G. Warfield Hobbs
Ammonite Resources Co.
New Canaan, Conn.
The first part of this article discussed demographic and consumption trends in energy resource utilization, and the second part reviewed developments in conventional petroleum, uranium, and tar sands.
In this third and final section, oil shale, coalbed methane, and geothermal resources with be covered together with energy fuel reserve life and the study's conclusions regarding the future of energy minerals.
More resource trends and conclusions
Oil shale
Oil shale is an energy mineral that of late has disappeared from the pages of many leading energy journals. It should not be omitted in this article because bituminous shales contain trillions of barrels of kerogen that have significant future potential as feedstock for synthetic petroleum.
Several commercial scale pilot projects have demonstrated the technical feasibility of producing petroleum, including jet fuel, from oil shale in the U.S. However, all shale oil projects have been abandoned in the U.S. as continued development was simply not economic.
A commercial oil shale operation in Estonia mines 20 million metric tons/year of oil shale. Countries like Israel and Jordan, with no significant oil production, have long considered developing their substantial oil shale deposits.
Brazil has significant oil shale resources and an- nounced plans in 1992 to construct a 3,500 b/d research project. The Chinese are constructing a 2,400 b/d plant in the Fushun area of Northeast China (OGJ, Apr. 17, News- letter).
Currently the most ambitious oil shale development proposal is that of two Australian companies, Southern Pacific Petroleum NL and its sister company Central Pacific Petroleum NL, which plan to develop a Tertiary age oil shale deposit in eastern Queensland.
The proposed Stuart oil shale project will consist initially of a 6,000 ton/day commercial demonstration facility capable of producing 4,500 b/d of hydrotreated naphtha and low sulfur fuel oil. This will be followed by a staged development that will ultimately produce 84,000 b/d of oil products, including gasoline, from an in-situ resource of 3.05 billion bbl.
After extensive bench and pilot testing of different technologies, the Canadian Aostra Taciuk process, originally developed for Alberta tar sands, was found to be most suitable for the East Queensland shales. Southern Pacific Petroleum estimates that the capital investment for full development of the Stuart Oil Shale Project will be (U.S.) $1.65 billion in 1993 dollars, and that the average production cost, occasioned by the economies of scale of the final development stage, will be $6.50/bbl. Permitting and project financing are in progress.
Esso Australia Resources Ltd., the operator of the 2.65 billion bbl Rundle oil shale project, also in East Queensland, filed a mineral development license in February 1995.
At current world oil prices and alternate fuel availability, the cost of oil shale development is not competitive with conventional fuels unless there are unique natural and local market circumstances, as in eastern Australia. Improvements in mining, processing, and upgrading oil shale hydrocarbon extracts to commercial grade petroleum products will occur over the next decade.
The success of one or two commercial scale projects such as those planned in Australia and China will lead to rapid development of other shale oil facilities, in a manner similar to the growing interest in Canadian and Venezuelan tar sands.
Coalbed methane
Over the past decade a significant new energy resource has been developed by the commercialization of methane production from coal seams. Technological advances in hydraulic fracturing, and the incentives provided by a very generous tax credit for unconventional gas production, are responsible for the successful commercialization of coal seam gas in the U.S.
U.S. Coalbed methane production and utilization has risen from essentially zero prior to 1978 to 732 bcf in 1993 (Fig. 12 (10922 bytes)). Now more than 5,700 wells are producing coalbed methane. Commercial production rates per well range from only 100-150 Mcfd on average in the central Appalachian basin in Virginia to over 10 MMcfd from the best wells in the San Juan basin in New Mexico and Colorado.
Coalbed methane production has risen from a fraction of 1% to about 3.6% of total U.S. gas production the past five years. This is a phenomenal rate of growth. Proved reserves in the U.S. have doubled over the past 5 years to more than 10 tcf. This rate will not continue, however, as expiration of the Sec. 29 tax credit on Dec. 31, 1992, for newly drilled wells marked the end of the U.S. coalbed methane boom.
High volume wells such as those in the San Juan basin, and low volume wells that produce little water, such as those in the central Appalachian region of Virginia, are economic without the tax credit. Wells in areas like the Black Warrior basin in Alabama, which produce high volumes of water and relatively low volumes of gas, are uneconomic to only marginally economic without the Sec. 29 Tax Credit in a low gas price environment. The value of the Sec. 29 tax credit in 1995 will be about $1.06/Mcf.
Drilling and completion of coalbed methane wells will continue in the U.S. in those areas where production has proven to be economic without the tax credit. Activity continues in the San Juan basin. An ambitious drilling program of 1,000 wells is planned by River Gas Corp. in Utah, where per well average production appears to be in excess of 300 Mcfd. Equitable Resources Energy Co. continues to drill new coalbed methane wells in Virginia. The Raton basin in Colorado may be developed.
The identified "in place" resource in the U.S. exceeds 400 tcf. However, because of the low permeability of most coals and higher operating costs compared with conventional gas wells, a significant increase in domestic coalbed methane activity will require further improvement in completion technologies, higher gas prices, and perhaps a new tax credit.
