G. Alan Petzet
Exploration Editor
Federal tax credits and horizontal drilling technology are fueling a large slice of onshore development in the U.S.
So many profitable development prospects are available that exploratory drilling has sunk to the lowest level in recent years in many areas.
Total drilling is picking up a little from 1989.
The number of drilling permits issued in March rose 11.1% from February 1990, with the biggest increases in California and Texas. The first quarter figure, adjusted for differing numbers of filing days in each month, is 25% above the 1989 level.
But the outlook would be dismal without coalbed methane and other nonconventional gas prospects and horizontal drilling.
For instance, more than half of Rocky Mountain gas well completions in 1989 were in three fields: Basin and Ignacio-Blanco fields in the San Juan basin and Wattenberg field in the Denver basin, Petroleum Information Corp. reported. The San Juan completions were heavily weighted toward coalbed methane.
Coalbed methane drilling is at fever pitch there and in Alabama's Black Warrior basin, although production is still low as well dewatering continues. Antrim shale nonconventional gas is the target for by far the largest number of wells in Michigan.
About 70 horizontal wells produce 7% of North Dakota's oil.
February Texas Railroad Commission figures show that South Texas counties with growing oil production from horizontal Austin chalk drilling aren't threatening the West Texas counties kept on top by carbon dioxide assisted oil production.
However, tax credit supported tight sands drilling in sprawling Carthage and Waskom fields vaulted Panola County to the state's fourth largest gas producing county in February, latest month for which figures are available. The credit is scheduled to expire after May 1991.
Surpassing Panola County's 14.84 bcf/month were Pecos, Webb, and Zapata counties.
LAS ANIMAS ARCH
An oil play tied mainly to Pennsylvanian Morrow channel sandstone in southeastern Colorado is still going strong in its fourth year.
Union Pacific Resources Co. (UPRC), Fort Worth, the major participant, said low well costs and relatively high production rates allow well payout to occur in as little as 2 months.
UPRC plans to participate in 70 exploratory and 60 development wells in 1990.
The company participated in more than 200 wells in 1989 in the area, centered on Cheyenne County, Colo., which it calls an extremely economical play. UPRC's combined exploratory/development success rate in 1989 was 47%.
The company produced a net 8,000 b/d of oil in the area during 1989, although production is restricted in some fields until secondary recovery projects start.
Most production is from Morrow channel sandstones at 5,100-6,200 ft. Economic production is also present in secondary objectives such as the Keyes member of Morrow and Pennsylvanian Marmaton formations.
Drilling time is about 1 week/well. Completed well cost is less than $300,000/well, including about $90,000 for drilling.
Frontera and Arapahoe units in the Stateline trend were formed May 1 and Dec. 1, 1989, respectively.
Gas reinjection began Sept. 30, 1989, in Frontera field. Waterflooding is to start in mid-1990 in Arapahoe Unit.
Unitization negotiations are under way for the rest of the trend, and more secondary projects are anticipated.
UPRC shot about $4 million in proprietary seismic in the past 12 months south of Mount Pearl-Sianna and west of the Stateline trend, said George Lindahl III, vice-president of the exploration group.
UPRC has drilled 16 wildcats in this area during first quarter 1990 and hopes to continue that pace the rest of the year. The effort has yielded one discovery, which the company has not announced. An offset is to be spudded, probably this month.
TXO Production Corp. opened Harker Ranch field at the north end of the Stateline trend in March 1989, and UPRC followed up with a multiwell development program.
PI said at least 18 dry holes have been drilled in the effort to delineate the field.
Extending Morrow production south from the Stateline trend, Carr Exploration, Dallas, opened Jace field in Kiowa County, Colo., with two completions in 1989.
Amoco Production Co.'s 1 Moore-Johnson opened Moore-Johnson field pumping 522 b/d of oil from Morrow at 5,136-64 ft.
