the total activity cost for a technology development activity and a minimum of 50 percent for a system field test demonstration activity. Cost sharing for start-up development activities and advanced research efforts was not required.

Results

In spite of NASA’s success in the development of alkaline fuel cells for space power applications in the late 1960s, this fuel cell concept could not be applied for stationary power. The technology for stationary applications would

TABLE F-16 Funding for the DOE Fuel Cell Program, FY 1978 to FY 2000 (millions of 1999 dollars)

Budget Line Item

Appropriation

Stage

Phosphoric acid fuel cells

410.8

Applied R&D

Molten carbonate fuel cells

406.9

Applied R&D

Solid oxide fuel cells (advanced concepts)

198.0

Applied R&D

Fuel cell systems (includes MCFC, SOFC)

114.2

Applied R&D

Multilayer ceramic technology

3.7

Applied R&D

Advanced research

33.7

Basic and applied research

 

SOURCE: Office of Fossil Energy. 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.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

need to be quite different and would require development efforts. The fuel cells for stationary applications would need to operate with readily available fuels and use air as an oxidant in lieu of ultrapure hydrogen and oxygen. More importantly, stationary fuel cells would have to be much lower in capital cost. As developers undertook the task of commercializing fuel cells, it was clear that they could not do this on their own because of the high technological and financial risks. Many of the vendors were small companies dedicated to the application of fuel cells for industrial/utility power generation. These companies had shown that they were not able to sustain fuel cell development without significant DOE/FE support. Although significant effort was put into low-temperature and mid-temperature fuel cells in the 1980s, a large-scale commercial application of these technologies never developed. While the PAFC program in the early 1990s resulted in the sale of several hundred small units, this was achieved with the aid of government funding. High-temperature fuel cells have also been under development in laboratories since the early 1970s. These fuel cells, while possessing attractive operational characteristics, have never been developed to a commercial scale.

During more than 30 years of fuel cell development, many of the large suppliers of power generation equipment elected to terminate their company-sponsored programs in fuel cell technology. The organizations that continued to work in fuel cell development did so mainly with financial support from the DOE program. As a result, there are a number of companies that now view fuel cells as having a potentially significant future market. These organizations have initiated the development of fuel cell support systems, e.g., fuel reformers, on their own, without DOE financial support.

Benefits and Costs

The portion of the Fuel Cell program that was terminated between 1978 and 2000 was for low-temperature fuel cells. FE support for this technology was not maintained because the effort was successfully completed. PAFC power systems were judged to be commercial in 1992, and two hundred ~200-kW units were supplied worldwide, in large part as a result of the U.S. government buy-down program, which subsidized about one-third of the initial capital cost. Although other fuel cell R&D programs were continued, there have been no commercial products introduced from these programs.

DOE/FE funding for fuel cells was originally a part of the coal budget sector. In FY 1994, the fuel cell program became part of the natural gas budget sector. Cumulative totals for each are $845.8 million within the coal sector and $321.4 million within the natural gas sector (Table F-17) (OFE, 2000k).

DOE support is continuing and is claiming the possibility of commercial entry in niche markets by about 2003, with large-scale production (400 MW per year capacity) anticipated by 2005. It is questionable if this goal can be achieved on DOE’s stated timeline. Since there will not be a substantial number of units in service before 2005 (the guideline of this study for realized benefits), no benefits can be attributed to this program.

Lessons Learned

Fuel cells, as a technology to generate power directly from fuel with no moving parts, have an appeal, and for some

TABLE F-17 Benefits Matrix for the Stationary Fuel Cells Programa

 

Realized Benefits/Costs

Options Benefits/Costs

Knowledge Benefits/Costs

Economic benefits/costs

DOE R&D costs: $1167 million through 2000 for three fuel cell technologies (PAFC, MCFC, SOFC)

The early low-temperature fuel cells, which were subsidized, produced no economic benefit

Potential market by 2003; 400-MW per year manufacturing plant expected by 2005

Could be used as back-up and stand-alone power sources

Development of compact fuel reformers, electrolyzers, critical materials and processes, and multilayer ceramic technology

Environmental benefits/costs

None

Fuel cells provide clean power and emit 60 percent less global warming gases than combustion engines

Potentially higher efficiency and lower NOx emissions than small single-cycle gas turbines

None

Security benefits/costs

None

None

Distributed generation could provide improved grid stability

aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

applications, for example, power in space missions, the technology is an ideal match. However, when the technology was tried for stationary applications, the inability of the fuel cells to accept fuels and oxidants that were not ultraclean necessitated fuel/oxidant treatment subsystems, which increased the complexity and cost of these fuel cells. In the 30 years of DOE support for fuel cells, there has been little or no commercial application that resulted in substantial public benefit and no commercial product without DOE subsidies. This leads one to question the ability of subsidies to drive a new product to market if that product does not have significant stand-alone commercial benefits.

The promised efficiency of fuel cells is a moving target. Gas turbine combined cycles have become the accepted power generation technology for the utility industry, and their efficiencies are projected under the DOE ATS program to reach 60 percent. Thus, there is no doubt that opportunities exist to increase the efficiency of conventional systems, so fuel cells will need to meet higher efficiency and lower capital cost targets in order to be considered. As fuel cell systems become more complex in order to compete, it will be more difficult to achieve market acceptance. Systems that have to rely on many elements working together in order to produce a desired result are normally viewed by the utility industry as having reliability issues. This was one of the major concerns that limited the use of gas turbine combined-cycle technology in its early stages of development. Overcoming the reliability issue will require many years of successful operation at the full-scale demonstration scale.

In the 30 years of the program, major companies have terminated their internal programs and have exited DOE-sponsored programs. The only thing that has kept this program going is an extremely strong advocacy group and the significant DOE program funding.

In many ways, the fuel cell program shares characteristics with the MHD program. It is difficult if not impossible for DOE to drive a program to the point of commercial reality with its funding alone unless there is a real effort by industry, with the manufacturing infrastructure and financial support, to commercialize the technology. DOE has not been very successful here in determining if an industrial partner is seriously undertaking the R&D or just in the program to receive DOE funding support. Although industrial support for fuel cell program has increased in recent years, it has yet to be shown that the program will result in benefits that are in line with the more than $1 billion that has been invested in this technology area.

MAGNETOHYDRODYNAMICS

Program Description and History

Driven in large measure by the desire to find ways to use abundant domestic coal resources, DOE’s Office of Fossil Energy (FE) conducted R&D on magnetohydrodynamics (MHD) technology for 16 years because of its perceived potential as a major technology for electric power generation using coal. The program successfully proved the concept of using MHD technology but was discontinued in 1993 because of the high cost of designing, constructing, and operating a complete MHD system.

Both an MHD power generator and a conventional generator are based on the electromagnetic induction principle. A conductor moves through a magnetic field inducing an electric field in the conductor. While a conventional generator relies on the copper windings of the rotating conductor, an MHD generator uses the gaseous products of combustion that are ionized by raising them to sufficiently high temperatures in seeded conductive material. Thus, a perceived advantage of the MHD concept is the absence of moving parts.

The DOE R&D concept for a central-station electric power station based on MHD technology consisted of two cycles in series—an MHD topping cycle, from which power would be extracted directly, and a steam bottoming cycle, in which power is produced in a conventional steam turbine cycle:

  • In the topping cycle, coal is burned in a pressurized combustor with preheated air or oxygen-enriched air to produce a combustion gas having a temperature of 2482°C to 2760°C. At this temperature, the combustion gas is only slightly conductive due to thermal ionization. An easily ionized seed material such as potassium is added to increase conductivity, and the combustion gas is expanded through the MHD generator, located in the magnetic field. As the gas exits the generator, it is decelerated in a diffuser and discharged at approximately 1982°C into a steam boiler.