Canada. The potential coalbed methane resource of Cretaceous coals of the Western Canadian sedimentary basin exceeds that of the U.S.
Researchers at the Alberta Geological Survey (D. Nikols et al.) estimated in 1991 that potential coal gas in place in Alberta alone was on the order of an incredible 2,000-3,000 tcf, compared with 400 tcf in the U.S. If only 5% of this gas were recovered, the volume would amount to 100-150 tcf!
As Western Canada is awash with inexpensive conventional gas, Canadian operators have little incentive to pursue coalbed methane in the near term. The coalbed methane resources of Alberta, may however, provide an economic and environmentally more attractive alternative to costly development of gas in the Canadian Arctic over the next 25 years.
International. Many opportunities exist for coalbed methane production outside North America. This is particularly true in the coal producing regions of Central and Eastern Europe, India, and China, where there is no natural gas infrastructure and where the burning of coal for power generation has caused serious pollution problems.
Commercialization of coal seam gas in advance of deep underground mining, and from vertical boreholes in areas not being mined, has substantial economic, environmental, and strategic benefits. These factors will propel coalbed methane activity in the major coal basins of Poland, the Czech Republic, Ukraine, and China. In the coal basins of the U.K., France, Germany, and Australia, relatively high gas prices are stimulating active coalbed methane exploration and development by both major oil companies and large and small independents. Enron and Amoco are among the larger companies pursuing international coalbed methane opportunities.
Geothermal
Geothermal steam is an environmentally friendly energy mineral resource for electric power generation and district heating, which has huge current and unlimited future potential.
Over the past 15 years worldwide geothermal generating capacity has risen 230% to a current 8,968 mw from 3,888 mw in 1980 (Table 9 (5753 bytes)). About one third of this capacity is in the U.S., chiefly in California and Nevada. Other countries with commercial geothermal energy projects include: Mexico, El Salvador, Iceland, France, Italy, Japan, Philippines, Indonesia, and New Zealand.
The Geysers electric power geothermal field in California is well known. Two non-U.S. examples where geothermal energy is being used commercially for district heating, thereby providing substantial savings in fossil fuel costs and reducing "green house" gas emissions, are in Iceland and France.
Geothermal hot water is piped 25 miles to the city of Reykjavik, Iceland, where it provides district heating for the capital city's 145,000 inhabitants. Near Paris, France, 13,000 apartments are heated by 60-80 C. hot water from nearby wells 1,500-2,000 m deep.
Geothermal resources are divided into four categories: 1) hydrothermal; 2) geopressured geothermal; 3) hot dry rock; and 4) magma. All commercial projects are presently based on hydrothermal, where wells are typically 1,800-2,450 m deep and have reservoir temperatures of 180-270 C.
A pilot project at Fenton Hill, N.M., managed by Los Alamos National Laboratory has been in operation since 1977 to test the commercial feasibility of hot dry rock geothermal energy. At Fenton Hill, water is pumped down 12,000 ft (3,658 m) wells into an artificially fractured dry hot rock reservoir where the temperature is 460 F. (238 C.). The water turns to superheated steam and is then produced up a production well and through an electric generating turbine.
The pilot project operates at high efficiency and demonstrates that hot dry rock geothermal energy is technically feasible. Los Alamos geothermal researchers have concluded that "hot dry rock energy potential at accessible drill- ing depths could meet all the nation's energy needs for more than 5,000 years."
Volcanically active re- gions where magma occurs at accessible drill depths also provide significant geothermal potential. However, as a practical matter, we do not yet have the technology to handle the 650-1,300 C. working environment of magma.
At $1.5-3.6 million/mw-hr of productive capacity, geothermal energy requires slightly more capital per megawatt to develop than conventional fossil fuel power plants (Table 4). Operating costs are higher than coal and nuclear plants but less than natural gas and oil fired electric power facilities. Improving technologies and higher fossil fuel costs in the future will make geothermal very competitive in markets where geothermal resources are present.
Geothermal power generation in the U.S. was about 2,700 mw in 1992, representing only 0.4% of total domestic electric generating capacity of 695,900 mw. A study by Sandia Laboratories projects potential capacity of 23,000 mw at 6/kw-hr or 44,000 mw at 12.5/kw-hr by 2030. The U.S. Geological Survey estimated a potential capacity of 150,000 mw from indentified and undiscovered geo- thermal resources in the U.S.
The major impediment to new U.S. geothermal development is that opportunities for new electric power generating capacity are limited. Further, and perhaps more importantly, public utilities are not going to abandon the hundreds of billions of dollars of installed conventional capacity in the forseeable future in favor of new investment in geothermal power.
Internationally, there is more opportunity for geo- thermal resources to meet surging demand for electric power. This point is proven by major new geothermal power contracts in the amount of 1,200 mw in Indonesia and 1,000 mw in the Philippines.
Geothermal energy is a resource that has tremendous potential in a world hungry for new electric generating capacity, interested in low cost district heating in the cooler latitudes, and concerned about the reduction of green house gas emissions.