Amoco also completed a Morrow well 2 miles south of 1 Moore-Johnson and was testing two Morrow prospects, one in Kansas and one in Colorado, between Moore-Johnson and Jace fields.
Mull Drilling Co. and Murfin Drilling Co. are also active in the area.
HUGOTON DEEP DRILLING
Several operators are taking advantage of infill drilling in Kansas Hugoton gas field, permitted beginning in 1987, to evaluate deeper producing formations.
Anadarko Petroleum Corp., with interests in 625 gas wells in the Kansas part of Hugoton field, participated in 50 deep tests in 1987-89.
Anadarko said a major economic advantage is the ability to drill a deep test with a known secondary completion zone in the field's regular Permian Chase group gas pay that can be completed if the deep test is unsuccessful.
By yearend 1989, 14 deep discoveries had been successfully completed, and 12 offset or development wells had followed.
Most of Anadarko's 1989 Hugoton deep discoveries have produced 1-1.5 MMcfd/well from various members of Morrow.
Stirrup field, Morton County, Kan., which resulted from the Hugoton deep exploration program, at yearend 1989 was producing 5.4 MMcfd of gas and 72 b/d of oil from six Morrow wells.
One Stirrup field well, USA P-1, separated by a fault from other wells in the field, is capable of producing 3.4 MMcfd of gas from Morrow.
MICHIGAN ANTRIM GAS
A play driven partly by a federal nonconventional gas tax credit is fractured Devonian Antrim shale gas in Michigan.
Antrim produces 25-150 Mcfd/well from about 1,500 ft. Other factors in the play include an unusually high success rate, low finding costs, proximity to gas markets, existence of pipeline infrastructure, and a relatively stable gas market.
About 145 of the 217 holes drilled in the state in first quarter 1990 were to Antrim. Only eight Antrim holes were drilled in first quarter 1988.
Northern Michigan Exploration Co. (Nomeco) calls the play one of the company's four building blocks. The other three are the Gulf of Mexico, Ecuador, and acquisitions.
It plans to have participated in more than 200 Antrim wells at a cost of $13.1 million in 1990, the last year for drilling under the tax credit unless extended by Congress.
By the end of 1990, Nomeco expects to have participated in 480 wells capable of Antrim production. It expects Antrim reserve additions to exceed a net 63 bcf by that time.
By the end of 1989, it had participated in 227 Antrim wells, of which 151 were on production at an average rate of 27 Mcfd/well.
Gas rates are increasing as the formation is dewatered by gas lift or downhole pump. Within a few months to a year or more, gas will be capable of unloading formation water without mechanical assistance.
An estimated 700-800 Antrim wells are hooked up and capable of producing a combined 40-50 MMcfd of gas.
ARKOMA BASIN
The Arkoma basin is expected to have big years for drilling in 1991-92.
A search for gas in Cambro-Ordovician Arbuckle is under way in earnest on the Oklahoma side of the basin and promises to erupt shortly in Arkansas.
ARCO Oil & Gas Co. in March completed its 12th Arbuckle producer in Wilburton field, which had produced about 78 bcf of gas from 10 Arbuckle wells through December 1989. The Wilburton Arbuckle discovery was completed in late 1987 in Latimer County.
ARCO recently dedicated field gathering and dehydration facilities and is drilling several more development wells in Arbuckle and Pennsylvanian zones.
The company spudded an Arbuckle wildcat, 1 Ulysses, in September 1989 south of Wilburton field that probably set a basin drilling depth record, although information isn't being released.
Amoco may vie for the depth mark at 1 Devil's Backbone, a planned 22,500 ft wildcat to Cambrian Reagan in LeFlore County.
Active Arbuckle exploratory wells stretch along an 85 mile front from Amoco's well to Texaco USA 1 Burnett Estate in far southwestern Pittsburg County.
Pennsylvanian discoveries continue to be completed along buried thrust faults in what became known as the Pennsylvanian Spiro-Wapanucka play.
