Summary

Natural gas is a preferred fuel, the combustion of which offers environmental advantages over the other fossil fuels. Its use is being encouraged by the Department of Energy (DOE). However, the expansion of domestic gas utilization has been hampered since the gas shortages of the late 1970s. Two factors relate to supply, resources, and producibility. There appears to be about an 18-year supply of producible gas. This includes nine years of proved reserves plus perhaps eight years from field growth and one year from undiscovered resources (if the drilling experiences of the past decade are repeated). Although only a fraction of this amount can be recovered in any one year, there appears to be enough producible gas to sustain current production levels through the next decade. Increased lower-48 State gas production, as projected by DOE, likely will require expanded drilling activity.

However, a future gas drilling boom is questionable. In 1993, an estimated 12,376 wells were drilled in search of natural gas, compared to between 21,000 and 27,000 wells per year in the late 1970s and early 1980s. Since that time, the domestic fleet of drilling rigs has decreased by 65 percent, and only a fraction are drilling at any one time. In 1992, the active rig count fell below 600 for the first time since record-keeping began in 1940. Also, the fewest number of seismic crews were actively exploring since that count was first recorded, only one-quarter the number active in the mid-1970s. The depressed nature of the petroleum industry is further illustrated by the loss of 450,000 jobs in the past decade. Rising oil and gas prices will encourage drilling, but even at the peak of the past drilling boom, when oil prices exceeded $30 per barrel and/or gas prices $2.65 per thousand cubic feet, less than 27,000 gas wells were drilled. Some of these gas prospects were of marginal quality with unrealistic financial projections and success ratios estimated.

As large gas accumulations became more difficult to find, the negative results of such programs diminished the appeal of gas exploration as an investment. In an industry that depends upon both borrowed and investment funds, especially as the major companies move overseas, it may be difficult to finance the drilling of large numbers of gas wells. Given the depressed condition of the domestic petroleum industry and the relatively low oil prices expected in the 1990s, sufficient drilling to increase domestic gas production through the decade may not occur. New technology may improve exploration and development, but will require significant additional investment. Also, the utilization of more sophisticated technology often entails extra costs that are not always recovered and may be too expensive for the smaller independents who do much of the gas drilling. Therefore, the key to increasing gas production will continue to be drilling.

Introduction

Natural gas is the portion of petroleum in underground reservoirs that becomes gaseous under atmospheric conditions at the surface. It is primarily a hydrocarbon, a mixture of methane and ethane, and also may contain propane, butane, pentane, and hexane. It is derived from the remains of vegetation and of planktonic (1) plants and animals that were buried within fine-grained sediments and subjected to heat and pressure over geologic time. Gas is a preferred fuel, the combustion of which offers environmental advantages over the other fossil fuels. When it is burned completely, only carbon dioxide and water are normally formed. The combustion of natural gas is relatively free of the soot, carbon monoxide, and sulfur and nitrogen oxides that are often products of burning other fossil fuels. On a Btu basis, gas produces less carbon dioxide than coal or oil, thus making a significantly smaller contribution to a potential greenhouse effect. However, the low density of gas makes it more expensive to transport than oil. A section of pipe in oil service can hold 15 times more energy than when used to transport high pressure gas. Thus, gas pipelines must be of larger diameter for a given energy movement. Compression also adds to the disparity between the transportation costs of the two fuels. An oil pumping station uses energy to overcome frictional losses, but a gas line requires a large amount of energy to compress the gas before pipeline friction is even encountered. To the extent that domestic gas can be substituted for oil, a growing oil import dependency could be slowed by increased natural gas utilization, and the natural gas industry might support new markets. Therefore, natural gas is expected by the Department of Energy to play an increasingly important role in the future domestic energy mix. (2)