  • In the bottoming cycle, NOx emissions are controlled by tailoring the time-temperature profile within the radiant boiler to keep the NOx content within allowable levels and by fuel-rich combustion. SOx is removed from the gas stream by reaction with potassium seed from the topping cycle to form a recoverable solid product. Use of an electrostatic precipitator or a baghouse at the exit of the boiler controls particulate emissions. Spent seed removed from the bottoming cycle is supplied to a regeneration system, where it is converted to a non-sulfur-containing form for reinjection into the topping cycle.

Initial MHD research in the United States was conducted primarily at universities and private companies. Early government interest in MHD was directed at developing power sources for space and military applications and centered in agencies such as the Department of the Interior’s Office of Coal Research, the National Science Foundation, the Atomic Energy Commission, the National Aeronautics and Space Administration, and the Department of Defense. The energy crises of the early 1970s focused more attention on MHD’s potential as a central-station power-generating concept using abundant coal resources, leading to increased R&D sup-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

port by DOE’s predecessor agency, the Energy Research and Development Administration (ERDA). After the creation of DOE in 1977, MHD quickly became one of its major technology programs.

DOE’s MHD program was focused on the development of two major test facilities—the Component Development and Integration Facility (CDIF) and the Coal-Fired Flow Facility (CFFF). The CDIF, in Butte, Montana, was designed for testing the MHD topping cycle and subsystems at a scale of up to 50 MW. The CFFF, at Tullahoma, Tennessee, emphasized the testing of bottoming cycle components and subsystems at a nominal scale of 28 MW. The R&D program at the test facilities went through three phases. The initial phase involved facility design, construction, and testing. The second phase involved scale-up and preliminary testing of components. The third and final phase was initiated in 1984 and involved a multiyear effort targeted at achieving integrated proof of concept testing at CDIF and CFFF.

Funding and Participation

Between 1978 and 1993, DOE expenditures for the MHD program totaled about $680 million, or $1020 million in constant 1999 dollars. Over this same period, private industry cost sharing totaled about $61 million. Cost sharing began in 1986, when private industry was required by legislation to cost share, initially at 10 percent, but increasing to 35 percent by the end of the proof-of-concept program, in 1993.

Almost half of the DOE expenditures for MHD R&D occurred in the first 4 years, from 1978 to 1981, during design and construction of the test facilities. A review of DOE requests and congressional appropriations for the MHD program shows that in those years Congress funded the program close to the level requested by DOE. The record also shows that, with the exception of 1985, DOE did not request any funds for the MHD program from 1982 to 1993, when the program was finally terminated. In those years, the funding came from direct congressional line item additions to the DOE budget. The MHD funding history is shown in Table F-18 in actual and constant 1999 dollars.

Results

As noted above, funding of the MHD R&D program was terminated after 1993. While the MHD program was modestly successful in the proof-of-concept phases, system evaluation studies were indicating that the cost to design, construct, and operate a central station MHD power generation facility was much higher than the corresponding cost for other coal-fired power generation options. In addition to the high costs, the claim for high-cycle efficiencies was questionable. This raised real doubts that the MHD system could compete on an efficiency basis with the advanced gas turbine combined cycles used by the utility industry. These doubts ultimately led to program termination. As discussed

TABLE F-18 DOE Funding for the Magnetohydrodynamics Program (millions of dollars)

Fiscal Year

Current Dollars

1999 Dollars

1978

70

145.1

1979

76

145.5

1980

72

125.2

1981

70

112.2

1982

29

43.8

1983

29

42.1

1984

30

42.0

1985

30

40.7

1986

27

35.9

1987

26

33.5

1988

35

43.6

1989

37

44.4

1990

40

46.2

1991

40

44.6

1992

39

42.5

1993

30

31.9

 

SOURCE: Office of Fossil Energy. 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.

in the following section, the MHD R&D program did contribute valuable information to some spin-off technologies that are either are being applied or may find application.

Benefits and Costs

The benefits and costs of DOE’s MHD R&D program are summarized in the matrix shown in Table F-19. The program had no realized economic, environmental, or security benefits. While the MHD concept was proved, the decision to terminate before proof of concept could be established at close to a commercial scale means MHD has little if any options value. The R&D did, however, result in some knowledge benefits, among them the following:

  • Provided a database for technologies that require the injection of solids into pressurized chambers,

  • Contributed to combustor development for subsequent clean coal technology projects,

  • Contributed insights on collecting current from multiple power sources that may be applicable to fuel cells,

  • Provided a database for pressurized high-temperature gas heaters,

  • Provided MHD generator information that may find applicability in defense programs (missile defense) and NASA programs (wind tunnels, assisted launch vehicles), and

  • Provided a material database for boiler tube fabrication in a corrosive environment.

Although these claims for spin-off applications are made by DOE, no direct commercial benefit can be attributed to

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

TABLE F-19 Benefits Matrix for the Magnetohydrodynamics (MHD) Programa

 

Realized Benefits/Costs

Options Benefits/Costs

Knowledge Benefits/Costs

Economic benefits/costs

DOE R&D costs: $1.02 billionb

Industry costs: about $90 millionc

No benefits, since the technology was not deployed

None

Provided databases for technologies that require the injection of solids into pressurized chambers, for pressurized high-temperature gas heaters, and for boiler tube fabrication in a corrosive environment

Contributed to combustor development for subsequent clean coal technology projects

Developed a materials research database for boiler tube fabrication in a corrosive environment

R&D on regenerative air heaters and database for pressurized higher-temperature air heaters

Environmental benefits/costs

None

None

None

Security benefits/costs

None

None

None

aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000.

bThe program was funded between 1978 and 1993. Of the $1.02 billion expended on the program over this period, DOE requested only $590 million for the years 1978 to 1981 and 1985. The remainder of the funding, $430 million (42 percent of the total), was added to the DOE budget by direct congressional line items additions.

cBeginning in 1986, the private sector was mandated to cost share at a 10 percent level, which steadily increased to 35 percent at the end of the proof-of-concept program in 1993.

the MHD technology program. The only contribution would be additions to the knowledge base for high-temperature components.

Lessons Learned

MHD was one of several early DOE R&D programs focused on finding ways to make greater use of domestic natural resources for energy. In the late 1970s and early 1980s, the government played a key role in funding demonstration of the technology.

The funding history clearly shows that substantial funds continued to be spent after 1981 to prove the MHD concept in the face of data that were showing significant technical barriers to the successful development of the concept. At the same time, studies indicated that even if developed, the MHD power generation system would not be competitive on an efficiency or cost basis with alternatives that were already in use by the utility industry. The data suggest that this information led to DOE’s decision not to request funding after 1981, except for 1985. However, Congress continued to fund the program through 1993, an indication of the strength of congressional support for MHD.

In looking at this history, we need to keep in mind the government role in technology demonstration on the heels of the energy crises of the 1970s. Once an investment had been made in large-scale proof-of-concept experimental facilities, there was pressure to use the R&D facilities to prove the concept even with data suggesting that the costs of deploying the technology would be too high. Several lessons can be learned from this experience:

  • Private sector interest in developing a technology, as evidenced by a willingness to cost share in the demonstration process, must be considered. In MHD, some cost sharing was mandated by the congressional appropriation acts that kept the program going (10 percent starting in 1986, growing to 35 percent by termination in 1993), but there was no cost sharing in the design, construction, and early operation of the costly large-scale facilities.

  • There must be an understanding of where a technology fits in an R&D portfolio from a priority standpoint, so that decision makers at all levels can be provided with all the information they need to make the best decisions in the interest of the overall R&D program.

  • Difficult decisions to terminate programs must be made

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

as early as possible and available funds redirected to the areas of greatest potential.

