Minnesotans For Sustainability©
Sustainable Society: A society that balances the environment, other life forms, and human interactions over an indefinite time period.
The Domestic Natural Gas Status
Joseph P. Riva, Jr.*
Table of Contents
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.
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)
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)
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
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
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.
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.
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.
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.
Although almost all Devonian shale contains some gas, its gas-producing ability is generally indicated by color. The organic-rich black and very dark brown shales appear to be the best gas producers. The gas that is recovered from Devonian shales occurs in well-connected fracture porosity. Devonian shale gas production (currently mostly from the southwestern part of the Appalachian basin) is at low flow rates, but is generally long lasting. Thus, recovery efficiency can eventually become quite high. Because the factor of greatest importance for commercial flow rates is the presence of natural fractures, there is limited exploration for Devonian shale gas. The only direct method to detect areas of natural fracturing is drilling, which is expensive. Normally Devonian shale gas wells are stimulated by artificial fracturing with explosives or hydraulic pumping. While some shale wells may outperform some conventional gas wells on a cumulative production basis, their slow flow rates result in a slow rate of return on invested capital. The need for casing to protect coal seams, in addition to the cost of stimulation, makes shale gas expensive. However, further improvements in recovery methods could help reduce costs.
Proved tight continuous gas reserves have been estimated by the U.S. Geological Survey at 308.1 tcf, within a range of 219.4 to 416.6 tcf. (20) However, unless gas prices increase, only a small fraction of this gas will be recovered and even this will involve drilling and fracturing very many more wells.
Total domestic natural gas production decreased by five percent between 1980 and 1993 (to 17.789 tcf). Currently, about 79 percent as much gas is being produced as was produced in 1973, the peak year of domestic gas production. Proved gas reserves peaked in 1967, and since have declined by 45 percent to 162.4 tcf (see figure 1). The decline during 1993 was 1.6 percent (2.6 tcf). Total gas discoveries in 1993 (8.868 tcf) increased by 26 percent over the previous year, but were 11 percent lower than the average for the prior ten years. New field discoveries (0.899 tcf) were extremely low, representing only about two and one-half weeks production, and were 35 percent lower than the prior ten-year average. Recently, field growth has increasingly sustained proved gas reserves. In 1993, there was 14.29 tcf of gas field growth, compared to the 0.899 tcf found in new fields. The steep decline in new field gas discoveries is indicative of the maturity of the gas resource base. Since the large gas fields mostly have been found, those remaining generally are small and each contributes relatively little gas to proved reserves.
Table 3 shows domestic natural gas production and proved reserves, as compiled by the Energy Information Administration and the American Gas Association, and the number of wells producing gas by World Oil. In table 3, 1967 is shown because it was the year of peak domestic proved gas reserves, while 1973, also shown, was the year of peak domestic gas production. Proved gas reserves have generally declined since 1981, except for 1990 when an economic reassessment of North Slope (Alaska) gas resources led to a reclassification of some technically recoverable gas as proved reserves.
Domestic natural gas production increased in 1993 to 17.8 tcf. The current production level is near the maximum achievable, given the magnitude of proved gas reserves, as the lower-48 State domestic gas reserves/production ratio (R/P) is 9/1. The size of the gas bubble (excess gas production capacity) depends upon the existence of shut-in wells and usable infrastructure, and also upon wells now operated below maximum production capacity. Recently, it has appeared that the gas bubble is essentially gone, and that gas production capacity and demand are reaching equilibrium. This was demonstrated during the cold weather at the end of 1989 and in the winter of 1993-94, when maximum utilization of both producing gas fields and gas storage facilities was necessary to meet demand.
The year-around gas bubble no longer exists as supply and demand come together in peak winter months. However, a surplus of gas exists in warmer months. Also shown in table 3 and in figure 2, is average annual per-well gas production, which has declined by 66 percent since 1973.
