G. Warfield Hobbs
Ammonite Resources Co. New Canaan, Conn.
The first part of this article presented a macro-economic and demographic overview of current and projected trends in energy consumption and comparative energy costs.
This part and the third part will address developments in each resource in more detail.
Resource trends
Crude oil
Crude oil provides 40% of the worlds energy requirements.
As of Jan. 1, 1995, worldwide proved reserves of oil were 999,760,837 bbl (OGJ, Dec. 16, 1994, p. 35).
What is most noticeable in Fig. 4 (27447 bytes) is that world oil production at 19-22 billion bbl/year has really not changed significantly the past 15 years. The ratio of known reserves to annual production has actually increased 50% to about 45 years from about 30 years.
The past five years however, reserves and the R/P ratio have not changed significantly. This graph clearly demonstrates that the petroleum industry has done an excellent job at finding new reserves and increasing recovery from developed oil fields. There is no shortage of conventional crude looming over the horizon.
OPEC controls 77% of the worlds petroleum reserves and 41% of the 1994 daily production of 60.4 million b/d. OPECs production of 24 million b/d supplies about 15% of total world energy consumption.
Oil is a commodity subject to rapid and unpredictable price gyrations. Collectively, OPEC is in disarray and appears to be losing its ability to control oil prices within a trading range of about $12-24/bbl. Oil traders on commodity exchanges such as the Nymex are winning the upper hand in day to day control of oil prices. Nevertheless, there is no question that individual OPEC producers can significantly affect daily oil prices.
An investment of over $100 billion will be required to raise OPEC production to 40 million b/d by 2000 in order for OPEC to maintain its share of world oil production. Where will this capital come from? Can it be raised? Is there an alternative to investment in OPEC countries?
Political instability and Moslem fundamentalism in North Africa and the Middle East are "wild cards" that can radically alter price and crude oil deliverability. A scenario such as a fundamentalist overthrow of the Algerian government could cut off vital gas supplies to southern Europe virtually overnight. Assassination of King Faud in Saudi Arabia by Moslem extremists could lead to a revolution in Saudi Arabia, followed by an Iranian invasion to "protect" Moslem holy shrines. These are real scenarios that could occur at any moment.
As the recent Persian Gulf war demonstrated, the major oil consuming nations will intervene militarily to protect oil supplies in the Middle East. Rising political unrest and Moslem fanaticism in North Africa and the Middle East should stimulate strategic planners to take a serious look at energy mineral fuels as a dependable, relatively stable priced, long term option as an alternate to Middle Eastern oil.
The Former Soviet Union has huge conventional re- sources that could provide an alternative to North African and Middle Eastern crude oil and natural gas. Yet there are significant economic and political risks involved with large petroleum development projects in the FSU as well.
Natural gas
Natural gas currently provides nearly 22% of world energy consumption. Production of natural gas has increased 35% during the past decade to a total of more than 76 tcf/year (Fig. 5)(17148 bytes).
Natural gas is one of the fastest growing primary energy fuels. Worldwide reserves were 4,980 tcf as of Jan. 1, 1995 with approximately 40% controlled by OPEC. Natural gas will be in abundant supply for generations.
Coal
Coal currently provides 26% of the worlds primary energy requirements.
Worldwide coal consumption increased between 1983 and 1992 to 5 billion tons from 4.3 billion tons (Fig. 6)(19842 bytes). This is an increase of only 14.8%, less than the 22% overall growth in energy consumption during the same period. As coal is primarily used for electric power generation it cannot be expected to track total energy increases.
The important message for coal producers is that coal is projected to maintain its approximate one-quarter share of world energy markets through 2010.
Coal consumption continues to increase in the U.S. at twice the rate worldwide despite environmental pressure to reduce coal use. U.S. consumption has risen to 928 million tons from 707 million tons in the decade between 1982 and 1993, an increase of 31% (Fig. 7)(22997 bytes).
Nominal prices for coal have declined over the past decade. This decline is even more pronounced when adjusted for inflation. The decline in the price per ton of coal has required coal producers to implement significant reduction in operating costs through improved mining efficiencies, reduction of the labor force, mine consolidation, and improved mine to market transportation efficiencies.
Coal will continue to maintain its 55% market share as the leading electric power fuel in the U.S. Abundant domestic supply, relatively stable commodity price, improved mine productivity and operating efficiencies, together with new boiler combustion and emission control technologies will assure strong markets.