COAL-BED METHANE

Program Description and History

During the natural gas shortages of the 1970s, there was a widespread notion that the resource base of natural gas in the United States was substantially depleted. A variety of nonconventional sources, including coal-bed methane, were considered as possible sources of commercial gas. With a combination of basic and applied research, field demonstrations, and tax credit incentives, many of these nonconventional sources of natural gas now compete with conventional sources and contribute significantly to the nation’s gas supply. Coal-bed methane (CBM) currently supplies 1.3 Tcf annually, or 7 percent of total domestic production of natural gas.

Early work on CBM was carried out by the U.S. Bureau of Mines and focused on predraining and capturing methane from the active, gassy mines of the Appalachia and Warrior basins. The Bureau of Mines program was assumed by DOE in 1978 and funded for 5 years. Subsequent R&D was conducted chiefly by the Gas Research Institute (GRI) and industry. The DOE effort was aimed mostly at defining the size and recoverability of the resource base as well as the use of natural gas associated with active coal mine operations. Several pilot field projects were conducted, including testing the use of vertical wells in deep, unminable coalbeds; testing the use of vertical wells in multiple coalbeds; and combining in-mine, multiple horizontal boreholes and CBM-fueled gas turbines for on-site power generation. Experiments in hydraulic fracture stimulation, conducted by the Bureau of Mines and later by DOE, demonstrated the utility of this technology in CBM recovery. In addition to the FE program, the DOE Small Business Innovative Research program funded several projects involving strategies for well-site selection, drilling practices, and well-completion techniques for coal-bed methane production.

Funding and Participation

The DOE coal-bed methane program was funded for 5 years, from 1978 to 1982, as shown in Table F-20. DOE reports that significant cost sharing was obtained from industry for the vertical well pilot project and the hydraulic fracture mine-back efforts on the Warrior Basin, but that no specific information on the associated expenditures is available.

Results

DOE’s CBM program was relatively short-lived and modestly funded, with much of the fuller development of this

TABLE F-20 Funding for the Coal-bed Methane Program (millions of 1999 dollars)

Year

Funding

1978

1.5

1979

8.0

1980

9.2

1981

8.4

1982

3.0

Total

30.1

 

SOURCE: Office of Fossil Energy. 2001c. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Coal-bed Methane Program, January 10.

resource, as DOE acknowledges, attributable to the R&D efforts of GRI, which made CBM research a high priority, to industry activity, and to the provision of tax credits as incentives for development of the resource. The tax incentives no longer exist, but together with basic and applied research, they were able to establish an industry that is thriving without tax credit incentives and that has been competitive in recent years in a market of relatively cheap natural gas. Nonetheless, DOE played a critical role in recognizing the commercial potential of CBM, in initially assessing the magnitude of the resource, and in certain pilot field tests.

Costs and Benefits

DOE calculates realized economic benefits of $499 million (1999 dollars) in increased revenues and cost savings to producers, primarily from the Warrior and San Juan basins, with a benefit to cost ratio of 16.6. In addition, $91 million (1999 dollars) is credited from royalties on federal lands and from increased state severance taxes due to displacement of imports. If DOE were credited with one-third of the benefits, this would amount to about $200 million (see Table F-21).

Lessons Learned

The DOE CBM program demonstrates that even with a modest amount of funding over a relatively short period, early involvement of public research can prove beneficial. The initial work led GRI to take up CBM R&D and make it a top priority, and it stimulated industry interest, which—coupled with production incentives in the form of tax credits—created an entirely new supply of natural gas.

DRILLING, COMPLETION, AND STIMULATION PROGRAM

Program Description and History

DOE has a long history of involvement with the oil and gas industry. The Drilling, Completion, and Stimulation pro-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

TABLE F-21 Benefits Matrix for the Coal-bed Methane Programa

 

Realized Benefits/Costs

Options Benefits/Costs

Knowledge Benefits/Costs

Economic benefits/costs

DOE R&D costs: $30.1 millionb

Industry cost share: significant but indeterminatec

Substantial economic benefits:d $200 million

Verified substantial undeveloped resource basee

Increased gas supply

Given the termination of DOE’s R&D, there are minimal options benefits

Future application of the basic science established by the DOE program may enable new domestic (and international) coal-bed methane basins to become productive

Provided an essential scientific knowledge basef

Conducted pilot field tests and projectsg

Experiments that demonstrated hydraulic fracture stimulationh

Basic science on coal-bed methane storage and production mechanisms

Environmental benefits/costs

Reduced methane emissions to the atmospherei

Potential to reduce greenhouse gasesj

Provided guidance to EPA on coal-bed methane emission control mechanisms

Security benefits/costs

None

Minimal

Increased understanding of the size of the domestic natural gas resource base

aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000.

bIn addition to the FE program, the DOE Small Business Innovative Research program funded several projects involving well-site selection strategies, drilling practices, and well completion techniques for coal-bed methane production.

cDOE reports that significant cost sharing was obtained from industry for the vertical well pilot project and hydraulic fracture mine-back efforts on the Warrior Basin, but that no specific information on the expenditures is available.

dFE estimates that the benefits total $499 million in lower producer costs and $91 million from incremental royalties and taxes. FE assumed that (1) basic science is credited with 20 percent of the production impact, and applied science and field demonstrations are credited with the remaining 80 percent; (2) the DOE CBM program is allocated one-third of the basic science production impact, based on providing one-third of the basic R&D expenditures; industry and GRI are allocated the remaining two-thirds; (3) the DOE CBM program is allocated 20 percent of the CBM production impact in the Warrior Basin; and (4) industry and GRI are allocated 80 percent of the CBM production impact from the Warrior Basin and 100 percent of the CBM production impact from all other basins. However, it must be recognized that, through 1992, coal-bed methane benefited from the existence of Section 29 tax incentives for the production of unconventional gas. These incentives were substantial and worked in conjunction with the DOE R&D program to increase the production of coal-bed methane. DOE is credited based on the above with a $200 million benefit.

eThe DOE effort was aimed mostly at defining the size and recoverability of the resource base as well as the use of natural gas associated with active coalmine operations. The DOE CBM resource assessments established that a large, 400-Tcf natural gas resource was contained in coal seams.

fDOE’s initial coal-bed methane R&D program provided a significant portion of the basic R&D that formed the scientific knowledge base for this gas resource, and established the essential coal-bed methane storage and flow mechanisms, including adsorption, desorption, diffusion, and fracture-dominated flow.

gThese included the test of use of vertical wells in deep, unminable coals, testing the use of vertical wells in multiple coalbeds, and combining in-mine, multiple horizontal boreholes and CBM-fueled gas turbines for on-site power generation. A major breakthrough occurred when DOE demonstrated that CBM could be efficiently produced using vertical wells, as opposed to only using in-mine horizontal boreholes. The program also supported field tests that demonstrated the mechanisms of methane storage and flow in a near-commercial setting (a closely spaced well pattern) and supported field tests of the performance and effectiveness of using hydraulic fracturing to stimulate gas flow from coal seams in a series of test wells followed by mine-back experiments.

hConducted by the Bureau of Mines and later by DOE, these demonstrated the utility of this technology in coal-bed methane recovery and that coal seams could be efficiently and safely hydraulically fractured, thus accelerating the rates of gas flow in these low-permeability formations.

iFE estimates reductions of at least 1000 Bcf.

jOwing to current concerns over greenhouse gases, there is renewed federal government interest in coal-bed methane: DOE’s Carbon Sequestration R&D program is sponsoring a major enhanced coalbed methane recovery project, and EPA is supporting R&D on mine-related coal-bed methane emissions capture and use in both U.S. and overseas coalmines.

gram goes back to the drilling research program initiated in 1975 following the Arab oil embargo. The program focused on developing drilling technology to increase domestic oil and gas production. In 1993 it was separated into oil and gas subsections. The gas research program focuses on technology to increase natural gas production.