There were more than twice as many wells producing gas in 1993 than in 1973, when gas production peaked at 22.6 tcf. An average gas well in 1973 annually produced nearly three times more gas than a similar well in 1992. Annual per-well gas production has declined rather steadily since the early 1970s, to 0.062 billion cubic feet (bcf) in 1993 (see table 3). This is about equal to the average production of a coal seam gas well, and about ten times higher than average stripper well output. In 1993, the 160,000 stripper gas wells (those producing 60,000 or less cubic feet per day) that were on-line and accounted for about five percent of total domestic gas production. As the larger conventional gas fields become depleted and intensively infill drilled and new gas discoveries become smaller in the mature basins (where much exploration has already taken place), per-well gas recovery decreases and an increasing number of wells are needed to produce the same amount of gas. Likewise, unconventional gas accumulations will be produced more slowly than the older, large conventional gas fields and thus require more wells. Some coal seam and tight gas is produced at near stripper well rates. In 1993, some 12,376 wells (including exploration and development wells and dry holes) were drilled for gas and 3,499 stripper wells were abandoned. The net result was an increase of 5,269 producing gas wells.
Table 3. Total U.S. Dry Gas
Lower-48 States (onshore and offshore) 1993 proved gas reserves, production, reserves/production ratio (R/P), producing gas wells, and average annual per-well gas production are shown in table 4, along with the percentage change during the past decade shown in parentheses.
Table 4 indicates that over the past decade, the average annual per-well gas production decline in the Midcontinent, the Nation's second leading gas producing region, was 15 percent. In the leading gas producing region, the Gulf Coast, average annual per-well gas production declined by nine percent compared to the end of 1983. The offshore part of the Gulf Coast, with the exception of the subsalt prospect, is a mature gas producing region with a cumulative production of about 100 tcf in over 675 fields. As development has progressed, the size of the discoveries has decreased along with major company interest. As leases are relinquished in record numbers, independents are replacing the major companies as the Gulf's predominant operators. However, the independents often do not have the finances to duplicate all of the work normally done by the majors or to utilize the most expensive advanced technology. Thus, drilling in the Gulf has declined at a time when more wells are needed to maintain reserves and production levels. (21) While there were even greater declines in average yearly per-well production in the Pacific and Atlantic and Easter Interior regions, the Gulf Coast and Midcontinent, together, account for 81 percent of the gas production in the lower-48 States. Thus, they have a major influence on lower-48 State average annual per-well gas output, which declined 19 percent in the last decade. Table 4 also shows a significant decline in proved gas reserves in the Pacific, Gulf Coast, and Midcontinent. In both the Gulf Coast and the Midcontinent, gas is being produced at efficient rates (RP's = 6/1 and 9/1). (22) It is doubtful if this recovery rate can be much increased. Therefore, for production to be sustained or increased in these regions, there will have to be additions to proved reserves.
The estimated number of total wells drilled for gas (exploration and development and dry holes) are shown in table 5. (23) During the 1980s, an average of about two wells had to be drilled for gas (exploratory, development, and dry holes) to net one additional producing gas well, since not all wells are successful and depleted wells are constantly being plugged and abandoned. Table 4 shows the decline in annual per-well gas production over the past decade. If this per-well gas production decline rate of could be reduced by one-half in the next decade with improved technology, fewer wells would have to be drilled each year than were drilled in 1993 to sustain current production levels to 2004. This would amount to a total of about 6,025 wells per year, only about one-half as many as were drilled in 1993. However, if the decline rate remains similar to that of the past decade (19 percent), some 13,770 wells would be needed yearly, an amount that should not be difficult to achieve.
The Department of Energy has recently projected an increase in lower-48 State domestic gas production over the next decade to about 18.8 tcf. (24) If there were no decline in average per-well gas production rates, current drilling levels may achieve this increase. However, if the rates were to fall by the same amount as in the previous decade, some 19,500 wells would be needed in each year of the next decade to achieve the production increase projected by the Department of Energy. This is more wells than were averaged in the 1980s and than were drilled in any one year in the 1990s. Unless the cost of gas rises significantly, drilling at such levels will not be achieved. The Rocky Mountain region contains the most underutilized proved gas reserves in the lower-48 States, but produces at a low per-well rate lower because of substantial coal seam and tight gas output. With Midcontinent per-well production rates and Rocky Mountain rates already near the lower-48 State average, it is likely that the average rate will further decline in the next ten years.
