The U.S. probably is helpless to prevent another domestic oil production decline in 1991 despite the recent oil price runup and looming supply crisis.
That will be the case even if oil prices remain at current levels and there is an all out effort to boost production in key producing states.
The main reason is that an industry decimated by the ravages of the 1986 oil price collapse cannot muster the capital, equipment, and personnel within 6 months or 1 year to make a significant difference in U.S. oil production.
Even if the wherewithal were available, however, operators stung by the 1986 price collapse remain generally unwilling to boost drilling/production outlays sharply on the basis of an oil price level that might soon evaporate.
WHAT'S POSSIBLE
Oil & Gas Journal estimates that a best effort by U.S. producers will result in a gross production increase of about 373,580 b/d by fourth quarter 1991.
That is an extremely optimistic view based on preliminary results of surveys of states' incremental production capabilities by the Interstate Oil Compact Commission and on estimates by other industry sources.
Many of the states' preliminary estimates hinged on oil prices remaining at current levels, tax incentives, or regulatory relief, or a combination of the three.
OGJ also estimates U.S. oil production will fall in 1990 by 5.1% to 7.225 million b/d. That compares with declines of 6.5% in 1989, 2.5% in 1988, and 3.8% in 1987.
However, 1987-89 were peak years for Alaskan oil production, with the decline at Prudhoe Bay field making a significant dent in 1989.
Lower 48 production fell by 6.3% in 1987, 4.1% in 1988, and 6.3% in 1989.
Assuming a comparable decline rate in 1991 of about 5% in the absence of a concerted effort to hike production yields a gross U.S. production loss due to natural decline next year of 361,250 b/d.
Thus, under this best case scenario, U.S. production in 1991 would average 7.237 million b/d, a net gain of only 12,330 b/d after a major push to boost oil flow.
Whether that major push materializes to the extent envisioned remains to be seen, and the likelihood of the best case scenario is doubted by some of the industry officials OGJ contacted.
For example, Texas hinges its projection of another 40,000 b/d in 1 year on oil prices stabilizing at $25/bbl for the year.
California's IOCC estimate of another 150,000 b/d in 1 year is based on the assumption that all of its production decline since 1985 could go back on stream. Instead, industry officials think the state would at best restore perhaps 75% of those production losses, putting a realistic estimate at closer to 100,000 b/d.
In addition, many of the IOCC estimates did not take into consideration natural decline rates. Accordingly, OGJ predicts a more likely average U.S. production of 7.08 million b/d in 1991.
That means a net decline of about 145,000 b/d from the level OGJ projects for 1990.
OGJ estimates U.S. oil demand will slip 0.9% in 1990 to 18.02 million b/d, because of slower economic growth, fuel switching, and conservation in response to the recent runup in oil prices. U.S. oil demand will climb to 18.1 million b/d in 1991, according to OGJ projections.
CRUDE IMPORTS UP IN 1991
Despite the possible threat of an oil supply shortfall in 1990-91, an all-out effort to boost production, and the highest oil prices in more than 5 years, U.S. crude oil imports, excluding the Strategic Petroleum Reserve, will have to rise another 225,000 b/d to meet expected demand in 1991.
The estimates assume there will not be any political action to spark widespread fuel switching or drastic conservation measures, directly or indirectly, through taxes or other means.
A sustained oil price increase could slow and perhaps flatten the U.S. crude production decline curve.
U.S. production reversed its long term slide in 1977 with start-up of supergiant Prudhoe Bay oil field, then seesawed during 1978-1980 before sustaining an increase during 1982-85 after a record surge of drilling.
However, industry now recognizes that surge as an anomaly, fueled by the mistaken belief that oil prices would remain high indefinitely without significantly trimming demand.
Although some analysts are predicting higher oil prices in the 1990s because of the Middle East crisis, those forecasts have yet to lead to significant changes in capital spending plans among most companies.
Further, it is likely that even with a sustained period of higher oil prices, the U.S. crude oil and natural gas industry and its lenders will be much more conservative in their view of long term economics, remembering the lessons of 1986.
Shortages of confidence, investment capital, trained personnel, and well service rigs all but wipe out the possibility of a short term increase in oil production in most of the Lower 48 states, say officials of U.S. associations of drilling and well service contractors.
In addition, the revived prospect of punitive measures such as a "windfall profits" tax only makes companies even more leery of investing in developing more U.S. oil productive capacity.
It all adds up to the likely scenario that U.S. oil production will continue to decline in the early 1990s, perhaps at best slowing that slide somewhat if oil prices remain at current levels.
COMPANY SPENDING
There are some exceptions to U.S. companies' reluctance to change spending plans in the wake of the Persian Gulf crisis.