The current Drilling, Completion, and Stimulation program is designed to develop technology to reduce drilling costs, minimize formation damage, lower environmental risks, reduce surface footprint of onshore and offshore drilling, and improve access to culturally and environmentally sensitive areas. The program has consisted of a very large number of relatively small projects covering almost every facet of the drilling, completion, and stimulation technologies. Among the many research projects were research on the use of titanium pipe in extended-reach drilling; expandable metal packers; matrix and fracture acidizing; in situ rock stress measurements; geomechanics for sand control; geomechanics of horizontal completions; polycrystalline compact diamond drill bit technology; underbalanced drilling technology; mud pulse telemetry; and high-temperature measurements while drilling.

Historically, much of the technology covered under this program is implemented in the oil industry by service com-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

panies. The technologies are developed primarily by the oil service companies and oil companies. The oil companies usually make the technology they develop available to the industry by licensing it to the service industry. However, in recent years research by oil companies in this area has significantly declined. This was due in part to industry downsizing. It was also due to the difficulty of justifying research in a technology field where it is difficult to maintain a proprietary position.

DOE has historically worked closely with the industry in partnership programs such as the Natural Gas and Technology Partnership and in the Drilling, Completion and Stimulation Technology Forum. Through such partnership, industry gains access to the capabilities of the national laboratories in electronics, instrumentation, materials, computer hardware and software, etc. In 1992, DOE reorganized the program to make it more accessible and to stimulate more joint development projects.

Funding and Participation

Industry has indicated its interest in these programs by funding 29 percent of the total expenditures from 1978 to 1999 (see Table F-22). The programs had a wide range of participants from the oil field service industry, the oil industry, universities, and the national laboratories.

Funding for this program has undergone the usual fluctuations due to changes in administration priorities. For example, funding was curtailed in 1982, reflecting the administration’s position that government should not be involved in development of a resource base. In 1992, the administration directed DOE to conduct R&D to increase the natural gas resource base. In 1993, an administration program, the Natural Gas and Oil Initiative, led to a significant increase in the natural gas R&D program. At the same time the focus was shifted from developing a resource base to developing technology, particularly to meet the challenge of drilling in deeper and hotter rocks.

TABLE F-22 Total Funding for the Drilling, Completion, and Stimulation Program, FY 1978 to FY 1999 (millions of 1999 dollars)

 

DOE

Industry Cost Share

Total

Oil programs

48

24 (33%)

72

Gas programs

31

8 (21%)

39

Total

79

32 (29%)

111

 

SOURCE: Office of Fossil Energy. 2000m. OFE letter response to questions on the Drilling, Completion, and Stimulation Program from the Committee on Benefits of DOE R&D on Energy Efficiency and Fossil Energy, December 4.

Results

The early drilling program, prior to 1983, focused on the need to gain more efficiency from the limited number of drilling rigs available at that time. While the early program focused heavily on drilling technology, the post-1983 programs cover a broader range of completion and stimulation technologies.

Oil Programs

The oil programs can be categorized into five elements: (1) drill system development, (2) drill fluids and underbalance drilling, (3) surface operations, (4) completion, and (5) stimulation. To indicate the scope and depth of the program, some of the projects in each of these five areas are summarized below.

Drill System Development Projects
  • Polycrystalline diamond compact drilling bit. DOE played a significant role in the development of the polycrystalline diamond compact drilling bit (PDC). DOE funded work at Sandia National Laboratory and at General Electric to improve the bit design. It also funded field tests to demonstrate the technology. Penetration rates were three to five times faster than with conventional diamond bits. Today these drill bits account for about one-third of the worldwide drill bit market and enjoy sales of over $200 million per year.

  • Pressure coring system. Technology was developed to improve coring under pressure to preserve the fluid characteristics of the core.

  • Mud pulse telemetry. DOE played a significant role in the development of mud pulse telemetry. It supported a field demonstration of the technology in its very early and critical phase of development. This important technology led to the development of the measurement-while-drilling and logging-while-drilling service industry.

  • Electrodril. DOE participated in the development of the Electrodril system, which uses an electric motor downhole. While the Electrodril system was never commercialized in the United States, technology that was developed to transmit the power downhole was essential to the future development of the measurement-while-drilling and logging-while-drilling technologies.

  • Microdrilling. DOE has been active in the development of microdrilling, the drilling of holes of 1 in. diameter. Microdrilling can be cheaper and more environmentally sensitive for exploratory drilling. The concept was demonstrated with coil tubing.

Drill Fluids and Underbalance Drilling Projects
  • Air, mist, and foam aerated drilling. DOE developed new tools and a simulator for modeling the flow of compressible drill fluids and cuttings in a well bore.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Surface Operations Projects
  • Gas liquids cylindrical cyclone. DOE has been involved in the development of new cylindrical cyclones for gas liquids that are more compact and more efficient than conventional separators.

  • Fiber-optic sensors for downhole production monitoring. DOE is funding the development of a new, improved fiber-optic sensor technology for precise monitoring of temperature and pressure at reservoir producing intervals. It has the advantage of being small, self-calibrating, and able to withstand high temperatures and pressures.

Completion Projects
  • Ceramic borehole sealants. Chemically bonded phosphate ceramic sealants, technology created for the stabilization of radioactive waste, show promise as borehole sealants in place of conventional cement.

Stimulation Projects
  • Tiltmeter technology. Improved range, cost, size, and efficiency of tiltmeter technology are used to determine the orientation of underground fractures.

Gas Programs

The gas programs can be divided into five program areas (Table F-23). Several of the projects in the gas programs are summarized below to indicate the scope and depth of this program.

Drilling System Efficiency
  • High-power slimhole drilling system. DOE is developing a high-power slimhole drilling system that increases the rate of penetration, which is one of the major limitations on the use of slimhole drilling.

  • High-temperature measurement while drilling/logging while drilling. DOE is supporting the development of high-temperature measurement-while-drilling and high-temperature logging-while-drilling technologies, improving the ability to use smart technology when drilling for deep gas.

  • Composite drill pipe. DOE is supporting the development of drill pipe made from lightweight composites, which are about half the weight of steel pipe, thereby improving the ability to drill horizontal boreholes and to drill in deep water.

Underbalanced Drilling Systems
  • Integrated directional drilling system. DOE has supported the development of an “electromagnetic measurement while drilling” system and the development of a commercially viable underbalanced drilling system using this technology. Underbalanced drilling systems have been shown to increase the rate of penetration and minimize formation damage.

New Concept Drilling Systems
  • High-pressure coil tubing drilling system. DOE is developing a high-pressure drilling system where high-pressure fluid is transmitted to a high-pressure motor at the hole bottom through concentric coil tubing. This system is ex-

TABLE F-23 ADCS Gas Project Organizational Charta

Drilling System Efficiency

Underbalanced Drilling Systems

New Concept Drilling Systems

Supporting Research

Advanced Completion and Stimulation Systems

High-power slimhole drilling system

High-pressure slimhole pump assist drilling system

Conventional mud hammer

High-temperature MWD

High-temperature LWD

Mud-hammer optimization

Composite drill pipe

Integrated directional drilling system and slimhole EMMWD

Underbalanced drilling products

Lightweight solid additives

Foam 1 (foam drilling model)

Underbalanced drilling simulator

Steerable air percussion system

Advanced drilling system development

High-pressure CT drilling system

Advanced mud-hammer drilling system

Advanced TSP bits by microwave brazing

Microwave processing

Hydraulic pulse drill

Horizontal well technology (DEA-44)

Coiled-tubing and slimhole technology (DEA-67)

Underbalanced drilling technology (DEA-101)

Deep water riser wear study (DEA-137)

Fracture fluid characterization facility (FFCF)

Perforation dynamics study

CO2/sand fracture study

New nondamaging drill-in fluids

Real-time downhole stimulation monitoring and control system downhole fluid analyzer

Ultradeepwater completion system

aADCS, advanced drilling, completion, and stimulation; CT, coil tubing; EMMWD, electromagnetic measurement while drilling; LWD, logging while drilling; MWD, measurement while drilling; and TSP, thermally stable polycrystalline.