A relatively simple "technological" improvement for the coal industry would be the installation of mine to market coal slurry pipelines. This could significantly reduce transportation costs and increase coal to hydrocarbon competition. Pipeline and railroad lobbies have effectively killed the potential for coal slurry pipelines in the U.S.
However, the importance of this mode of inexpensive transportation in a country rich in coal and deficient in hydrocarbons and rail transportation is demonstrated by the recent contract for a 500 mile coal slurry pipeline in China.
For coal, the challenge will not be so much in finding new reserves but in maximizing extraction efficiencies and coal quality, mine reclamation, transporting coal cost-effectively, and improving combustion and pollution control technologies. Coal will continue to be a major factor in international energy supply for generations.
Uranium
Uranium is abundant and widely distributed, and at 5/MMBTU is the least expensive of all non-renewable energy fuels (Table 3).
Unfortunately, anything radioactive has a serious "image" problem. Nuclear power can be produced safely and economically, and nuclear waste can be disposed of safely. However, public perception, reinforced by the Three Mile Island and Chernobyl incidents, has severely limited the potential for nuclear power. Be that as it may, uranium supplies about 6% of total world energy. In Western Europe, 43% of the electricity generated is currently from nuclear facilities, with France having the highest percent at 77%, according to the U.S. EIA.
World nuclear power has grown since 1973 to just over 2,000 billion kw-hr from 191 billion kw-hr (Fig. 8)(20673 bytes). This is a tenfold increase in two decades. As of Dec. 31, 1993, EIA figures show there were 430 nuclear reactors operating worldwide in 30 countries, and 94 reactors were under construction.
Nuclear power is not expected to increase significantly in the next two decades due to limited current construction and plans for new capacity and retirement of existing reactors.
There was a uranium boom in the late 1970s as companies scrambled to produce fuel for the expected demand from nuclear plants planned and under construction. When the expected capacity failed to materialize, an oversupply of uranium developed and spot prices declined from a peak of $43/lb U3O8 in 1978 to a low of $7.12 in 1993 (Fig. 9)(23880 bytes).
The EIA estimate of world uranium reserves able to be produced at a cost of less than $30/lb is 3.99 billion lb. At a cost of $50/lb the figure is 5.75 billion lb. The figures for the U.S. are 292 million lb at $30/lb and 952 million lb at $50/lb, exclusive of uranium recovered from phosphates. At current world consumption of approximately 145 million lb/year of uranium, known in-ground uranium reserve life ranges from 27-40 years depending on the price.
U.S. uranium production has dropped to a low of 3.1 million lb of U3O8 in 1993, less than 10% of its peak of 43.7 million lb in 1980 (Fig. 10)(21069 bytes). Current U.S. demand for uranium is about 45 million lb/year, of which only 7% is met by new domestic production. Most uranium production in the U.S. is now obtained by low cost in-situ leaching and as a byproduct of phosphate mining. Open pit and underground mining is still active in Canada, the worlds leading producer of uranium.
The EIA forecasts world uranium demand of a cumulative 2.5-2.7 billion lb between 1994 and 2010, ranging from a current annual consumption of about 145 million lb to as much as 155 million lb; 1992 production was 91.7 million lb at an operating capacity of only 59%, representing about 63% of total demand, according to the Uranium Institute. The 37% balance of supply came through drawdown of the excess world inventory that has accumulated over the past decade.
Cancellation of projects like Long Island Lighting Co.s Shoreham nuclear plant, extended delays in bringing new facilities on line, such as the Seabrook Project in New Hampshire, and liquidation of excess uranium inventory have severely depressed world uranium prices. This situation was exacerbated beginning in the late 1980s by the export of low cost uranium from the Former Soviet Union and China. Worldwide uranium mining and milling operations have been significantly reduced, and much consolidation has occured within the industry.
The U.S. Department of Commerce accused uranium producers of the Former Soviet Union of "dumping" uranium on western markets at below production cost. EIA estimates there could be as much as 1 billion lb of military and civilian uranium inventory in the FSU.
In agreements between the Commerce Department and six FSU producers in October 1992 and March 1994, FSU export quotas were set which should allow western uranium producers prices to rise. Under the agreement, the U.S. will purchase at a cost of $11.9 billion, 500 metric tons (398 million lb) of highly enriched uranium (HEU) over 20 years. The uranium will be recovered from dismantled Russian nuclear weapons and processed and diluted in Russia before shipment.
Purchases will be 8 million lb/year during 1994-99 and 24 million lb/year the following 15 years. U.S. consumption, as previously stated, is about 45 million lb/year.