Recent History

The view of natural gas has not always been optimistic. In the late 1970s, there was an atmosphere of extreme pessimism about the future of domestic natural gas production. Apparent supply shortages, particularly in the winter of 1976-1977, were said to have been responsible for periodic curtailments of natural gas deliveries that caused considerable economic hardship to industry and occasionally even to commercial and public facilities. In certain areas, new residential gas hookups were not permitted because of supply problems. At that time, perceptions of sustained gas shortages dominated energy policy considerations, as such disturbing trends as declining finding rates for new gas fields and a continuing drop in proved gas reserves continued. The domestic natural gas resource was considered mature, the ten largest gas fields had been discovered between 1910 and 1956, and new large gas discoveries were rare. In 1978, the passage of the Powerplant and Industrial Fuel Use Act legally restrained the future utilization of natural gas in the industrial and electric utility sectors of the economy.

Although less gas was produced in 1993 than in the late 1970s, the perception of the future availability of natural gas has become much more optimistic. This has been reflected in Department of Energy (DOE) forecasts of increasing future domestic natural gas output. (3) Short-term production is in relative balance with demand, after a period of surplus capacity. This surplus was caused by a combination of energy conservation, economic recession, and industrial fuel switching from gas to oil due to declining oil prices and increasing gas prices. Gas prices need to remain competitive with the prices of rival fuels for the gas industry to expand. As domestic gas production has risen over the past few years, gas productive capacity has fallen as a result of declining wellhead prices and drilling. As excess domestic productive capacity narrows, Canadian imports increase. In 1993, gas imports accounted for 10.5 percent of U.S. gas consumption. (4)

In 1987, the Fuel Use Act was modified to permit electric utilities to burn oil or natural gas in new baseload generating facilities, provided that the plants were designed to permit future voluntary conversion to coal. The bill also repealed the incremental pricing provisions of the Natural Gas Policy Act of 1978. This action was supported by most energy trade associations and some environmental groups. The impact of the repeal of legal constraints on domestic gas utilization has been somewhat muted because exemptions to the Fuel Use Act routinely had been granted by the Federal Government. In new utility-owned generating plants, coal is cost-competitive with gas, and utilities still may be hesitant to use gas because of concerns regarding future availability. Also, the growth of fuel-switchable "marginal markets" is causing natural gas prices to be increasingly sensitive to the price of fuel oil. Some 40 percent of domestic end-use consumption of natural gas occurs in industrial plants that have fuel-switching capability. While concerns regarding the deliverability of domestic gas remain because of past shortfalls, the price of new gas must remain competitive with the price of coal and the world price of oil. The winter of 1991-1992 was warmer than normal, causing low gas demand and extremely low gas prices (only $1.00 per thousand cubic feet in February). However, spot gas prices increased and exceeded $2 per thousand cubic feet in the fourth quarter of 1992. Spot gas prices peaked in October at $2.57 per thousand cubic feet and then declined to $2.13 in December. (5)

As demand increased, the gas market appeared about in balance and prices were at about parity with residual fuel oil prices. However, there was concern about gas supply and deliverability for the next winter (1992-1993). (6) Rig activity and reserves had declined in response to the previous low gas prices. The performance of gas suppliers over the winter was important in establishing confidence in gas as a reliable fuel. Concerns about the adequacy of winter gas supplies began the previous spring as unusually cool weather delayed the normal buildup of gas in storage. Summer purchases of gas for inventory drove prices up to unusual levels. Gas prices rose even further when Hurricane Andrew hit the Gulf Coast and caused temporary panic in the gas spot and futures markets. However, as gas prices rose, fuel-switching away from gas to residual fuel oil became more common and the futures market for gas declined at the end of the year. (7)

