Bob Tippee
Managing Editor-Economics and Exploration
Bob Williams
Senior Staff Writer
Offshore exploration and development activity is growing in the shrinking U.S. area where it is allowed.
The Gulf of Mexico remains the nation's busiest offshore drilling arena. Brisk leasing during the past several years, the need to replace rapidly depleting natural gas reserves, and the promise of world class oil reserves in water deeper than 1,000 ft drive the action.
Off Alaska and California, environmental concerns have stymied development of oil fields that rank among the biggest U.S. oil discoveries of the 1980s.
Exploration remains largely moribund off California, but wildcat action is beginning to pick up again off Alaska. Of prime concern there is replacement of declining production from North Slope fields.
Antidrilling pressures, intensified by the Exxon Valdez tanker spill off Alaska last year, restrict activity elsewhere on the Outer Continental Shelf. Federal leasing of areas off the East and West coasts has essentially ceased (see story, p. 74). Even drilling on existing leases is in jeopardy.
An official at Mobil Oil Corp., for example, says he doesn't expect drilling to begin before next year on a wildcat that would be the first in federal waters off North Carolina. Mobil originally hoped to spud the Manteo Block 467 well, in 2,700 ft of water 47 miles off Cape Hatteras, last month.
Despite extensive environmental safeguards in its exploration plan-including a proposal that an oil spill response vessel remain on station throughout drilling-Mobil has encountered fierce opposition.
It has made a number of concessions to environmental concerns. At present, the Minerals Management Service is revising an environmental study needed before drilling can begin.
LEASING WORRIES GROW
Gulf of Mexico operators worry more about possible leasing limits than about anything else.
Most attribute the current drilling surge greatly to the areawide leasing system inaugurated during the Reagan administration. The system enables them to work the gulf as a basin.
But the Bush administration Interior Department has hinted at a change, perhaps a return to a tract nomination scheme.
Gulf operators express more concern about that prospect than about other potential drags on activity such as stubbornly low natural gas prices and tightening supplies of equipment and workers.
"We're very concerned that we'll see a limitation in (leasing of) the Gulf of Mexico in any way," says Jim MacKay, Texaco U.S.A. offshore exploration division manager of the eastern E&P region. "Little of the Gulf of Mexico can be eliminated as nonprospective."
Operators "find and produce more oil and gas using the system we have right now," says Mike Coffelt, Phillips Petroleum Co. exploration manager for North America.
Most operators think fears of future leasing restrictions heated the bidding in the last areawide OCS offering, Sale 123 of areas off Louisiana, Mississippi, and Alabama last March.
The sale, in which 96 companies offered $589,547,008 in 840 bids for 538 tracts, demonstrated another benefit of areawide leasing.
The system provides opportunities to large and medium-sized independent companies-such as Union Texas Petroleum Corp., Maxus Energy Corp., and Adobe Resources Corp., all of them active in Sale 123-that can't compete as readily with big major companies in a tract-by-tract scheme.
The sale also demonstrated a characteristic of current Gulf of Mexico work: The deep (greater than 600 ft) and ultradeep waters (greater than 1,000 ft) attract most of the attention because of the technological feats performed there; the shallower gas-prone waters of the shelf get most of the lease bids and drilling rigs.
The number of deepwater tracts receiving bids dropped to 168 in the most recent sale from 192 last year and 293 in 1988.
DRILLING UP
Gulf-wide, drilling is up sharply from a year ago.
Baker Hughes Inc. reported 81 rigs making hole off Louisiana the week of May 7 vs. 57 a year earlier. It tallied 30 rigs off Texas vs. 20 the previous year.
The increase comes despite failure of gas prices to increase as expected this year. Most operators say they're disappointed with gas prices so far this year but still expect improvement longer term.
"We work off longer term price projections," says Jack Golden, BP Exploration Western Hemisphere vice-president and general manager of exploration. His company is active both in the ultradeep water and on the shelf.
M.E. Wiley, southern district vice-president for ARCO Oil & Gas Co., says, "There can still be a lot of attractive opportunities out there" at current prices.
David Hunt, president of CNG Producing Co., says there's "a substantial amount of gas shut in. It may be a tough summer." But he expects prices to "come back a bit."
His company, which is concentrating on gas prospects in the deeper Miocene pays in shallow water, sees "more opportunities than we have funds available right now" due to recent pipeline investments by CNG's parent.
The drilling increase is beginning to strain supplies of some types of rigs-mainly floaters capable of drilling in deep water-boats, and crews.
"In general, the market's just tightening up for deepwater rigs," says R. L. Howard, president of Shell Offshore Inc. "I don't think it's a crisis."
CNG's Hunt says day rates for jack ups climbed to $15,000 last November and December from about $11,000 last summer. He says companies held back drilling funds during the first part of 1989 seeking acquisitions, then spent the money drilling late in the year.
Jack up day rates have settled back to about $13,000, he says.
WHAT'S PLANNED
Among some of the largest operators, drilling emphasis is tilting toward exploration.
Exxon Co. U.S.A. proposes to operate 11 gross wildcats in the gulf this year, compared with seven drilled last year, says Richard Brown, geological manager for offshore. Of this year's wildcats, six will be on the shelf (generally, water shallower than 600 ft), five on the slope. Last year the company operated three wildcats on the shelf and seven on the slope.
Development drilling will slip to 30 gross wells from 37 in 1989, with all but three of this year's total on the shelf. Exxon plans to operate four outpost/delineation wells this year, down one from last year.
Shell Offshore plans to keep two rigs drilling wildcats in deep water and two drilling wildcats on the shelf through the year.