The uranium industry is at a turning point. Mine production is 60-65% of demand. Western commercial uranium inventories have been reduced significantly. There is much uncertainty about Russias ability to effectively reprocess and dilute HEU to western reactor quality standards and deliver product on schedule.
Ten million metric tons of HEU were to be delivered to Western markets in 1994; none was delivered. Nuexco, one of the worlds leading traders of uranium, declared bankruptcy in February 1995. This has caused some disruption in the spot market for uranium.
Uranium Exchange Institute, Danbury, Conn., recently concluded that these factors could put sufficient pressure on spot demand to lead to uranium price increases in the range of $17-19/lb by 1999, with prices staying in that range through 2004. This is significantly higher than the EIA price forecast of only $11.85/lb by 2000 (Fig. 10)(21069 bytes).
A high side sensitivity in the Uranium Exchange Institute study forecast a possible uranium price spike to $23-27 by 1998. In anticipation of rising uranium prices, Canadian uranium mining company share prices soared in late 1994 and early 1995.
The good news for uranium producers is that commercial uranium supply and demand will likely come back into balance in the near term and that prices could rise significantly. By mid-April 1995 the spot price for uranium had already risen to $11.40/lb.
These factors will lead to new mining and exploration activity. The White Mesa uranium mill near Blanding Utah, for example, will be reopened in mid-1995 by Energy Fuels Nuclear Inc., Denver, to process stockpiled uranium and vanadium ores from the Colorado Plateau uranium mining district. Reactivation of this mill could lead to re-opening of some of the 10-15 uranium mines presently in "mothballs" in surrounding San Juan County.
It is expected that low cost in-situ leaching will be the major source of future uranium production in the U.S. Many lower grade sedimentary uranium deposits passed over during the uranium boom of the 1970s as uneconomic for underground or open pit mining will have to be re-evaluated to determine their suitability for solution leach mining.
Tar sands
Bitumen tar and extra heavy oil sands have long been recognized as a major future source of petroleum. The Athabasca sands in Alberta and the Orinoco tar belt in Venezuela each has over 1 trillion bbl of bitumen in place.
Canada. Skeptics who believe that unconventional hydrocarbons are not economic at current world oil prices will be surprised to learn that approximately 250,000 b/d of 32, 0.1%-0.2% sulfur, synthetic oil is being produced from the Athabasca tar sands at Fort McMurray, Alta.
Nearly 70 million bbl of synthetic crude oil was produced from bitumen sands by Syncrude Canada Ltd. in 1994. The average delivered to pipeline production cost last year was (U.S.) $10.78/ bbl, exclusive of DD&A. The average sales price was $15.58/bbl, resulting in a handsome operating margin of $4.80/bbl.
The massive Syncrude project has operated profitably every year since inception (Fig. 11)(26000 bytes). So much for the myth of unconventional fuels not being economic!
In addition to the mammoth open pit bitumen sand extraction and synthetic crude processing projects of Syncrude and Suncor, an additional 140,000 b/d of liquid bitumen is produced by commercial in-situ steam stimulation at Essos Cold Lake project (92,000 b/d), Shells Peace River project (10,000 b/d), Amocos Wolf Lake project (23,000 b/d), and from an additional 25 commercial and experimental projects.
Amoco has filed permits to produce 50,000 b/d from horizontal wells at its Primrose project, and Esso plans to expand its Cold Lake heavy oil production to 127,000 b/d by 1997.
Tar sand projects produced about 25% of Canadas oil requirements in 1994. Three quarters of the heavy oil production was from the Syncrude and Suncor mining operations, and the balance was from in-situ commercial and experimental projects.
At the Syncrude operation in Fort McMurray, 25-40 m of overburden are stripped to uncover the 40 m thick tarry "ore." Two tons of tar sand are processed to make 1 bbl of synthetic crude. Bitumen is separated from the sand with steam and a hot water and caustic soda solution and then diluted with naphtha. After final centrifuging, pure 8, 4-6% sulfur, liquid bitumen at about 80 C. is produced.
This pure bitumen is then upgraded in a coking process that produces hydrocarbon gases, naphtha, and gas oil. The hydrocarbon gases are used as refinery fuel. Naphtha and gas oils undergo a secondary upgrading in which they are treated and blended to produce light gravity low sulfur synthetic crude oil.