Exxon Co. U.S.A. last month completed 1-B Retherford, in Latimer County, flowing as much as 13.5 MMcfd of gas through a 20/64 in. choke with 1,478 psi flowing tubing pressure from Spiro perforations at 13,338-365 ft.
The discovery is about 1 mile northwest of Exxon's 1 Retherford, a 19,046 ft dry hole completed in 1983.
Not shown on the map are numerous other exploratory and development wells in progress to Spiro, Wapanucka, and Pennsylvanian Cromwell at 13,000-15,000 ft, especially in Pittsburg and Latimer counties.
ARKANSAS ACTION
This year and next also will be busy ones in northwestern Arkansas.
Nomeco has been conducting a geological study of the Arkansas portion of the basin with emphasis on Arbuckle potential and has begun working with a partner, Yates Petroleum Co.
Nomeco-Yates, with about 50,000 net acres in the basin, is evaluating prospects for drilling in 1990 with objectives ranging from Pennsylvanian channel sands to fractured Arbuckle carbonates.
UPRC holds 120,000 acres of mineral rights in western Arkansas along Missouri Pacific railroad rights-of-way. TXO Production Co. had rights to explore the acreage the past 7 years but recently returned full control to UPRC.
The acreage is prospective for shallow Pennsylvanian and deep Arbuckle objectives.
UPRC is not likely to drill an Arbuckle wildcat in 1990 but because of the acreage position is capable of responding quickly if another company makes a discovery near its acreage, Lindahl said.
It is preparing two Arbuckle prospects for possible drilling in 1991.
Pennzoil Exploration & Production Co., Anadarko, and others plan to drill a deep Arbuckle feature known as East Danville Prospect in Yell County, but timing hasn't been announced.
A joint venture that includes Toreador Royalty Corp., Dallas, acquired more than 14,000 acres of leases in the past year on eight seismically defined Arbuckle prospects in Arkansas. Many of the prospects, which range in depth from 8,500 ft to 16,500 ft, are also prospective for Pennsylvanian objectives.
GREEN RIVER BASIN
Development and exploration are picking up in Green River basin mainly to support the planned Kern River and Wycal gas pipelines to California.
Infill drilling will provide some throughput for the pipelines, but Lindahl said UPRC expects to maintain a very active exploratory program in the basin the next 2-3 years on more than 1.8 million acres it controls there.
The exploration objectives include a Cretaceous Dakota play at about 18,000 ft and several pay zones at 8,000-12,000 ft.
UPRC has two unannounced discoveries in the area waiting for completion testing and offset drilling, Lindahl said.
UPRC received state approval in early 1989 to drill a second well on each 640 acre unit on which it has a producer in the Moxa Arch area.
In its application, UPRC estimated original gas in place, mainly in Cretaceous Frontier, in a 100 sq mile area in Lincoln, Sweetwater, and Uinta counties of 14.5 bcf/640 acres. It estimated recovery for the entire area at 780 bcf with two wells per square mile compared with 460 bcf with one well per square mile.
The area consists of parts of Bruff, Verne, Fabian Ditch, Wilson Ranch, and Church Buttes fields.
PARADOX BASIN
In Paradox basin, Magellan Petroleum Corp. and partners in the Navajo joint venture were testing a third southeastern Utah discovery in early May.
The 1 Cajon Mesa was flowing at rates of 300-600 b/d of oil and 5 MMcfd of gas through a 28/64 in. choke with about 1,300 psi flowing tubing pressure from two zones in the Pennsylvanian Desert Creek member of the Paradox formation.
Net pay in the two zones totals 36 ft between 6,080 ft and 6,128 ft.
The shallower Pennsylvanian Lower Ismay member also yielded good oil and gas shows and will be tested later.
The joint venture's two earlier discovery wells, 1 Anasazi and 1 Saghzie, in the southern portion of giant Aneth field, and 1 Cajon Mesa, 2 miles northeast of Aneth, are producing oil from algal reef mound buildups common in the basin.