Chevron U.S.A. has hiked capital spending by another $100 million this year to accelerate oil and gas drilling and boost production in the U.S. Chevron said the spending gain is intended to add initially 40,000 b/d of oil equivalent to its U.S. oil and gas production.
Plans call for another 130 development wells in major fields, including Bay Marchand off Louisiana, Rangely in Northwest Colorado, Lost Hills in California's San Joaquin Valley, and Whitney Canyon/Carter Creek in Southwest Wyoming.
Those mature fields are targeted for the boost because they have the permits and infrastructure in place to immediately handle production from more wells.
Most of the drilling is scheduled for the fourth quarter, with the added production expected to peak early next year.
Chevron said the work will be done as soon as possible, but increased competition for drilling rigs and other equipment could slow that push somewhat.
The added drilling boosts Chevron U.S.A.'s previously approved 1990 budget by about 10% to more than $1 billion.
Most of the extra spending is earmarked for the Gulf of Mexico and San Joaquin Valley.
Meantime, Conoco Inc. has added $10 million to its 1990 capital budget for exploration in the Gulf Of Mexico. Conoco accelerated the timetable for five prospects that had been previously scheduled for 1991 and later years.
"However, with the literal dismantling of the exploration infrastructure in the U.S. during recent years, this country can't expect to see a significant increase in exploratory activity right away," said M.G. Pitcher, Conoco executive vice-president for worldwide exploration.
"It must also be recognized that even if one of these wells is a commercial discovery, it still will be some time before it becomes a source of energy for the nation," Pitcher added.
"But while this single effort will not lessen U.S. dependence on overseas energy right away, it is a step in the right direction."
NEW E&D OPTIONS
In terms of exploration and development of significant new oil potential, there are almost no near term options.
There is one option to turn the expected net U.S. production decline in 1991 into a net gain: bringing Point Arguello field in the Santa Barbara Channel off California on stream more quickly than expected.
The $2 billion Offshore California development project, lying idle for about 3 years, could go on stream after about 6 months of demothballing and commissioning efforts.
it would take another 6 months to build Point Arguello flow to as much as 75,000 b/d. But that would hinge on having all permits in hand today.
The Point Arguello project remains ensnarled in a dispute over whether partners led by Chevron Corp. can transport the field's oil to market via tanker or existing onshore pipelines.
The companies remain at odds with Santa Barbara County and the California Coastal Commission, and the Middle East crisis has not yielded concessions from state or local authorities.
Meantime, Chevron and partners are pursuing a new onshore pipeline proposal while still seeking a permit for interim tankering. The new pipeline could go on stream in perhaps 24-30 months if permits were expedited (OGJ, Aug. 20, Newsletter).
The U.S. Department of Energy has offered to mediate the dispute, with no progress reported to date.
Longer term, another significant project in the pipeline is Exxon Corp.'s proposed further development of Santa Ynez Unit (SYU), also in the Santa Barbara Channel.
SYU flow, currently about 25,000 b/d, could jump to 90,000 b/d in 1994-95, but production from further development won't start until second quarter 1993 (OGJ, June 4, p. 71).
In addition, there are a number of significant discoveries off California that have been blocked from development because of environmental opposition or economic constraints.
They represent reserves that, if developed quickly and concurrently under an extremely unlikely scenario, could boost Offshore California production by a further 100,000-300,000 b/d in the late 1990s.
Production from marginal fields on Alaska's North Slope could offset to some degree declining North Slope production in the latter part of the decade as well, if industry could overcome a host of environmental, technical, and economic constraints. For now, however, there is little prospect of production from new fields in Alaska before 1992-93.
In the next century, industry must look to frontier areas of the Outer Continental Shelf and the Coastal Plain of Alaska's Arctic National Wildlife Refuge for reserves that might slow the U.S. oil production decline.
If those areas were made accessible today, production could not start until late in the decade-after 2000, in the case of ANWR's Coastal Plain.
Even with access, there remain other roadblocks to development, such as the Bush administration's new no net loss wetlands policy, which requires protection of wetlands in an area equal to those covered by proposed development.
Oil industry officials earlier this month called for the Bush administration to exempt Alaska from the policy. Alaska holds two thirds of all U.S. wetlands, and the entire North Slope is classified as wetlands.
GOVERNMENT INCENTIVES
Whatever incentives state and federal governments can provide are likely to have a limited effect in the near term.
The Texas Railroad Commission (TRC) approved an emergency 90 day program, effective Sept. 1, allowing oil wells in the state to produce at 100% of their maximum efficient rate (MER). Wells in fields where production is held below MER by special TRC rules were excluded from the emergency measure.
Texas oil and gas regulators expected the emergency measure to increase production statewide by 20,000 b/d.
But with Texas oil production declining each month by an average 8,333 b/d, officials said, whatever incremental oil was recovered would soon be lost to long term production declines.