It was the next winter (1993-1994) that proved critical. Decontrol of wellhead gas prices, underway since 1978, was completed. The pipeline industry had been restructured to allow unlimited third-party access to gas transportation facilities by the Federal Energy Regulatory Commission's (FERC) omnibus package that, with Order 636, completed the introduction of an unprecedented level of competition to the industry. As a result, gas is traded in a highly competitive market, while pipeline transportation is arranged separately. With the restructuring and downsizing of the industry over the past several years, there was concern as to how well it would function, especially if the winter was particularly cold. There followed record-breaking cold in the eastern half of the country, putting the gas industry to a severe test in its first heating season under the new regulatory regime. In spite of the lowest average temperatures in five years, gas utilities generally were successful in meeting gas demand. However, although storage capacity had been expanded and producers shipped record volumes of gas to the Midwest and East, gas deliverability was a problem. Some distribution companies had difficulties in maintaining flow pressures in their pipelines because of the heavy demands on the system. Thus, some customers had to be cut off so that the suppliers could refill the lines. However, as there were relatively few such service disruptions and they usually were brief, FERC's Order 636 generally was viewed as a success. (8)

The frigid weather, along with increasing gas prices, helped raise the value of natural gas produced domestically above that of crude oil output for the first time in history. Wellhead revenues for natural gas produced in the United States in 1993 reached $38.8 billion, up from $32.6 billion in 1992. This can be compared to $35.8 billion in wellhead revenues from crude oil, down substantially from $41.8 billion in 1992.(9) Total gas well completions in 1993 exceeded oil well completions, also for the first time ever. The trends of increasing gas demand and production accompanied by a decline in gas production capacity have continued. The production capacity decline is due to the drop in wellhead prices in 1986, which resulted in a significant decrease in the number of gas wells drilled. There is now a tighter balance between domestic gas demand and domestic gas supply. (10)

Natural Gas Resource Assessments

As shown in table 1, the most recent update of the U.S. Department of the Interior's (DOI) assessment of the conventional domestic natural gas resource base is considerably more optimistic than the previous estimate. Although proved gas reserves declined by 13 percent between the two assessments, the total gas resource base was estimated to have increased by 22 percents The greatest increase is in the inferred reserve category. Inferred reserves include those gas resources that are expected to be added to proved reserves through revisions of reserve estimates as a consequence of the general application of improved recovery techniques, and of the extensions of known fields and of the discovery of new gas accumulations in known fields. In the most recent assessment, inferred reserves are estimated to be about three and one-third times higher than in the previous assessment. In the onshore areas of the lower-48 States, the reestimation of reserves in old fields has added more gas to proved reserves each year than have new discoveries. Thus, the future growth of discovered fields will be an important source of additions to reserves. The reserve growth determined by new drilling will increase domestic gas production capacity, while the reserve growth achieved through calculated revisions to prior estimates will not.

Table 1. Total Domestic Conventional Natural Gas
(Dry gas in trillions of cubic feet)

The increase in reserve growth projections has been based on historical data and on the judgment that gas reservoirs are more complex than previously assumed and may hold substantial quantities of conventional gas that will not be recovered by typical well spacing and vertical holes. However, the total amount of gas discovered in new fields in 1992 represents only two weeks of domestic gas production, and while new field discoveries were up in 1993, only two and one-half weeks worth of gas was found. Even very substantial growth in such small gas fields will not add much gas to future reserves.

The ten largest known domestic gas fields were discovered before 1971 and contain nearly one-quarter of total proved gas reserves. The largest, Hugoton, was found in 1922. It is a giant field, which originally contained about 30 trillion cubic feet of in-place gas, of which about one-third remains. In 1992, 70 years after its discovery, it had 5,889 producing gas wells. These included 1,513 new infix wells that were drilled on the premise that an additional 3.5 to 5 trillion cubic feet (tcf) of gas, that could not be produced from the original wells, would be recovered (thus increasing proved reserves by that amount). Hugoton's reservoirs are carbonates that are interbedded with shales. They are heterogeneous and complex, making the field appear an excellent candidate for an enhanced recovery operation, since it was expected that additional infix drilling would encounter isolated gas accumulations not in communication with an original well. However, a recent study indicated that no new infix well encountered gas that was not being drained by an original well. Thus, there was no increase in Hugoton's proved gas reserves, and the more than 1,500 new infill wells will not increase total gas production from the field. (12) Such recovery results, as well as the small size of recent gas discoveries, raise doubts about newly increased inferred reserves estimates. Utilizing the new assessment, the projected domestic, conventional gas resource base totals some 1,711.9 tcf, including 403.8 tcf of undiscovered recoverable gas resources. Currently, Alaska's natural gas output is utilized within the State. Until a means of transporting significant quantities of Alaskan gas to the lower-48 States is in place, domestic gas production necessarily will depend upon lower-48 State gas resources and reserves. Table 2 shows the remaining gas resource base in the lower-48 States.