SOURCE: Office of Fossil Energy. 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.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

pected to drill two or three times faster than conventional coil tube drilling systems. Field trials are scheduled.

  • Advanced mud-hammer drilling system. DOE is supporting the development of advanced concepts in mud hammer drilling to reduce drilling costs for hard rock formations.

Supporting Research

DOE supports industry projects in such areas as horizontal drilling, coil tubing and slimhole drilling, and underbalanced drilling.

Advanced Completion and Stimulation Systems
  • Real-time downhole stimulation monitoring and control system. DOE is participating in the development of technology to monitor reservoir stimulation procedures in real time and to mix fracturing fluids downhole. Together these technologies can be used to increase the production of natural gas by increasing the efficiency and reducing the cost of fracturing tight gas-bearing sands. Field tests in which fracture fluids and sand were mixed downhole indicate significant potential for this technology.

  • Ultradeepwater completion system. DOE is participating with industry in the development of deepwater production technology to allow subsea separation of oil, gas, and water.

Benefits and Costs
Economic Benefits

The cumulative cost to DOE of the oil program from 1978 to 1999 was $48 million and the cumulative cost of the gas program was $31 million, for a total of $79 million, all in 1999 dollars (see Table F-24).

Many of the projects were quite successful and are producing significant economic benefits. Nevertheless, it is difficult to assess the total benefit, in part because both programs consist of a myriad of small projects. Also, it is difficult to separate the contributions made by DOE and contributions made by industry and others.

DOE assessed the benefits from the oil programs from 1978 to 2005 at $2.2 billion. While it has not been possible to verify the bases for all these assessments, it is certainly obvious that DOE has made a contribution well in excess of its outlay. For example, DOE made important contributions to projects such as the development of polycrystalline diamond compact drill bits, horizontal drilling, slimhole and coil tubing drilling, synthetic drilling fluids, cutting injection, wireless telemetry for production monitoring, and gas liquids cylindrical cyclones.

DOE did not assess the total value of the gas program, but it assessed the benefits of just two projects, namely, underbalanced drilling technologies and high-temperature measurement while drilling/logging while drilling. It estimated a benefit of $252 million from the two programs.

DOE supported the development of important and high-risk projects that might not otherwise have been done by industry, with a significant benefit to the country. While difficult to quantify, it is clear that DOE created benefits that substantially exceeded their outlay. DOE claimed very large benefits for the program; however, DOE did not calculate the cost-benefit ratio by the recommended methodology. Clearly, there were significant benefits from the program. However, because of the large number of small projects that make up the program, it was not practical with the time available for the committee to do an assessment using the recommended methodology. Therefore, based on its own experience with similar programs and the obvious success of a number of these programs, the committee made the judgment that a cost/benefit ratio of about 12 was appropriate and assigned a benefit of $1 billion.

Environmental Benefits

The advanced drilling and completion technology provides significant environmental benefits such as smaller footprints, reduced noise, lower toxicity of discharges, reduced fuel use, and better protection of sensitive environments (Table F-24).

Security Benefits, Options Benefits, and Knowledge Benefits

Since these programs are all directed at increasing the production of oil and gas in the United States, they directly contribute to national security. In addition to the projects already commercialized, there are many still in the pipeline that could provide significant future economic benefits (options). Moreover, a substantial number of the projects in this program added to the knowledge base.

Lessons Learned

The oil service industry, which is the primary user of technology developed in this program, is dominated by a large number of small and medium-size firms. Many of these firms have limited R&D budgets. Also, in the oil industry, technology disperses quickly, making it difficult to capitalize on R&D investments. Therefore, high-risk research is either avoided or done by consortia. The government can play an effective role with a relatively small investment in high-risk projects to stimulate advances in technology that can have a large positive impact on the industry and benefit the nation. The key to an effective program is interaction with and feedback from the industry.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

TABLE F-24 Benefits Matrix for the Drilling, Completion, and Stimulation Programa

 

Realized Benefits/Costs

Options Benefits/Costs

Knowledge Benefits/Costs

Economic benefits/costs

DOE R&D costs: $79 millionb

Industry costs: $32 million (29 percent cost share)c

Substantial realized economic benefits of approximately $1 billiond

In addition to the projects already completed, there are many still in the pipeline that will provide significant future economic benefitse

Makes technologies immediately available to the entire industry, including small and medium-size firms that have limited R&D budgets

Allows drilling for deeper and/or unconventional gas

Potential to enhance the net value of gas resources

Permits accelerated and incremental production

R&D on the use of titanium pipe in extended-reach drilling, expandable metal packers, matrix and fracture acidizing, in situ rock stress measurements, geomechanics of sand control, geomechanics of horizontal completions, polycrystalline compact diamond drill bit technology, underbalanced drilling technology, mud pulse telemetry, high-temperature measurements while drilling, and other areasf

Environmental benefits/costs

Smaller footprints, enhanced well control, protection of sensitive environments, reduced noise, toxicity, and fuel use, and othersg

Requires fewer wells to be drilled and thus reduces volume of wastes produced

Allows drilling in environmentally sensitive areas

R&D on the utilization of drill cuttings for wetland restoration

R&D on slimhole technologies and underbalanced drillingh

Security benefits/costs

Increase in U.S. production of oil and gas

Potentially large increase in domestic U.S. oil and gas production and reserves

DOE involvement ensures the technology is widely available to increase oil and gas production and reserves

aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000.

bConsists of $48 million for the oil programs and $31 million for the natural gas programs.

cIndustry cost share for the oil programs was 33 percent and for the natural gas programs was 21 percent.

dFE estimates that the economic benefits from programs initiated through 2005 total a projected $2221 million for the oil programs and $252 million for the gas programs. It is difficult to assess the total benefits because both programs consist of a myriad of small projects. Also, it is difficult to separate the contributions made by DOE and contributions made by industry and others. However, while it is likely that both of these figures overestimate the benefits attributable to only the FE R&D programs, it is nevertheless likely that the realized economic benefits are substantial and greatly exceed the total of the DOE and private industry R&D costs. Assuming a benefit to cost ratio of 12:1 based on industry expert opinion for this class of R&D, a benefit of $1 billion is assigned.

eThe drilling program prior to 1983 focused on the need to gain more efficiency from the limited number of drilling rigs available at that time. While the early program focused heavily on drilling technology, the post-1983 programs cover a broader range of completion and stimulation technologies.

fR&D in the oil programs area includes Drill System Development projects, such as the polycrystalline diamond compact drilling bit, pressure coring system mud pulse telemetry, electrodril, and microdrilling; Drill Fluids and Underbalance Drilling projects, such as air-, mist-, and foam-aerated drilling; Surface Operations projects, such as gas liquids cylindrical cyclone and fiber-optic sensors for downhole production monitoring; Completion projects, such as ceramic borehole sealants; and Stimulation projects, such as tiltmeter technology. R&D in the gas programs area includes Drilling System Efficiency, such as high-power slimhole drilling systems, high-temperature measurement while drilling/logging, and composite drill pipe; Underbalanced Drilling Systems, such as integrated directional drilling systems; New Concept Drilling systems, such as high-pressure coil tubing drilling systems and advanced mud-hammer drilling systems; Supporting Research in areas such as horizontal drilling, coil tubing, slimhole drilling, and underbalanced drilling; and Advanced Completion and Stimulation Systems, such as real-time downhole simulation monitoring and control systems and ultradeepwater completion systems.

gFE lists the environmental benefits of advanced drilling and completion technology as including smaller footprints; reduced noise and visual impacts; less-frequent well maintenance and workovers with less associated waste; reduced fuel use and associated emissions; enhanced well control for greater worker safety and protection of groundwater; less time on site, with fewer associated environmental impacts; lower toxicity of discharges; and better protection of sensitive environments.

hSlimhole technologies can significantly reduce the area and duration of land disturbance, and underbalanced drilling can reduce the volume of drilling fluids that require disposal, especially offshore.

