U.S. OIL FLOW HIKE UNLIKELY OUTSIDE W. COAST

Oct. 15, 1990
There is little chance major producing states or offshore areas outside the West Coast can hike U.S. oil flow significantly within 1 year. Prospects of increased oil production in states outside the West Coast aren't much improved for the 5 year outlook, either. Those outlooks are likely even if oil prices remain high as a result of an oil supply shortfall or continuing tensions stemming from the crisis that has followed Iraq's blitz of Kuwait.

There is little chance major producing states or offshore areas outside the West Coast can hike U.S. oil flow significantly within 1 year.

Prospects of increased oil production in states outside the West Coast aren't much improved for the 5 year outlook, either.

Those outlooks are likely even if oil prices remain high as a result of an oil supply shortfall or continuing tensions stemming from the crisis that has followed Iraq's blitz of Kuwait.

U.S. industry officials cite a lack of confidence and shortages of investment capital, trained personnel, and workover rigs as factors that all but wipe out the possibility of a sizable short term increase in oil production in key Gulf Coast, Midcontinent, Midwest, and Rocky Mountain regions.

What's more, industry in those states won't see a significant contribution in the next few months from two areas of activity getting a lot of attention from federal energy planners: horizontal drilling and enhanced oil recovery.

Those four regions of the country account for more than half of U.S. production. However, they could account for only about 18% of a projected increase of 424,280 b/d in U.S. production within 1 year, according to a survey of producing states by the Interstate Oil Compact Commission. The balance of that increase would come from Alaska and California (OGJ, Oct. 1, p. 38).

Production gains among states offering a 5 year forecast in the IOCC survey would total 246,250 b/d by 1995. California accounts for 225,000 b/d of that total, assuming Point Arguello oil field will be on stream and producing at peak.

However, the IOCC states' forecasts generally did not indicate whether their production gains were net gains after allowing for natural field declines.

Further, Alaska did not offer a 5 year forecast in the survey. Expected declines in North Slope production alone are likely to outstrip expected gains in the Lower 48 by 1995, absent any about-face in the permitting climate for Alaska and California.

Even a best effort, then, would result in a gross production gain of only about 20,000 b/d by 1995 in major U.S. producing areas outside the West Coast. What is more likely, OGJ projections show, is a slowdown in the rate of decline of U.S. production (OGJ, Sept. 17, p. 21).

HORIZONTAL WELLS, EOR

Horizontal drilling may be a viable solution to boost production eventually, but reducing the number of wells being shut in would provide a more immediate effect, said Bill Pitts, president of Oklahoma Kansas Midcontinent Oil and Gas Association (MOGA).

He said horizontal drilling may not be far enough along to show any dividends by yearend, although there are seven or eight such incremental production wells in Beaver, Beckham, and Kingfisher counties, Okla.

"There are people who think shale formations in southern Oklahoma will have potential for this type of development," Pitts said.

The Oklahoma legislature passed two bills in its most recent session to encourage horizontal drilling. One would provide wider spacing for horizontal wells, and the other would exempt them from the state's 7% gross production tax for 2 years or until payout.

EOR is another possibility, but Pitts doubts the larger tertiary projects could show results in 3 months. Availability of capital and the unstable oil market are problems for EOR,

"A lot of enhanced recovery projects are not feasible at anything under $25/bbl," Pitts said. "If you're going to invest $10-20 million on an EOR project, you're not going to do it on the basis of $25/bbl oil today. You're going to do it on the basis of oil being $25/bbl a year from now, and frankly, who knows?"

TEXAS MER RULE

Texas Railroad Commission official Brian Schaible said it is not known how many wells will be affected by a TRC emergency rule, effective Sept. 1, allowing wells in the state to produce at 100% of their maximum efficient rate (MER).

Texas oil and gas regulators at the time expected the rule to result in a temporary gross jump in production of 20,000 b/d if East Texas field were not included.

TRC officials expect most of the increase to come from horizontal wells in the Cretaceous Austin chalk trend of South Texas. Preliminary production data for August show Austin chalk wells were producing about 16,000 b/d below potential.

TRC records show that in April 1990, wells in Pearsall field in Frio, Dimmitt, Zavala, and LaSalle counties produced 29,319 b/d of oil from Austin chalk, up from 6,951 b/d in October 1989.

Schaible said recent testimony before the commission indicated there is potential for another 400 b/d from Happy Spraberry field in Garza County and 500 b/d from RCR Pettit A field in Gregg County.

However, Texas Independent Producers and Royalty Owners Association's Scott Anderson said, "There are some doubts as to whether we'll achieve an increase of 20,000 b/d."

Brent Allen, Perryton, Tex., president of the Panhandle Producers and Royalty Owners Association, said there isn't much potential to increase production in the Texas Panhandle.