Table 4. Lower-48 States Dry Gas in 1993
Table 5. Estimated Total Wells Drilled for Gas
Several years of increasing gas consumption have brought domestic gas supply and demand into a precarious balance. Increasing gas utilization has resulted in record gas import levels, up from 0.689 tcf in 1986 to 2.2 tcf in 1993, some 10.5 percent of total demand. (25) At a time when low oil prices are causing many producers to reduce oil directed exploration, gas drilling has increased. Higher gas drilling activity comes at a time when overall drilling is very low and the demand for gas continues to grow in all markets. However, serious questions remain as to whether the right kinds of gas wells are being drilled, since during the past decade, discoveries made by exploratory wells have fallen far short of replacing yearly production. After dropping to a low 16.2 tcf in 1986, U.S. gas consumption in 1993 was 20.3 tcf (including the 2.2 tcf of imports from Canada). (26)
Figure 3 shows the average annual wellhead price of gas (in current dollars) and the estimated total number of exploration and development wells and dry holes drilled for gas and table 6 includes the price of oil. (27) As shown, 1981 was the year of peak gas drilling activity. Oil prices were also at a peak, averaging $31.77 per barrel at the wellhead. Gas prices were rising and exceeded $2.45 per thousand cubic feet for the next four years. These also were years of high drilling activity. Increased drilling activity is likely to be needed to increase gas production during the next ten years, if average per-well gas production declines as in the previous decade. While the price of gas is expected to rise, oil prices are not expected soon to approach $30.00 per barrel. Thus, fuel switching again may dampen gas demand and gas drilling incentives.
The expansion of natural gas utilization has been in question since the late 1970s' supply limitations. Two factors relate to supply, resources (see table 2) and producibility. The least controversial part of the gas resource base, proved reserves, are estimated annually by EIA/DOE and are accepted as 152.5 tcf in the lower-48 States in 1993. (28) Proved reserves are producible, and 152.5 tcf is about a nine-year gas supply at current production rates. Inferred reserves are more controversial, with newly expanded estimates of 296.1 tcf. (29) During the past decade, about 136 tcf of gas was added to proved reserves by field growth. Thus, known fields have shown substantial growth in the recent past, and since most large fields are old, it is questionable that equal growth can continue. But, if about 136 tcf is again added to proved reserves in the next decade, this would be an additional eight-year gas supply that would be producible.
The range of lower-48 State undiscovered gas resources assessments is not as wide (276-325 tcf). (30) These estimates, however, are now limited by a drilling moratoria and must be reduced by about ten percent (to 248-392 tcf), because drilling is prohibited off much of the east and west coasts and Florida. It is ironic that environmentally inspired drilling moratoria will inhibit the utilization of environmentally favored natural gas, since 75 percent of successful offshore drilling encounters gas rather than oil and large gas accumulations are likely to exist in portions of the outer continental shelf now under moratoria. Thus, the offshore regions now off limits to drilling could be especially important, because the potentially large gas fields that they may contain could provide the high production rates that would be useful in offsetting the falling rates in the mature onshore gas provinces.
Table 6. Gas and Oil Prices and Number of Wells Drilled For
To become producible, undiscovered gas resources must be discovered and
converted to proved reserves, an ongoing process that depends upon exploratory
drilling activity. In the past decade, only about 13 tcf of gas was discovered
in new lower-48 State fields, not even one year's supply. Recent drilling has
fallen behind that of the 1980s, but if one year's gas supply is again
discovered, there would be a reasonably firm 18-year supply of producible gas
available (nine years of proved reserves, eight years of inferred reserves, and
perhaps one year of undiscovered resources).