Resource life
The world is not about to run out of primary energy fuels (Table 10 (5355 bytes)).
On the basis of known proved reserves obtainable by current technologies, and at current consumption rates, the world has 45 years of remaining crude oil, 66 years of natural gas, 229 years of coal, 27 years of uranium, and over 1,000 years of tar sand/bitumens. Geothermal is unlimited as are hydro, wind, and solar power.
Technological and geopolitical developments have, and will continue to extend access to and the supply of conventional petroleum. The price of oil has not increased in real terms adjusted for inflation, yet supply continues to increase. Technology is driving supply by reducing exploration risk and cost, increasing field recoveries, and improving consumption efficiencies.
Technology and operating efficiencies more than commodity price will extend the reserve life of all energy resources. As with any natural resource commodity, improvements in extraction and processing technologies that result in lower production costs, also significantly increase economic reserves in two ways. First by making it possible to improve recovery factors from developed deposits, and secondly, to make lower grade deposits that would not otherwise be developed economic.
Proven conventional oil reserves will be depleted more quickly than the energy minerals. The cost of replacing those reserves, particularly in increasingly remote, deepwater, and harsh environments, will exceed the cost of energy mineral alternatives. This is already happening as was previously demonstrated in comparing the development costs per barrel for a large Alberta tar sand project with a major offshore development such as Hibernia field or a similar project off Europe.
Tar sands and eventually oil shales will ultimately provide as much oil on a daily basis, if not more, as is produced from conventional petroleum deposits. The volume of natural gas that may some day be obtained from coal seams is astronomical. Coal is abundant. Uranium could and should play an important role in satisfying future electric energy de- mand. Geothermal energy is unlimited.
There will be no shortages of primary energy fuels in the next century.
Factors that affect energy mineral exploration, development, and consumption inclConclusionude: supply and demand in world commodity markets; the state of the world economy; resource market competition; the size of the resource; technology development; government fiscal policy and environmental regulations; lease terms; and finally, and most importantly, company mindset and budgets.
Surging demand for energy resources, even at times of economic recession, and a vast supply of energy minerals are certain. Governments are providing access to energy mineral resources and are legislating favorable fiscal terms. Technology has made energy minerals cost competitive with conventional petroleum resources. Energy minerals can be extracted and consumed with minimal environmental impact.
The only remaining obstacle to major new development of energy mineral resources is corporate and public mindset. Education of management and the public as to the potential of energy minerals and their economic benefits will do much to further future exploitation of coal, uranium, tar sands, oil shale, coalbed methane, and geothermal resources.
From a strategic standpoint, long range planners must consider energy minerals as alternatives to North African, Middle Eastern, and Former Soviet Union crude oil and natural gas, in the event that religious and political unrest in these regions leads to serious petroleum supply disruptions.
Near term energy mineral exploitation will be, and is being, affected by the fact that consumer demand for energy worldwide has finally reached a critical mass that is growing significantly faster than the rate of population growth and the economic growth of OECD countries.
Technological advances have made energy mineral fuels price competitive with conventional hydrocarbon resources at relatively low oil and gas prices.
Crude oil prices are not expected to increase significantly in current or real terms, with the exception of price spikes caused by actual or threatened disruption of Middle Eastern supply. Current conventional oil production is able to meet world demand. Development of the world's vast bitumen resources will be able to satisfy the incremental demand for oil that cannot be met by conventional sources. The hundreds of billions of barrels of synthetic crude that can potentially be produced economically from bitumens at current low oil prices, and future shale oil production, will restrain future oil price increases.
The future is bright for energy minerals, but that future has already arrived. This "new age" in energy minerals is making its entrance without the benefit of $30-40/bbl oil prices, thanks to technological advances and rising world energy demand. Energy minerals are poised to become increasingly more competitive and profitable as we enter the 21st century.
Acknowledgments
The author thanks the following organizations and persons for their assistance in preparing this series of articles: U.S. Energy Information Administration; American Association of Petroleum Geologists; Alberta Energy Resources Conservation Board; Alberta Chamber of Resources; Syncrude Canada Ltd.; Bitor America Ltd.; Geothermal Resources Council; Lorraine M.A. Goobie, PhD., Shell Canada Ltd.; Curt D. Steele and David Clark, The Uranium Exchange Institute; West Virginia Coal Association; Utility Data Institute; Nuclear Energy Institute; Carl J. Smith, West Virginia Geological Survey; Natural Gas Supply Information Center at the University of Alabama; S.A. Holditch & Associates; and the Utah Geological Survey.
Table 9
WORLD GEOTHERMAL ELECTRIC GENERATING CAPACITY
Year Capacity, mw1980 3,8881990 5,8281995 8,968U.S. capacity in 1992 was 2,738.5 mwSource: Huttrer 1990, Geo- thermal Resources CouncilTable 10KNOWN WORLD ENERGY RESOURCES Years remaining production atResource present rateCrude oil 45Natural gas 66Coal 229Uranium 27Tar sands 1,000+Hydro UnlimitedGeothermal Unlimited
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