DOWNSTREAM FUNDAMENTALS RESEARCH PROGRAM

Program Description and History

The Downstream Fundamentals Research program has a long and illustrious history. It was started as a research facility to measure the thermodynamic properties of petroleum in 1943 at the Bureau of Mines laboratory in Bartlesville, Oklahoma. In the early years this laboratory pioneered the development of new analytical techniques to separate hydrocarbons and to accurately measure their thermodynamic properties. Most of the research in downstream fundamentals for the period from 1978 to 1997 was

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

TABLE F-25 Summary of Environmental Benefits of Drilling Technology Advancesa

 

Fewer Wells

Smaller Footprint

Habitat Protection

Better Wellbore Control

Reduced Waste Volumes

Water Resources Protection

Reduced Fuel Consumption

Reduced Air Emissions

Enhanced Worker Safety

Coiled tubing

 

x

x

x

x

 

x

x

 

Horizontal drilling

x

 

x

 

x

 

MWD

x

 

x

x

 

x

Multilateral drilling

x

x

x

 

x

 

Slimhole drilling

 

x

x

x

x

 

Synthetic drilling fluids

 

x

x

x

x

x

x

x

PDC bits

 

x

 

x

x

x

aMWD, measurement while drilling; PDC, polycrystalline diamond compact (drill bits).

SOURCE: Office of Fossil Energy. 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.

conducted under the auspices of the National Institute for Petroleum Energy Research (NIPER) in Bartlesville. In 1997, the NIPER facility at Bartlesville was closed. Much of the equipment was moved to the Oak Ridge National Laboratory (ORNL), where work in this area continues.

The program can be characterized by three major subdivisions—Thermodynamic Data and Engineering Properties, Fuels Chemistry, and Process Fundamentals. The programs are designed to develop the fundamental thermodynamic data used by engineers to design chemical and refinery processes, to characterize crude oil feedstocks, and to develop techniques and data to improve processes and solve product quality problems.

The program underwent several major changes as a result of changing administrations, changing circumstances in the petroleum business, and changes in the type of fundamental information needed. From 1978 to 1983, the laboratory was run as a government research laboratory with essentially no cost sharing by private industry. During this period, heavy emphasis was on developing fundamental data on nonconventional fuels such as shale oil and tar sands. During the late 1980s, the first of two government efforts to privatize this facility occurred. At that time cooperation with industry expanded, DOE funding declined significantly, and there was a shift in program emphasis to near-term applications. In the 1990s DOE funding increased. The program was redirected from the characterization of synthetic fuels to the characterization of heavy petroleum. Significant increases in industry participation occurred.

Funding and Participation

Historically, industry participation in the fundamentals program was low. However, in the most recent programs, industry participation is significant (28 percent) (Table F-26).

Results
Thermodynamic Data and Process Engineering Properties

Since its founding in 1943, the program has been responsible for many significant advances. For example, the original rotating bomb calorimeter was designed in the Bartlesville laboratory. A major accomplishment was the determination of the thermodynamic properties of the sulfur compounds contained in U.S. light crude oil. The program also allowed the calculation of many chemical bond energies of interest to the military and civilian sectors.

Since 1978, the Thermodynamic Data and Process Engineering Properties program has focused on coal liquids, shale oil, oil from tar sands, and, most recently, heavy crude oil. The thermodynamic data developed under this program are needed to design processes to convert these materials to useful products, to calculate yields, and to develop process simulations.

Fuels Chemistry

The primary accomplishments in fuels chemistry is the development of unique analytical methods and separation

TABLE F-26 Funding for the Downstream Fundamentals Program (millions of 1999 dollars)

Program

DOE Expenditures

Industry Cost Share

Total

1978 to 1999

46

5 (10%)

51

2000

2.6

1 (28%)

3.6

Total

48.6

6 (11%)

54.6

 

SOURCE: Office of Fossil Energy. 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.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

techniques and their application to provide fundamental data on the changing slate of liquid fuels feedstocks. This includes, for example, characterization of light cycle oil, a refinery by-product blended into diesel fuel, to determine which compounds were causing fuel instability.

In addition, an extensive and unique analytical database containing the analysis of thousands of domestic and foreign crudes was developed and maintained on a Web site.

Process Fundamentals

Fundamental data related to processes for refining and petrochemical manufacture were developed. Projects included such processes as HF alkylation, catalytic cracking, coking, and desulfurization.

Benefits and Costs

The economic benefits of the work carried out under the Downstream Fundamentals program, which is a very fundamental in nature, are virtually impossible to estimate with any degree of confidence because the research is so far back in the chain from science to application (see Table F-27). Undoubtedly, over the years the results of this work have made a significant contribution to the well-being of the industry and the nation as a whole. That industry is funding a significant portion (39 percent) of the current program is an indication of the value that this program currently engenders.

Lessons Learned

All programs, even those as highly regarded as the early thermodynamic programs, must evolve over time to fit the changing needs of society and the changing modalities of interaction with industry. The Fundamentals program has changed: first, it was focused on light crude oil, then on synthetic fuels and now, on heavy crude oil. At the same time the nature of the program has evolved: From being essentially an academic program, it has become a program highly leveraged in partnership with industry.

EASTERN GAS SHALES PROGRAM

Program Description and History

Naturally fractured shales containing natural gas within fractures have long been known in the Appalachian, Illinois,

TABLE F-27 Benefits Matrix for the Downstream Fundamentals Programa

 

Realized Benefits/Costs

Options Benefits/Costs

Knowledge Benefits/Costs

Economic benefits/costs

DOE R&D costs: $49 million

Industry costs: $6 millionb

Significant value, but so far back in the scientific chain that it is hard to quantifyc

None

Analytical techniques and thermodynamic data for petroleum, coal liquids, shale oil, and tar sands

Development of fundamental thermodynamic data used to design and operate refining and petrochemical processesd

Research on process fundamentals and on fuels chemistrye

Development of an extensive and unique database containing the analysis of thousands of domestic and foreign crudes

Environmental benefits/costs

None

None

None

Security benefits/costs

None

None

None

aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000.

bFor most of the period 1978–2000, industry’s cost share was zero or very small; however, since 1995 it has been about 50 percent.

cThe primary accomplishment in fuels chemistry is the development of unique analytical methods and separation techniques and their application to provide fundamental data on the changing slate of liquid fuel feedstocks—for example, characterization of light cycle oil, a refinery by-product blended into diesel fuel, to determine which compounds were causing fuel instability.

dThe program has been focused on coal liquids, shale oil, oil from tar sands and, most recently, heavy crude oil. The thermodynamic data developed under this program are needed to design processes to convert these materials into useful products, calculate yields, and develop process simulations. It is this data set that underlies the design and operation of petroleum refineries and petrochemical plants.

eProjects included such processes as HF alkylation, catalytic cracking, coking, and desulfurization.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

and Michigan basins. In fact, they have been a minor source of natural gas since the early part of the 19th century and have been produced commercially since the 1920s. The gas reservoirs are shallow and easily accessible, but yields are low and a large number of wells must be drilled. Historically, the shales have been the site of a significant number of U.S. gas wells, although their contribution to U.S. production is minor.

During the mid-1970s, at the time of widely perceived and actual shortages of natural gas, production from the Eastern gas shales amounted to only about 70 Bcf yearly. Drilling and completion practice was low cost but technically simple and ineffective.