The boundary between conventional and unconventional gas resources is not well defined because often they are a product of a continuum of geologic conditions. About 10 tcf of proved gas reserves are in coal seams and are included in the 18-year supply of producible gas previously described. Coal seam gas resources (estimated-between 43 and 58 tcf) currently are not producible. Also currently not producible are the 219 to 417 tcf of estimated tight continuous gas resources. These unconventional gas accumulations remain to be precisely located and evaluated for development and some will require new or improved technology for economic recovery. All types of unconventional gas accumulations are produced at lower flow rates than conventional gas fields, and thus require significantly more wells to achieve similar production rates.
Increasing lower-48 State gas production levels, as projected by the Energy Information Administration, are probably dependent upon increased drilling activity. (31) However, the prospects of a future drilling boom are not favorable. In 1993, an estimated 12,376 wells were drilled in search of natural gas. This was an increase from the 10,032 wells in 1992, but also can be compared to between 21,000 and 27,000 wells drilled for gas per year in the late 1970s and early 1980s. The domestic fleet of drilling rigs has been declining since 1982, from over 5,640 to below 2,000, but only a fraction of the remaining rigs 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. Because of the decreasing rig count, an estimated 45,000 workers lost their jobs in 1991 and 1992, part of 450,000 petroleum industry jobs that have been eliminated in the past decade. In 1993, increased gas drilling helped raise the average rig count to 757, but the smallest number of seismic crews were active since the count has been recorded, some 74 percent fewer crews than in 1974.
Rising oil and gas prices will encourage drilling and at the peak of the drilling boom, when oil prices exceeded $30 per barrel and/or gas prices $2.65 per thousand cubic feet, more than 20,000 gas wells were drilled each year. However, many of these prospects were of marginal quality with unrealistic financial projections and success ratios factored into their drilling programs. As large gas accumulations became more difficult to find, the negative results of such programs diminished the appeal of gas drilling as an investment. In an industry that depends upon both borrowed and investment funds for a substantial portion of its operations, it may be difficult to finance the drilling of the increased numbers of gas wells that may be needed annually to increase domestic production. Not even the most optimistic forecasts put oil prices or drilling at the levels of the early 1980s. Given the reduced condition of the domestic industry, drilling may not increase sufficiently to increase domestic gas production through the next decade. New technology can be expected to improve gas exploration and development. However, such research and development will require significant additional investment. Also, the utilization of more sophisticated technology often entails extra costs that are up front and not always recovered. The smaller independent companies that do much of the gas drilling may not be able to afford the more costly technical advances. Therefore, the key to increasing gas production will continue to be drilling.
The key factor for sustained or increased lower-48 State gas production is gas well deliverability. The low levels of gas reserve additions have forced the utilization of available wellhead capacity so high that deliverability may become a problem. In the Gulf area, operators are producing at maximum rates while many gas producers in the Rocky Mountains have shut-in gas wells because of soft regional markets. Although substantial reserves and productive capacity exist in this region, its average per-well production, with many tight gas and coal seam gas wells, is only 0.063 bcf, compared to 0.231 bcf in the Gulf Coast. In the Gulf Coast, however, per-well gas production has declined by nine percent in the past decade. If average lower-48 State per-well gas production continues to decline at the same rate as in the past decade, a yearly average of about 13,770 wells will have be drilled for gas to sustain current production through the next decade, but some 19,500 wells per year may be necessary to increase it to the levels projected by the Department of Energy. As it appears unlikely that yearly gas drilling will expand to nearly 20,000 wells, domestic gas production may not increase, as least to the extent projected by DOE. Then a future expansion of gas consumption would depend upon increased imports or on the transportation of Alaskan gas to the lower-48 States.
Congressional options to encourage increased drilling and, thus, future domestic gas production include such possible tax reform measures as reestablishing the tax credits on unconventional gas resources and/or allowing companies to expense geological and geophysical exploration costs. However, a larger increase in future gas production likely would result from a lifting of the moratoria on offshore gas exploration and development, because of the large gas fields with potentially high productive capacity that are thought to exist in some parts of these frontier regions.
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