Table 2. Remaining Natural Gas in the Lower-48 States
(Dry gas in trillions of cubic feet)

Unconventional Gas Resources

The decomposition of organic matter in an oxygen-poor environment, with the aid of anaerobic bacteria, results in the formation of methane. Organic matter is ubiquitous, and, therefore, so is natural gas. If all of the natural gas could be collected, it could provide the world's energy for thousands of years. Unfortunately, most is too diffuse to be of commercial value and, in the course of geologic time, reaches the earth's surface and is lost. Gas is generated in an extensive vertical zone extending downward into the earth's crust that includes shallow biogenic gas, intermediate gas formed along with and dissolved in oil, and deep thermal gas. The organic source rocks can be at depths extending below 16,000 feet from which the gas migrates along permeable horizons until it reaches the surface or is trapped. Gas displays an initial low concentration and high dispersibility, making adequate seals very important to conventional gas accumulation. However, due to differences in the physical properties of gas and oil, similarly sized oil traps contain more recoverable energy (on a Btu basis) than gas traps, although more than three-quarters of the in-place gas often can be recovered. (13) The boundary between conventional gas and unconventional gas resources often is not well defined, as they result from a continuum of geological conditions. Coal seam, shale, and tight gas occurs in rocks of low permeability. Special treatment is required to produce such gas, even at relatively low recovery rates.

    Coal Seam Gas Accumulations

The process by which vegetation is converted to coal over geologic time generates large quantities of natural gas. Such gas becomes concentrated as conventional gas deposits in adjacent permeable sediments and as unconventional continuous gas deposits in the coal. Coal seam gas is produced mainly in the San Juan basin (New Mexico), the Piceance basin (Colorado), and the Black Warrior basin (Alabama). The coal does not form a continuous reservoir over an entire basin. Rather it occurs in individual non-communicating beds separated by other strata. Coal seams are compartmentalized gas reservoirs bounded by facies changes or faults and the coal itself yields extremely variable amounts of gas. Deeply buried coal seams exhibit severely reduced permeabilities and, thus, reduced gas recoverability. The productivity of a coal seam gas well depends mostly on reservoir pressure and water saturation. Multiwell patterns are necessary to dewater the coal and establish a favorable pressure gradient. Since the gas is adsorbed on the surface of the coal and trapped by reservoir pressure, initially there is high water production and low gas production. Thus, an additional expense relates to the disposal of coal bed water, which may be saline, acidic, or alkaline. Then, water production declines and gas production significantly increases before eventually beginning its long decline. In general, however, coal seam gas recovery rates have been low and unpredictable.

Proved reserves of coal seam gas in 1993 were estimated at 10.184 tcf, more than double the 5.087 tcf reported in 1990. (14) However, the growth in reserves compared to 1992 was only one percent, as the Federal tax incentives for drilling new coalbed methane wells had expired. Coal seam gas production increased by 36 percent in 1993, to 0.732 tcf, and accounted for about four percent of total domestic gas production. The increase resulted from improved production technology and significant tax credit incentives applicable to wells drilled from 1980 to 1992 under the Crude Oil Windfall Profits Tax Act of 1980. In 1991, the tax credit was about $0.90 per thousand cubic feet of produced coal seam gas, which was more than 50 percent of the average wellhead gas price at the time. (15) The expiration of the tax credit on coal seam gas drilling at the end of 1992 (when it reached $0.92) has impacted the coal seam gas industry. Coal seam gas drilling, which accounted for about half the domestic gas wells in the past several years, has declined somewhat as producers concentrate on producing more gas from existing wells that carry the tax credits. Production of coal seam gas increased by 55 percent in 1992 to 0.539 tcf (three percent of total domestic gas production).