The Eastern Gas Shales program was initiated in 1976 by the ERDA, assumed by DOE in 1978, and continued until 1992. It was designed to assess the resource base, in terms of volume, distribution, and character, and to introduce more sophisticated logging and completion technology to an industry made up mostly of small, independent producers. The goal was to substantially increase production from these basins at a time when increased national supply was critically important.

Funding and Participation

DOE expenditures from 1978 through termination of the program in 1992 amounted to $137 million (1999 dollars), with about two-thirds of the total having been expended between 1978 and 1982 (OFE, 2000o). Prior to DOE assumption of the program, ERDA had expended in excess of $20 million and the GRI had invested about $30 million in Eastern gas shale R&D. The DOE and GRI effort was well coordinated, with DOE focusing on basic research and assessment and GRI concentrating on applications.

Results

The DOE program was responsible for bringing together and integrating a significant amount of scattered data on the Eastern gas shales critical to a solid assessment of the resource base. Such an assessment was, as is always the case, necessary for the optimum deployment of technology. DOE sponsored work in core and fractigraphic analysis, as well as electrical downhole well logging, all aimed at understanding the density and distribution of natural fracture networks. Results of these studies aided in the development and deployment of foam fracture technology and, especially, the optimum deployment of massive hydraulic fracturing. Directional wells had been drilled in the shale reservoirs prior to the Eastern Gas Shales program, but the better understanding of the distribution of natural and induced fractures provided by the program permitted maximum intersection of horizontal and directional wells with fracture zones, increasing yield per well drilled.

Increases in production from the Eastern gas shales since the 1970s have been significant. By 1998, 6 years after the program was terminated, annual gas production had reached 380 Bcf, up from 200 Bcf in 1992 and 70 Bcf in 1978. Proved reserves were nearly 5 Tcf, with another 2 Tcf having been produced in the 6 years from 1993 to 1998. By 2010, annual gas production from shale formations, including the Fort Worth Basin as well as the Eastern basins, is projected to reach 800 Bcf and, by 2020, approach 1 Tcf.

The increased gas production, proved reserves, and pace of drilling in gas shales reflect the contribution of industry and GRI (especially in the Michigan Basin), but the strong presence of the DOE program seems particularly significant to the increased production that is taking place.

Benefits and Costs

While the knowledge benefits of the program are substantial, especially in advancing ability to detect and predict fracture density and distribution—important in many hydrocarbon reservoirs other than shales—the direct benefits come from the increased production from the shale formations (Table F-28). These benefits were quantified by estimating the volumes of incremental shale gas production DOE attributes to the program. Consideration must be given to production that would have occurred in the absence of the program, production induced by the existence of Section 29 tax credits under the Natural Gas Policy Act, and production resulting from the R&D activities of GRI.

The DOE program is credited with 50 percent of the incremental shale gas production from the Appalachian Basin (over industry’s baseline) and 10 percent of the incremental gas production in the Michigan and Fort Worth basins. This amounts to 92 Bcf of additional gas production in 2000 and 1743 Bcf cumulative additional gas production from 1978 to 2005. The benefits analysis set net revenues at 17.5 percent of sales revenues, giving an increased net revenue to industry of $705 million (1999 dollars). With a program expenditure of $148 million, the calculated benefit to cost ratio is 4.8 to 1. In addition, DOE calculates $33 million (1999 dollars) from royalties on federal lands and from increased state severance taxes due to the displacement of imports and over $8 billion in consumer savings due to lower gas prices.

Lessons Learned

Although the in-place shale gas resource base in the United States is large, it is marginal and produced in relatively small increments. At the time ERDA, and later DOE, began the program in the Eastern gas shales, the conventional wisdom was that any significant expansion of production would require relatively high gas prices and that technology in these formations could do little to substitute for high prices. But incentives through tax credits, combined with optimum deployment of advanced technology, served to revive a domestic gas province in decline. This combina-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

TABLE F-28 Benefits Matrix for the Eastern Gas Shales Program (EGSP)a

 

Realized Benefits/Costs

Options Benefits/Costs

Knowledge Benefits/Costs

Economic benefits/costs

DOE R&D costs: $137 millionb

Private industry R&D costs: $35 millionc

50 additional Bcf of natural gas being produced annually, 1260 additional Bcf of natural gas supplies produced, and 3200 additional wells drilled

About $600 million in economic benefitsd

Offers potential for expanded shale gas production if natural gas prices risee

Discovery of Bass Island Trend

Development of coring and fractigraphic analysisf

Development of foam fracture technology, downhole video camera, and massive hydraulic fracturing stimulation

Increased ability to detect and predict fracture density and distributiong

Assessment of the resource baseh

Development of methods for geologic integration of well logs, core data, geophysical survey results, and remote sensing interpretations; production of maps and cross sections; bibliography of Devonian shale technologies; distribution of core samples and well logs; and development of methods of integrating technological data

Environmental benefits/costs

More environmentally benign method of drilling shale wells

Decreased environmental impact of expanded shale gas production

None

Security benefits/costs

None

None

None

aUnless otherwise noted, all dollar estimates are given in constant 1999 dollars through 2000.

bIn addition to the FE R&D expenditures, EGSP benefited from substantial federal tax incentives under the Section 29 program and other legislation, which involved substantial revenue losses to the federal government. In addition, substantial EGSP R&D was conducted by the Department of the Interior, ERDA, and NASA, and these expenditures are not included here.

cPrimarily the GRI EGSP R&D program. Estimates of R&D by individual private companies are not available.

dThe direct benefits come from the increased production from the shale formations and were derived from the estimated volumes of incremental shale gas production DOE credits to the program. Consideration must be given to production that would have occurred in the absence of the program, production induced by the existence of Section 29 tax credits under the Natural Gas Policy Act, and production resulting from the R&D activities of GRI. The DOE program is credited with 50 percent of the incremental shale gas production from the Appalachian Basin (over industry’s baseline) and 10 percent of the incremental gas production in the Michigan and Fort Worth basins. This amounts to 92 Bcf of additional gas production in 2000 and 1743 Bcf cumulative additional gas production from 1978 to 2005. The benefits analysis set net revenues at 17.5 percent of sales revenues, giving an increased net revenue to industry of $705 million. In addition, DOE calculates $33 million from royalties on federal lands and from increased state severance taxes. Thus, $600 million is a relatively realistic estimate that takes into account the influence of the Section 29 tax credits and private industry R&D.

eFE estimates this at natural gas prices exceeding $4.00 per Mcf.

fDOE sponsored work in core and fractigraphic analysis, as well as electrical downhole well logging, aimed at understanding the density and distribution of natural fracture networks. Results of these studies aided in the development and deployment of foam fracture technology and especially the optimum deployment of massive hydraulic fracturing. Directional wells had been drilled in the shale reservoirs prior to EGSP, but the better understanding of the distribution of natural and induced fractures provided by the program permitted maximum intersection of horizontal and directional wells with fracture zones, increasing yield per well drilled.

gThis is important in many hydrocarbon reservoirs other than shales.

hThe DOE program was responsible for collecting and integrating a significant amount of scattered data on the Eastern gas shales critical to a solid assessment of the resource base. Such assessment is, as always, necessary for the optimum deployment of technology.

tion has allowed production to expand long after termination of both the R&D program and tax credit incentives and to do so in a period of relatively low—much lower than had earlier been projected—gas prices. In a significant way, technology can and does substitute for price in marginal resources, and the Eastern Gas Shales program proved that critical point.

ENHANCED OIL RECOVERY

Program Description and History

Conventional methods of oil recovery, including primary and secondary recovery, achieve, on the average, about 35 percent recovery of the original oil in place, less if the oil is heavy or viscous. The volume of oil remaining in already-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

discovered reservoirs in the United States is on the order of 340 billion barrels. Conventional wisdom in the 1970s held that additional recovery would involve a physical or chemical change in the reservoir or its contained fluids to move oil that was immobile.