Production from Cajon Mesa is expected to boost production to more than 1,000 b/d of oil.
In early May, the joint venture was drilling 2 Monument, a Desert Creek-Lower Ismay wildcat 1 mile south of Cajon Mesa, and 2 Tower, an Upper and Lower Ismay wildcat 5 miles east-northeast of Cajon Mesa.
The joint venture is exploring 254,000 acres of Navajo lands in Utah, Arizona, and New Mexico.
It has also reworked several old wells and completed two new ones in northeastern Arizona's Black Rock gas field, where it plans to hike production to 20 MMcfd of gas from about 11 MMcfd.
Also on the Utah side of the Paradox, Ampolex (Texas) Inc. and Celsius Energy Co. are pursuing several objectives. They staked 43-1 Federal in San Juan County to 7,000 ft or Akah.
The wildcat is 4 miles southeast of Bug field, which produces from Ismay and Desert Creek, and about 7 miles northwest of Ampolex 2 island Butte in Dolores County, Colo.
That discovery well flowed 1,461 b/d of oil and 1.3 MMcfd of gas on a drillstem test of Lower Desert Creek at 6,165-6,203 ft in April 1990.
BASIN AND RANGE
High levels of drilling are expected in Nevada after the state had a good year in 1989.
Gary-Williams Oil Producer, Denver, was drilling toward 8,000 ft at a 1 mile northwest offset to an indicated discovery in Pine Valley.
The indicated discovery well, 25-A Three Bar Unit, 3 miles northwest of Blackburn field, is believed to have flowed 50 b/d of oil from Miocene Humboldt at 4,344-84 ft and encountered three other prospective pays. The operator had not confirmed the information by mid-May.
Gary-Williams has also staked locations for two wildcats within about 8 miles south of the indicated discovery.
Meanwhile, Foreland Corp., Golden, Colo., farmed out northern Pine Valley acreage to J.R. Bacon Drilling Inc., Shelby, Mont., which is required to drill seven wells on the acreage by yearend 1991.
Bacon is required to drill three development wells to the Tertiary Indian Well formation at about 2,000 ft in Tomera Ranch field and four new field wildcats to Paleozoic targets at 4,000-5,500 ft.
One of the wildcats will be north of Gary-Williams's indicated discovery.
MADDEN DEEP UNIT
No drilling occurred last year in the Wind River basin's Madden Deep Unit in Fremont County, Wyo., but Louisiana Land & Exploration Co. says it made much progress in formulating future development plans.
A gas treatment plant is to be installed in 1991 to treat sour gas from the Mississippian Madison formation, tapped below 20,000 ft by the 1-5 and 2-3 Bighorn wells in 1985 and 1988.
The working interest owners also plan a long term production test of one of the previously drilled Madison wells and infill drilling in the shallower horizons.
Several new pipelines have been proposed for the area, and LL&E expects gas production from Madden field to expand as current transportation bottlenecks are relieved.
DIRECTIONAL EXPLORATION
Several operators are using directional and horizontal drilling technology for exploration in various basins.
In North Dakota, horizontal Mississippian Bakken wells were producing an estimated 7,000 b/d of oil in early May.
Meridian Oil Inc., Houston, operates 28 of the wells, and numerous other operators have completed Bakken horizontal wells or are entering the play.
UPRC has about 70,000 net acres in the Williston basin, centered on Dunn County, N.D.
It plans to participate in six gross Mississippian Bakken horizontal wells starting in summer 1990.
It will drill five wildcats horizontally to Cretaceous Niobrara at about 8,000 ft in southeastern Wyoming and northern Colorado starting this summer.
UPRC's exploration department also drills the company's first well or two in each locale in the Austin chalk of Texas, even if vertical producing wells are nearby.
The company keeps exploratory and development costs separate in order to assess finding costs in the chalk.