"We've been on 100% allowables for quite some time," Allen said.

Morris Burns, executive vice-president of the West Central Texas Oil and Gas Association, Abilene, said there would be very little if any increased production in West Central Texas as a result of the TRC's emergency order.

"There aren't more than a handful of maximum allowable wells in West Central Texas," Burns said.

TRC at first deferred steps to increase production in East Texas field, where the U.S. Department of Energy hoped the state could add another 10,000 b/d beyond the 20,000 b/d already envisioned.

But TRC upheld East Texas field operators' objections to increasing production in the field because of concerns about damage to the reservoir. Some of the wells on the periphery of the field have been in danger of watering out, and operators feared the increase would speed the process. Accordingly, TRC ordered the East Texas production cap to be held at 86% of MER.

"After 3 months the expected increase will be gone, due to normal decline," TRC's Schaible said. "So by increasing production by 20,000 b/d, we have simply staved off the normal decline for a period of 2 1/2 months."

Texas currently produces about 1.7 million b/d of crude oil and about 80,000 b/d of condensate from state wells and 50,000 b/d from federal waters. OGJ estimates total Texas production for the week ended Sept. 28 at 1.87 million b/d, compared with OGJ's estimate of 1.88 million b/d for the week ending Aug. 31, before the TRC emergency rule took effect.

In 1989, Texas production averaged 1.949 million b/d, according to preliminary OGJ estimates earlier this year (OGJ, Jan. 29, p. 49).

During 1990 through July, the state lost crude oil production totaling more than 39,000 b/d. That's an improvement from last year, when Texas crude output declined an average 8,333 b/d/month.

Texas production has been sliding since 1972, when it peaked at 3.29 million b/d. Even during the record drilling years of the early 1980s, the state's production decline only slowed.

LOUISIANA DECLINE

Mike French, Louisiana Department of Natural Resources director of technical assessment, said production of oil and condensate from Louisiana onshore and offshore wells could not increase beyond the current 423,000 b/d.

"There is the physical fact of the long term production decline curve, in which the drilling frenzy of the 1980s produced only a 1 year bump after sustained high prices," French said.

The state's only deviation since 1970 from a 4%/year decline in oil production occurred in 1984.

That followed 3 straight years of an average oil price of more than $30/bbl in Louisiana. Even then, the rate of decline merely slowed.

Louisiana oil and condensate production from state acreage has been declining since 1970, when it peaked at 1.55 million b/d. In 1988, this production fell to 457,534 b/d.

Louisiana Outer Continental Shelf production peaked in 1972 at 1.063 million b/d. By 1988, it had fallen to 811,000 b/d.

OGJ preliminary estimates place total Louisiana production at 1.158 million b/d in 1989 and 1.034 million b/d the week ending Sept. 28, compared with 1.03 million b/d the week ending Aug. 31.

Louisiana operators mostly had been producing all out ahead of the recent spike in oil prices in order to boost cash flow, but the state had lost many stripper wells to low oil prices, French said.

Apprehension among producers and investors about whether high prices would continue prevented them from committing resources to further drilling or workovers. French said some Louisiana producers thought eliminating Iraqi and Kuwaiti oil from world markets merely brought supply and demand into better balance.

Further, the oil and gas industry in Louisiana won't be able to put many more rigs in the field because too many experienced people have left the industry.

Frank Spooner, president of the Louisiana Association of Independent Producers and Royalty Owners, said there will be no short term increase in drilling in the state because independents don't have a great deal of money to invest in drilling.

"The increase in price will give them some money, and they'll spend it," Spooner said. "But it's just not enough to do what needs to be done, and there's no incentive for any outside dollars to come in."

OKLAHOMA

Boosting oil production in the short term will be a problem in Oklahoma because of the time it will take to deploy tools and manpower, said Oklahoma independent Petroleum Association (OIPA) Executive Vice Pres. Mike Coldren.

Horizontal drilling offers the best hope for increasing production in the next 6 months 1 year, Coldren said. The state also may see some shutin wells brought back on stream if prices stay up.

Much horizontal drilling activity is in Northwest Oklahoma's Mississippian Solid trend, but, Coldren warned, it will take operators some time to figure out how to boost production to the maximum, just as it has in South Texas.

"In Oklahoma, we are facing the same steep learning curve they had in the Austin chalk," he said.

As for hiking production, Coldren believes a more realistic goal would be to arrest the production decline at about 5%/year.

"If we could cut it to zero, that would be phenomenal."

It is unreasonable to hope for much more, he said, because there is no longer the bountiful supply of rigs and manpower Oklahoma had in the early 1980s.

"If the government said, 'We've got to increase domestic production and double the number of rigs,' we would have to call out the National Guard," Coldren said. "We don't have the people and equipment."