Common enhanced recovery methods include chemical methods (use of surfactants, alkaline-enhanced chemicals, and polymers and gels); gas flooding methods, generally using CO2 and enriched natural gas (to develop miscibility) and flue gas and nitrogen (generally to maintain reservoir pressure); microbial enhanced oil recovery, where the action of microbes ferments hydrocarbons and produces a by-product that is useful in oil recovery; and thermal methods to reduce the viscosity of heavy oils, most commonly by injecting steam (steam flooding) or by the introduction of heat in the reservoir by burning part of the oil in a reservoir (in situ combustion).

Initial work by DOE in enhanced oil recovery was a part of field demonstration projects started by the U.S. Bureau of Mines in 1974 and taken over by DOE in 1978. Twelve of the field projects involved chemical floods, five involved carbon dioxide injection, and six were thermal/heavy oil projects. These projects were initiated after the Arab oil embargo and were conducted at a time when imports were increasing and stated national policy was to increase domestic production. Applying advanced technology to the large base of unrecovered oil in existing domestic reservoirs was an obvious strategy to enlarge domestic production. The strategy was embraced by both industry and government, as the program was cost shared.

With the exception of steam flooding, the early demonstration of enhanced oil recovery (EOR) techniques was largely uneconomic, with some, but not significant, incremental oil recovery. The most significant information coming from these early experiments with EOR was the knowledge that the geological and engineering parameters of individual fields were insufficiently known. Most reservoirs were much more geologically complex than then judged.

The DOE Enhanced Oil Recovery program was significantly redirected in FY 1979. The programs that had been basically oriented to commercialization were to be phased out and funding for the EOR demonstrations went to zero in FY 1989. Since then, the program has focused on research, although some small-scale pilot projects have been conducted and some assistance is provided to independent operators. The program is designed to involve academia, government research organizations, and industry with programs in chemical methods, gas flooding, microbial methods, heavy oil recovery, novel methods, and reservoir simulation.

Funding and Participation

The EOR demonstration programs managed by DOE from FY 1978 through FY 1989 expended of approximately $110 million, with industry cost sharing amounting to about $200 million. These are carried by DOE under its field demonstration program.

Under the multitiered pricing of oil in the late 1970s and early 1980s, oil recovered with EOR techniques qualified for an incentive price. This proved difficult to administer and led to significant legal disputes between industry and government. It is judged not to have been a major factor in calculations of DOE costs and benefits.

From 1978 through 2000, DOE funded approximately 230 projects (exclusive of the early EOR field demonstrations) in thermal, gas, chemical, and microbial EOR and sponsored the development of reservoir simulators, screening models, and databases. A total of $177.2 million (1999 dollars) has been expended, with an additional $47 million in cost sharing, for a DOE share of 79 percent (see Table F-29). Approximately equal amounts, about 25 percent each, were expended in support of programs in thermal, gas, and chemical methods; about 10 percent of the total was expended each for microbial methods and simulation work; and about 4 percent supported so-called novel methods (downhole electric heating, microwave heating, seismic wave stimulation, and wettability reversal) (OFE, 2000p).

Results

A principal accomplishment of the program in the early stages was the recognition of the critical importance of reservoir characterization in the deployment of EOR strategies. Notable R&D accomplishments include advancements in the understanding and control of CO2-based EOR, especially development of chemicals and foams for mobility control; fundamental research on the miscibility of multicomponent systems; new technologies for thermal-based EOR; and introduction of microbial EOR.

Benefits and Costs

DOE estimates its EOR program and technologies have stimulated production of some 167 million barrels of oil equivalent more than would have been produced with industry acting alone. It credits its program with 2.8 percent of annual domestic EOR production. A net revenue value of 17.5 percent of sales revenues, equal to $3.50/bbl when domestic price is $20/bbl, was used to convert incremental production to benefits.

From 1978 through 2000, the DOE EOR program spent $177 million (1999 dollars) and attracted $47 million of cost share. In return for this investment, the program has provided $625 million (1999 dollars) in cost savings to oil producers, with a benefit/cost ratio of 3.5 to 1 (or 2.8 to 1, including the cost-shared portion of the expenditure). Including incremental federal estate revenues gives a total of about $700 million (Table F-29). Benefits will likely accrue in future years from the application of DOE-sponsored EOR research. Environmental benefits may accrue from the adap-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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. Fuels to Drive Our Future. Washington, D.C.: National Academy Press.


Office of Fossil Energy (OFE), Department of Energy. 2000a. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Fluidized Bed Combustion (FBC) Technology Area, December 11.

OFE. 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.

OFE. 2000c. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Indirect Coal Liquefaction Program, December 4.

OFE. 2000d. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: IGCC Technology Area, December 20.

OFE. 2000e. OFE Letter response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Flue Gas Desulfurization Program, December 4.

OFE. 2000f. 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. OFE Letter Response to questions from the Committee on Benefits of DOE R&D in Energy Efficiency and Fossil Energy: Coal Preparation Program. January 25.

OFE. 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.

OFE. 2001c. OFE Letter response to questions from the Committee on Ben-

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×

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.

Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 162
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 163
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 164
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 165
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 166
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 167
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 168
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 169
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 170
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 171
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 172
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 173
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 174
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 175
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 176
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 177
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 178
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 179
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 180
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 181
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 182
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 183
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 184
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 185
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 186
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 187
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 188
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 189
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 190
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 191
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 192
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 193
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 194
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 195
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 196
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 197
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 198
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 199
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 200
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 201
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 202
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 203
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 204
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 205
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 206
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 207
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 208
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 209
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 210
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 211
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 212
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 213
Suggested Citation:"Appendix F: Case Studies for the Fossil Energy Program." National Research Council. 2001. Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000. Washington, DC: The National Academies Press. doi: 10.17226/10165.
×
Page 214
Next: Appendix G: Glossary »
Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000 Get This Book
×
Buy Paperback | $61.00 Buy Ebook | $48.99
MyNAP members save 10% online.
Login or Register to save!
Download Free PDF

In legislation appropriating funds for DOE's fiscal year (FY) 2000 energy R&D budget, the House Interior Appropriations Subcommittee directed an evaluation of the benefits that have accrued to the nation from the R&D conducted since 1978 in DOE's energy efficiency and fossil energy programs. In response to the congressional charge, the National Research Council formed the Committee on Benefits of DOE R&D on Energy Efficiency and Fossil Energy.

From its inception, DOE's energy R&D program has been the subject of many outside evaluations. The present evaluation asks whether the benefits of the program have justified the considerable expenditure of public funds since DOE's formation in 1977, and, unlike earlier evaluations, it takes a comprehensive look at the actual outcomes of DOE's research over two decades.

  1. ×

    Welcome to OpenBook!

    You're looking at OpenBook, NAP.edu's online reading room since 1999. Based on feedback from you, our users, we've made some improvements that make it easier than ever to read thousands of publications on our website.

    Do you want to take a quick tour of the OpenBook's features?

    No Thanks Take a Tour »
  2. ×

    Show this book's table of contents, where you can jump to any chapter by name.

    « Back Next »
  3. ×

    ...or use these buttons to go back to the previous chapter or skip to the next one.

    « Back Next »
  4. ×

    Jump up to the previous page or down to the next one. Also, you can type in a page number and press Enter to go directly to that page in the book.

    « Back Next »
  5. ×

    Switch between the Original Pages, where you can read the report as it appeared in print, and Text Pages for the web version, where you can highlight and search the text.

    « Back Next »
  6. ×

    To search the entire text of this book, type in your search term here and press Enter.

    « Back Next »
  7. ×

    Share a link to this book page on your preferred social network or via email.

    « Back Next »
  8. ×

    View our suggested citation for this chapter.

    « Back Next »
  9. ×

    Ready to take your reading offline? Click here to buy this book in print or download it as a free PDF, if available.

    « Back Next »
Stay Connected!