The U.S. Geological Survey has assessed undiscovered, recoverable, continuous coal seam gas resources at 49.9 tcf within a range of 42.9 to 57.6 tcf. (16) Currently, average per-well coal seam gas production is about the same as average per-well conventional gas production in the United States. This is only three times higher than stripper well production. Average per-well conventional gas production from a mature gas-rich basin, such as the Gulf Coast was in 1980, is about five times higher. Coal seam gas can be substituted for conventional gas in the United States, as conventional gas prospects become poorer and average per-well gas production falls to coal seam levels, but several times as many wells will have to be drilled as were drilled in the past to achieve similar gas production levels.

    Tight Continuous Gas Accumulations

Large continuous gas accumulations are present in low-permeability (tight) Cretaceous and Tertiary age reservoirs in many basins of the western United States and in Devonian age reservoirs in the East and Midwest. The tight gas reservoir rocks can be sandstones, siltstones, shales, sandy carbonates, limestones, dolomites, and chalk. Such gas deposits are commonly classified as unconventional because their reservoir characteristics differ from conventional reservoirs and they require stimulation to be produced economically. (17) The tight gas is contained in blanket or lenticular reservoirs that are relatively impermeable (with in-situ effective permeability of less than one millidarcy, compared to as high as several darcies in conventional reservoirs). Continuous-type gas accumulations can occur downdip from water-saturated rocks and cut across lithologic boundaries. They often include a large in-place gas volume, but a low recovery factor. Historically, tight reservoirs have been uneconomical sources of gas because of low natural flow rates. However, gas is now recovered from the better quality tight reservoirs, especially the relatively continuous blanket-type sandstones that have been stimulated by massive hydraulic fracturing.

Massive hydraulic fracturing refers to volume. Since the tight reservoirs are massive, it is impossible to penetrate them effectively by pumping the 50,000 gallons of fluid that is normal in conventional reservoir fracturing. Stimulation can be improved with extremely large amounts of pumped fluid and proppants (granular material, usually sand, used to keep the fractures open after the fluid has been drained away). Massive hydraulic fracturing can require 500,000 gallons of gelled fluid and a million pounds of sand to be pumped down a well to create nearly vertical propped open fractures that provide a pressure sink and channel for the gas, thus creating a larger collecting area so that gas recovery is at a faster rate.

The $0.52 per thousand cubic feet Federal tax credit for drilling wells in tight gas reservoirs was an important factor in increasing rig activity in the second half of 1992, when one third of all active rigs were drilling for tight gas. When the tax credit expired at year-end, tight gas drilling was curtailed because most tight gas prospects are not economic without the tax credit. Gas production from tight reservoirs is about 1.2 tcf (about seven percent of total domestic gas production). (18)

The term Devonian refers to the geological time of deposition (about 350 million years ago) of shales in a shallow sea that covered almost half of the present continental land mass of the United States. The erosion of the lands adjacent to the sea produced massive quantities of fine sediments and organic debris that accumulated on the sea floor in stagnant water as organic-rich mud. Subsequently, the pressure of overlying sediments combined with the natural heat flow of the earth gradually transformed the organic mud to black shales. The Devonian shales were later uplifted and eroded and now cover only about one-fourth of the North American continent, where they occur mainly in the Appalachian, Michigan, and Illinois basins. As the mud was transformed to shale, natural gas was produced from the organic material. Some of the gas migrated and was trapped in adjacent sandstones forming conventional gas deposits and the rest remained locked in continuous-type accumulations in the nonporous shale. (19)