On the federal side, DOE earlier proposed some short term remedies for increasing domestic production and reducing oil demand (OGJ, Aug. 20, p. 36).
John Easton, assistant energy secretary for international affairs and energy emergencies, said, "With respect to medium term options, the department is in the process of evaluating additional measures that could be taken in the next 12-24 months. These, too, would be a balanced approach of energy production, reduction in demand, and fuel switching."
DOE has proposed tax incentives for production enhancement as well as for conservation measures, but they have been under consideration by a White House economic council for some time.
Before the current crisis, the Bush administration had proposed a series of tax changes to help maintain domestic production. Congress has yet to approve them at any level.
The administration suggested giving producers a 10% credit on the first $10 million of exploration expenditures (per year, per company) on intangible drilling costs (IDCs) and a 5% credit on the balance, a 10% credit for new tertiary enhanced recovery projects, elimination of 80% of current preference items generated by independents' exploratory IDCs under the minimum tax, and repealing a depletion provision that discourages independents and majors from buying and selling properties from each other.
The Bureau of Land Management (BLM) has ordered its state offices to expedite processing of applications for oil and gas leasing on federal lands.
INFILL/EOR
A DOE official said the best prospect for additional production is from a national infill drilling campaign but limited rig capacity "would be a barrier."
He said the number of drilling rigs might be increased to 1,400-1,500 with some effort, but finding personnel would be a problem.
Another problem is getting bank loans, he said.
"It takes a lot of justification for an oil producer to get money out of a bank these days. Who knows what prices will be a month or two from now? And the banks already are extended because of bad loans to industry. "
He said additional enhanced oil recovery projects could not help much, but of those, steam projects could be brought on stream the fastest, within 6-12 months.
"No matter what we do I don't think we can get any quick oil in the next 3-6 months."
Vello Kuuskraa, of ICF-Lewin, Fairfax, Va., said additional infill drilling offers "tremendous opportunity."
"Look at what industry was able to accomplish in the 1980-85 time period. We had a sustained level of drilling and we were able to stabilize our production during that time.
"We've learned over the past 5-6 years that infill wells actually add reserves, and the reservoir continuity is not as good at the traditional well spacings."
He said if the price holds, industry can mobilize its efforts in 6 months or a year and find the best fields for additional wells, and money and hardware to drill them. "History has shown that if the demand is there, industry can mobilize."
He also said if more natural gas can be moved through pipelines to California, "we could kick up heavy oil production out there."
API, IPAA VIEWS
Charles DiBona, API president, said U.S. production is about 7 million b/d but eventually could rise to about 9 million b/d and could hold for a long period of time, under the right conditions.
"Price is key. Whether you consider a well successful depends on what the price of oil is. Assuming a fairly high price, and access to public lands-that's the biggest detriment next to price-and assuming a reasonable permitting situation, we think you could stabilize production somewhere in the order of 9 million b/d."
DiBona said the next Congress "will have to ask very seriously whether or not they can afford to deny industry access to ANWR or OCS lands."
Significantly, no Washington oil association yet has advocated that existing environmental laws be relaxed so that production might be increased.
But API says Congress should reconsider what planned revisions to the Clean Air Act will affect domestic drilling and refining.
William O'Keefe, API vice-president and chief executive officer, said, "There are a lot of fixes within the Internal Revenue Service code that would be a help because they would lower the cost of production relative to the return."
He said they include the expensing of geological and geophysical costs, relaxing depletion rules on transfer of properties from majors to independents, and changes in the alternative minimum tax.
An Independent Petroleum Association of America official said it will be difficult to increase U.S. production in the very short term, but longer term, tax changes could have an effect.
"The current higher price is encouraging, but has to be in effect for a sustainable period of time to make a difference. Why should a U.S. oilman invest a quarter of a million dollars in a well today, when the madman Hussein may decide to kiss and make up with Kuwait tomorrow?"
Bobby Hall, API production manager, said industry could add "several percentage points of production from more frequent workovers."
He said the higher price for crude would justify the additional workovers, and although workover rigs might be in short supply initially, the service/supply industry would respond to higher demand.
Hall said if the Texas Railroad Commission decides to increase the allowable for East Texas field, which it is due to consider at its Sept. 20 meeting, "they might pick up 10-15,000 b/d right there."
Hall noted that Environmental Protection Agency could bring about a "great savings" in crude oil by relaxing its volatility rules on gasoline.
"The nation should be looking at a total package: getting more crude production, making it go further, and taking conservation steps."
RMOGA RECOMMENDATIONS
Rocky Mountain Oil & Gas Association (Rmoga) has made a number of recommendations to increase U.S. near term oil production, said Executive Vice-Pres. Jess Cooper.