Coldren added, however, that if oil prices stabilized at $25-28/bbl, the state could see its drilling rig count surge to about 150 from the current 130 in "a matter of a few months."

KANSAS

Because 90% of the oil wells in Kansas are strippers producing 3 b/d or less, EOR may be that state's best bet to hike oil production, said Don Schnacke, executive vice president of the Kansas Independent Oil and Gas Association (Kioga).

And because the state's taxes are among the highest in the Midcontinent region, Kioga has been active in recent legislative hearings on tax incentives for well stimulations. Kioga also seeks, among other proposals, severance tax exemptions for tertiary recovery projects.

"I think the legislature is going to take a sharp look at what they can do to keep this industry alive," Schnacke said. "I don't think the increase in prices is going to help much."

Higher oil prices will, however, cause some temporarily abandoned wells in Kansas to be worked over, but Schacke doubts it will make much of a dent in the oil production slide under way since 1986. Half the active rigs there are drilling for gas, mostly in Hugoton field in Southwest Kansas.

Sherry Albrit, director of the conservation division of the Kansas State Corporation Commission, does not foresee much increase from the state's current 150,000 b/d average unless prices stabilize.

But one possible bright prospect is a pilot study of five horizontal wells in the Zenith/Peace Creek field, she noted.

MICHIGAN

The outlook for exploratory drilling in Michigan is better than ever, especially in Silurian Niagaran reef in the southeastern lower peninsula, said Michigan Oil and Gas Association Pres. Frank Mortl.

The state, which produced 60,274 b/d of oil in 1989, could see a 10-20% increase in rig activity within 6-12 months, he said.

"Frankly, I think we are going to find a lot more oil as this price increase stabilizes."

There also are possibilities for EOR and workovers, especially in older fields in the Saginaw area, but the main obstacle is the state's unlimited liability oil spill law.

An operator that buys wells with the idea of stimulating them, Mortl said, must weigh an expected production increase against possible liability from prior pollution.

"They are very high here on what they call 'polluter pay' legislation," Mortl said. "The problem is, how do you distinguish between old and new pollution?"

ALABAMA

Jim Bolin, Alabama Oil and Gas Board assistant supervisor, said there are no large volumes of oil behind pipe not being produced in his state.

Alabama could hike liquids production by about 2,000 b/d from 876 oil wells and 120 gas/condensate wells, but that would require 6 months to achieve, he said.

Bolin said preliminary results of a study by the Alabama Geological Survey (AGS) showed a combination of production techniques might increase oil and condensate production by about 8% statewide without damaging formations. The condensate share would be limited by gas processing plant capacity.

AGS expects the increase to come mainly from deep Jurassic Smackover in Scandia, Choctaw, Clark, and Monroe counties.

Citronelle field has about 450 wells in four unitized areas, the largest of which has about 300 wells. Bolin said production of many Citronelle wells qualified them as strippers for the first time in 1989.

"In the past few years," he said, "we have seen a decline in oil production statewide because new oil isn't fully offsetting declines in old production."

Many oil fields in Alabama are one and two well fields, too small to encourage enhanced recovery projects, Bolin said.

MISSISSIPPI

Mississippi State Oil and Gas Supervisor A. Richard Henderson said oil economics has been such in his state that operators shut in many marginal wells rather than work them over.

Mississippi oil production has decreased sharply after peaking 20 years ago. Henderson noted some wells shut in for technical reasons in Mississippi could be reworked, but in some cases the cost of disposing of produced fluids make marginal wells uneconomic.

"People forget that many oil and gas people express their philanthropic tendencies with public service announcements and United Way contributions," Henderson said. "They can't go very long when philanthropy comes to losing money producing a commodity they have to sell."

State legislators have tried to stimulate oil production in Mississippi by exempting EOR projects and other classes of wells from the state severance tax.

MOUNTAIN STATES

Infill drilling and uphole recompletions around Northeast Colorado and Southeast Wyoming hold the greatest potential for added production, said Tom Vessels, president of the Independent Petroleum Association of Mountain States (Ipams).

The lowest risk projects, he said, probably are recompletions in and around Wattenberg field in the western Denver basin.

All the recompletions and new wells in the basin, assuming all operators would go with their best prospects first, would bring in about an additional 40 b/d/well sustainable, Vessels said.

As for hydraulic fracturing in that area, the mostly tight formations could sustain stabilized flow rates of about 510 b/d above prior yields after about 1 year.

Ipams operators have received inquiries about horizontal drilling along the Wyoming-Colorado border in Cretaceous Niobrara shale.

And some financial sources that had earlier been interested in those plays, Vessels said, are getting "real interested" with the prospect of continuing higher oil prices.

Copyright 1990 Oil & Gas Journal. All Rights Reserved.