Recovery of the bitumen in place is about 91% at the Syncrude operation. Since starting production in 1978, Syncrude has produced over 700 million bbl of synthetic crude oil. The company would like to increase its production to 300,000 b/d and expects to be able to bring unit production cost down to about (U.S.) $8.65/bbl by 1998. Syncrude estimates that it will produce a cumulative total of about 3.2 billion bbl of synthetic crude oil by 2025, when its current production permit expires.
As the economic depth for surface mining is about 75 m, only 10% of the total Athabasca deposit is suitable for mining. In-situ cyclic steam stimulation, and a new dual horizontal borehole, steam assisted and gravity drainage (SAGD) process, are being used successfully in areas where the tar sands are too deep to be surface mined. Recovery of the bitumen in place ranges from about 20% with conventional cyclic steam stimulation to possibly as much as 60% with the new SAGD process.
A typical SAGD well pair could be expected to drain an area 75 m wide by 1,200 m long by 20 m thick at a rate of 450-625 b/d over 10-12 years. Recoverable reserves of bitumen would be 2 million b/d per SAGD well pair assuming 60% recovery of the oil in place.
The Athabasca, Peace River, and Cold Lake tar sand deposits in Alberta are estimated to have a total 1.7 trillion bbl of bitumen in place. Recoverable reserves of bitumen, using current technologies, are estimated by the Alberta Department of Energy to be 246 billion bbl from in situ operations and 63 billion bbl from mining, for a total of 309 billion bbl. By comparison, Canadas conventional oil reserves are only 5 billion bbl, U.S. reserves are 23 billion bbl, and Saudi Arabias proved oil reserves are 258.7 billion bbl. Canada is clearly on its way to becoming a world oil power.
Total investment the past 30 years in Canadian tar sand research and development has been about (Canadian) $20 billion. According to the Alberta Chamber of Re- sources, further investment of $21 billion over the next 30 years is planned to raise bitumen and synthetic oil production from the current level of nearly 400,000 b/d, to 1.2 million b/d. By 2010, one half of Canadas oil needs will be derived from tar sands.
How does tar sand development compare with conventional oil? Syncrude invested $2.3 billion in initial construction capital and a further $2 billion for capacity expansions and sustained operations since 1978, to reach their current level of 200,000 b/d. If one assumes that it has cost Syncrude $4.3 billion to develop approximately 3.2 billion bbl of oil, then the development cost has been about (U.S.) $95/bbl at current exchange rates.
Syncrude estimates that it would cost about (Canadian) $5 billion during 5 years to bring a greenfield 30,000 b/d tar sand mining and synthetic crude production facility on line. If we were to assume recoverable reserves of only 1 billion bbl within the mining lease, the development cost would be (U.S.) $3.55/bbl. By simply enlarging the area of the mining lease to permit recovery of 2 billion bbl, the development cost is (U.S.) $1.77/bbl.
A new in-situ facility capable of producing 50,000 b/d of bitumen using the new SAGD technology would require about 100 pair of horizontal drainholes and cost approximately (Canadian) $650 million, according to the Alberta Oil Sands Technology & Research Center. Potential recoverable re- serves for a project of this size would be 200 million bbl of oil with a development cost of (U.S.) $2.30/bbl.
The largest petroleum development project in Canadas history, and probably the most costly offshore project in the world to date, is Hibernia field off Newfoundland. At an investment of (Canadian) $7.5 billion, Hi- bernia is expected to produce 125,000 b/d and recover 615 million bbl of oil, for a development cost of about (U.S.) $8.50/bbl.
An analysis of the capital costs and reserves of more than 50 undeveloped discoveries off the U.K. indicated a development cost of about (U.S.) $5.90/bbl of oil equivalent in 1992 dollars. Tar sands are clearly a bargain.
Despite the commercial success of the five major tar sand projects in Canada and the huge undeveloped potential of tar sands in Alberta, a number of proposed mega- projects have been cancelled. These include the Alsands, Canstar, and OSLO projects. Onerous fiscal terms, high interest rates, high inflation, and low oil prices contributed to the demise of these ventures.
Market conditions are much better today for major oil sand development. Inflation is low, interest rates are moderate, fiscal terms are improving, demand is soaring, and new technologies and operating efficiencies have reduced product unit costs. These or similar projects will ultimately be developed. Possibly as many as 10 tar sand mining ventures could be operated in Alberta, and thousands of in-situ wells can be drilled.
Venezuela. The worlds single largest bitumen sand deposit is the Orinoco tar and heavy oil belt in Venezuela. Known reserves of bitumen and extra heavy oil of about 1.2 trillion bbl are estimated by Petroleos de Venezuela (Pdvsa), of which 22% or 267 billion bbl are recoverable.