At yearend 1989 UPRC had 69,000 acres in the chalk, including 36,000 acres held by production. By early May it held 135,000 acres of leases and was reviewing terms on a further 30,000 acres committed to UPRC, mostly in the greater Giddings area.
Fractured Niobrara is the objective at Oryx Energy Co. 10-36 Tow Creek Unit, in Routt County, northwestern Colorado.
The well, to be bottomed about one-half mile south of Grassy Creek oil field, is to have a true vertical depth of about 6,500 ft with a measured depth of 8,000 ft.
HORIZONTAL DEVELOPMENT
Horizontal drilling is being conducted in numerous formations onshore and isn't meeting with success everywhere.
Marathon Oil Co., which has been drilling relatively short laterals from old Ordovician Trenton-Black River wells in Michigan for about 3 years, has experienced mixed results from the program, Michigan's Oil & Gas News reports.
It drilled a 170 ft lateral in 1987 from a 1 b/d well in Albion-Scipio field. Flow jumped to 137 b/d of oil, and 18 months later the well was still capable of about 88 b/d of oil.
However, a 75 ft lateral drilled from 2 Rossman Unit in an adjacent township resulted in average production rates of 2-3 b/d in late 1989 after a foamed acid treatment.
The well produced no oil and 2 Mcfd of gas at yearend 1988.
Marathon has also tried drilling short laterals in Stoney Point Trenton-Black River field and hasn't given up on the technique.
COALBED METHANE
Operators hope Congress will extend beyond Dec. 31 the time to drill coalbed methane wells under the nonconventional fuels tax credit.
The credit, presently about 850/Mcf of gas produced, applies through the year 2000 for wells drilled by yearend 1990, unless the drilling period is extended.
Cumulative Black Warrior basin coalbed methane production is about 100 bcf of gas since 1984. Alabama fields are producing about 20 bcf/year, and more fields are starting up.
About 1,000 permits to drill coalbed methane wells were issued in Alabama last year.
Industry sources estimate that about 400 coalbed methane wells were drilled in the San Juan basin in 1989 and a similar number will be drilled this year, all to Cretaceous Fruitland coals.
Gas in place is estimated at as much as 50 tcf in Fruitland and a further 22-34 tcf in deeper Cretaceous Menefee coals, which have no commercial production.
The San Juan basin remains the focus of coalbed methane drilling among western basins, but work is spreading to many other U.S. basins that are far less developed for coal seam gas than the San Juan.
Barrett Resources Corp. is working in the Piceance basin on multiwell drilling programs to Tertiary and Cretaceous zones, including Cameo coal seams.
Pennzoil Exploration & Production has set casing in at least 11 coalbed methane wells in the northeastern New Mexico portion of the Raton basin 25-30 miles northwest of Cimarron, N.M.
Pennzoil's multiwell program in the area is evaluating Raton and Vermejo coals at about 2,000 ft. Meridian Oil Inc. is also working the Vermejo and Raton coal seams in Las Animas County, Colo., about 25 miles southwest of Trinidad.
Fuel Resources Development Co., Denver, is conducting a program in the northwestern Sand Wash basin in Carbon County, Wyo.
Target is coal in the Almond formation at 1,500-3,000 ft.
Betop Inc., National Cooperative Refinery Association, Martens & Peck Operating Co., and Coastal Corp. are developing coalbed methane reserves in the Powder River basin.
Betop's initial project, 7 miles northwest of Gillette, Wyo., in Campbell County, produces from about 140 ft of subbituminous coal in the Paleocene Fort Union formation.
Equitable Resources Inc., Pittsburgh, plans to drill as many as 55 new coal seam wells in 1990 on its acreage in Dickenson County, W. Va., based on the success of the first 14 wells.
Oxy USA Inc. is working at a program of three wildcats to Pocahontas No. 3 coal at about 2,300 ft in Vansant quadrangle, Buchanan County, Va.
Several operators are completing coalbed methane wells near Independence, Kan.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.