Rmoga would like to see Interior Department reassess its oil and gas leasing process to open more federal lands to exploration and expedite lease issuance.
Interior should evaluate forests and resource areas on a case by case basis and avoid requiring new environmental impact statements (EISs), unless absolutely necessary, to speed up leasing decisions.
Rmoga believes Interior should also reduce the level of detail needed for environmental compliance, eliminate EiSs for development wells/fields, and increase use of categorical exclusion reviews.
Some forest areas, like Custer National Forest, should be opened for leasing, Rmoga said.
The association hopes Interior will ask Congress to review legislative options for speeding up leasing and permitting in high potential areas.
It contends Interior should also set goals to hike present leasing to historic levels, to be determined by BLM.
The department could reach those goals, Rmoga contends, by setting a priority for each state or forest office and goals for issuance of leases and permits.
BLM also could boost its minerals staff for leasing, permitting, and production in all areas, Rmoga said.
OTHER FEDERAL SOLUTIONS
There are other, broader ways in which government could spur greater production, Rmoga said. They include:
- Extending relief to states with arbitrary allowables on high production wells.
- Lifting moratoriums and bans on exploration and development, onshore and offshore.
- Doing away with archeological clearances for development wells.
- Dropping permit requirements for some workovers, such as hydraulic fracturing, recompletions, and casing repairs.
- Asking Congress to speed up endangered species analysis by removing the 90 day consultation period and allowing land management agencies to do them in house.
- Making BLM responsible only for federal lands directly affected in proposals where federal lands are grouped with state and private lands.
- Extending royalty relief to leases with sliding scale royalties and subsidizing reentry of abandoned marginal wells. For instance, Rmoga claims, reducing royalty rates as much as 50% on marginal production from federal leases would "greatly assist the continued economic viability of crude oil production."
- Convincing states to provide royalty relief and some exemption from severance and ad valorem taxes.
- Pressing tax credits for exploration and enhanced recovery.
- Urging BLM to expedite processing of permits for drilling, rights of way, special uses, and add unit agreements to that expedited process.
- Instituting a new category under BLM permitting covering reservoir management under which BLM would allow rate of withdrawal to exceed injection rates and volumes in secondary and tertiary recovery projects, allow waterflood injection rates to exceed parting/fracking pressures, and institute infill drilling for rate acceleration.
WELL SERVICING CONSTRAINTS
With many of the nation's service rigs already busy, Association of Oilwell Servicing Contractors (AOSC) contends slowing declines in U.S. oil production is the best that can be hoped for the next 6 months to 1 year.
AOSC Pres. Max Emmert said the only possible way to quickly increase U.S. oil production involves reperforating, fracturing, or acidizing wells.
He said many wells are available as good candidates for stimulation treatments. With oil prices nearly double those of a month ago, workover costs would pay out twice as quickly.
But since January, many producers already had begun returning to production marginal stripper wells shut in because of minor lift problems that could be solved quickly, Emmert said.
That in turn already is limiting the number of service rigs available for stimulations, he said.
According to AOSC surveys, 61% of U.S. service rigs are working, or 3,522 of 5,733 rigs available.
However, there continues to be a shortage of trained crews, Emmert said.
Service rigs in California and West Texas are near 100% utilization for the number of hands available, he said.
"At most, 4,000 service rigs could be manned nationwide," Emmert said.
He thinks an oil price of $20/bbl would be enough to encourage operators to continue working over wells.
"Stable prices of $22-25/bbl would stimulate drilling," he said.
DRILLING RIG CONSTRAINTS
However, even if oil producers had enough ready cash, damage to the U.S. industry infrastructure and a shortage of trained personnel will limit drilling increases the next 18 months, according to International Association of Drilling Contractors (IADC).
IADC Pres. Jim Day estimated drilling contractors would begin running out of experienced hands if the number of active rigs reached a level of 1,100-1,200.
Day said the supply infrastructure in the U.S. has deteriorated to the extent that delivery of 5 in. drill pipe and heavy rig components takes 8 weeks and new mud pumps 12-14 weeks.
Confidence among U.S. producers has been severely shaken by low oil prices and fears of oversupply on world markets ahead of the crisis, he noted.
"We don't have the infrastructure or the mindset needed for a substantial activity increase in the U.S. near term," he said. "I just don't see it occurring overnight."
Joe McMahon, president of the National Stripper Well Association (NSWA), said most of the 17,000 stripper wells plugged yearly since 1985 are lost permanently.
"A few producers might have gotten an exemption to shut them in without plugging, but we don't have any figures on what could be increased," McMahon said.
McMahon blasted the federal government for failing to enact a cohesive national energy policy since the Arab oil embargo in 1973-74.
"It has resulted in the dismantling of the domestic oil and gas industry," he said.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.