Bitumen of 7.5-9.5 and 2.7% sulfur, is extracted by steam stimulation with added chemical diluent from a reservoir depth of 150-1,200 m at production rates of about 600 b/d/well.
The lack of a market for the unrefined bitumen has historically been a major impediment for development of the Orinoco tar sands. However, in the late 1980s, Pdvsa developed a new bitumen product called Orimulsion that can be used as commercial boiler fuel for electric power generation.
Orimulsion is an emulsion of 70% bitumen processed to a particle size of only 20 microns, mixed with 30% water and 2,000 ppm surfactant. It has been successfully tested on a pilot basis at power plants in New Bruns- wick, the U.K., and Japan. Planning is in progress to convert two 800 mw facilities owned by Florida Power & Light Co. at Manatee, Fla., from fuel oil to Orimulsion.
Orimulsion is transported in heated tankers to coastal power stations and is currently priced at $1.80/ MMBTU. One bbl of Orimulsion has about 4.5 MMBTU, compared with 6.3 MMBTU for fuel oil. Ninety-five percent of the sulfur content of the bitumen fuel can be removed with conventional scrubbers to acceptable emission levels of 0.2% sulfur. Orimulsion is easier to handle than coal and has much less price volatility than fuel oil. Orimulsion production is fast approaching 100,000 b/d. Pdvsa plans to raise production to about 400,000 b/d by the year 2,000.
Total investment in research and development of bitumen production and Orimulsion is expected to approach $3.5 billion by the end of the decade.
Conoco Inc. in December 1994 announced plans to develop an Orinoco tar sand project using an in-situ cyclic steam process. The project will ultimately be capable of producing 120,000 b/d of 9.5 heavy oil that will be upgraded to 104,000 b/d of 20-23 gravity synthetic crude oil. The project will cost an estimated $1.7 billion to develop and is expected to produce about 1.5 billion bbl over 35 years from 1,200 wells. Conoco estimates that finding and development costs for the project will be between $1.52-3.70/bbl, significantly less than most international conventional oil development projects.
United States. The tar sand industry has long been dormant in the U.S. This is about to change.
Buena Ventura Resources, a subsidiary of Crown Energy Corp., Salt Lake City, has completed testing of a 50 ton/hr demonstration plant at Asphalt Ridge near Vernal, Utah. The company is now permitting a commercial scale facility that will be able to process 6,400 tons/day of mined bitumen sands with production of 3,000-4,000 b/d of bitumen.
A simple patented process that utilizes a diesel derivative hydrocarbon solvent and a biodegradable surfactant at ambient temperature will be used to separate the bitumen and sand. Buena Ventura Resources estimates that the project will require a capital investment of $25 million, and will recover 22 million bbl of bitumen over a 20 year project life. Developed cost for the Asphalt Ridge project will be $1.13/bbl if these figures are accurate. Initial unit production cost is expected to be about $9/bbl.
According to the Utah Geological Survey, Utah has 53 identified tar sand deposits with an estimated 19.4-29.4 billion bbl of oil in place. The in-place resource to a depth of 500 ft at Asphalt Ridge is about 1 billion bbl, of which the minable reserves are on the order of 120 million bbl assuming 85% recovery of bitumen from the ore.
Technological advances in bitumen extraction and processsing the past two decades have led to the economic and profitable utilization of bitumen from tar sands as a feedstock for synthetic crude oil or as bitumen based boiler fuel.
Development costs per barrel for bitumen and synthetic oil from tar sands are already more attractive than many major international conventional oil development projects. A major tar sand development is capable of producing at rates comparable to typical conventional oil fields but has reserves considerably greater than the usual field development.
Lifting costs are relatively high, but because of the low development cost per barrel the economics of tar sand development and production is not as sensitive to the uncertainties of world oil prices as major international conventional petroleum field development projects.
Production of bitumen and synthetic crude in Canada and Venezuela is approaching 500,000 b/d and has the potential to be many millions of barrels per day at current world oil prices. Recoverable reserves of bitumen in Canada and Venezuela alone are 576 billion bbl using existing technologies. This is more than one-half of proved world reserves of conventional oil. Large bitumen and extra heavy oil sand deposits in other regions of the world also have significant additional commercial reserves.
Tar sands are rapidly coming of age. They will play an important role in meeting future world demand for energy resources. The huge reserves and production potential of bitumen will begin to impact the price of conventional oil in the not too distant future.
Copyright 1995 Oil & Gas Journal. All Rights Reserved.