In ultradeep water, BP Exploration has plugged and abandoned one 100% working interest well, is logging a probable discovery in more than 2,300 ft of water on Block 160, and plans two more this year. With partners it will drill three wells this year in more than 3,000 ft of water.
Phillips's gulf exploration activity as "way up" this year, says Coffelt. The company plans 12-15 rank wildcats, most on the western shelf and 4-5 in the central gulf.
ARCO Oil & Gas plans 43 exploratory wells and 30 development wells, up slightly from 1990, says Wiley. It will set two platforms this year and is building four to set early in 1991.
Texaco U.S.A. will participate in 12 rank wildcats and 36 onstructure wildcats this year-"significant increases" from last year, says MacKay. The company will participate in about 65 development wells, the same as last year.
Most of Texaco's rank wildcats will be on the shelf to waters as deep as 800 ft. The company has participated in one ultradeep wildcat in the past 12-14 months but plans to return to ultradeep exploration in 1991.
CNG plans 16 gross wildcats (8.6 net) this year vs. 10 gross (6.3 net) in 1989. Development drilling will slip to 14 gross (5.3 net) from 23 (8.7 net) last year.
Maxus Energy plans 9 exploratory wells this year, up slightly from last year, says Earl Ritchie, vice-president of exploration. Its exploration budget, however, is up about 30% because it is taking larger working interests.
"We don't like what we've seen so far this year" in gas prices, says Ritchie, whose company concentrates on Miocene gas on the shelf. But he's still optimistic about the gulf gas play.
"We think it'll be active for some years to come."
NORPHLET TREND DEVELOPMENTS
Development projects are blooming outside the ultradeep waters of the gulf, the most significant of which at present are in the Jurassic Norphlet trend off Alabama.
Mobil Exploration & Producing U.S. Inc. has the area's only producing field-Mary Ann field in state waters of Mobile Bay. It plans to double Mary Ann output to 80 MMcfd this year with two new wells and a new production platform.
And last fall it obtained Minerals Management Service approval of a six well, 250 MMcfd development plan for federal Mobile Blocks 822, 823, 824, 778, and 779.
In that project it will install three offshore platforms and build a 250 MMcfd gas treatment plant next to Mary Ann field's facility near Coden, Ala. (OGJ, Oct. 9, 1989, p. 24).
Also in the Norphlet trend, Exxon U.S.A. plans to develop three fields-Bon Secour Bay, Northwest Gulf, and North Central Gulf. It will build a gas treatment plant with inlet capacity of 300 MMcfd in Mobile County (see schedule).
And Shell Offshore has begun work on its 200 MMcfd Yellowhammer gas processing and treatment plant near Mobil's facility as part of development of Fairway field, which it operates in partnership with Amoco Production Co.
It expects completion of the plant in the second half of 1991, with production starting in the fourth quarter.
ULTRADEEPWATER WORK
The ultradeepwater gulf lost a landmark on Apr. 16 when Placid Oil Co. and partners shut down their floating/subsea drilling and production system on Green Canyon Block 29. It was the gulf's first floating production system.
The $400 million operation started up Oct. 13, 1988, when the Ewing Bank Block 999-1 subsea satellite well went on stream in 1,462 ft of water north of the Green Canyon 29 subsea drilling/production template. The satellite set a gulf production water depth record, which fell the next month when Green Canyon 31-4 began flowing in a world record 2,243 ft of water. That record stands.
Loss of the 31-4 well late in 1989 to downhole equipment failure capped the Placid group's decision to halt operations. Sustainable flow rates from the 31-4 well, two other subsea satellite wells, and one template well didn't justify continuation of the project, Placid officials said.
The company planned to mothball in place the project's export pipeline bundle, Ship Shoal Block 207 processing platform, and template. It planned to pull the rigid production riser and recover control systems on the template and the floating platform's mooring system. The platform, Penrod 72, will be removed and mothballed.
Shell Offshore Inc. will break the world production water depth record when flow starts from the 32 slot Auger tension leg platform (TLP) it plans to install in 2,860 ft of water in the southeast corner of Garden Banks Block 426.
The $1.1 billion project will develop Blocks 427, 471, 470, and 426. Shell owns 100% interest. It will be the gulf's first full-scale TLP and the world's second.
Shell expects peak Auger production rates of 40,000 b/d of oil by 1995 and 150 MMcfd of by 2001. Flow is to begin in 1993.
Last month, the Sonat Offshore Drilling Inc. George Richardson semisubmersible spudded the first of nine wells Shell plans to drill prior to TLP installation, scheduled for third quarter 1993. That will give it the option of starting production as soon as the TLP is in place.
Shell Offshore has finished drilling 14 wells from its Platform Bullwinkle in 1,353 ft of water on Green Canyon Block 65 and has two more under way. Five wells are producing about 15,000 b/d through facilities on Platform Boxer 8 miles northwest.
Howard expects drilling of 30-35 wells to be complete in first quarter 1991.
Shell also has drilled 14 of 20 or more wells it plans in its Cognac redevelopment program. It's using two rigs now but will replace one this summer with a completion rig. The platform is in 1,024 ft of water on Mississippi Canyon Block 194.
Howard expects production to start in next year's first quarter. When completion is finished about midyear production will reach 26,000 b/d from about 50 wells.
Cognac originally had 61 wells. Production peaked at about 80,000 b/d in the early 1980s and dropped to 11,700 b/d before shutdown for redevelopment last September.
In April, Exxon Co. U.S.A. announced plans to proceed with two ultradeepwater gas development projects that had been on hold due to low oil and gas prices.
It will develop Mississippi Canyon Block 354 with a multiwell subsea system set in 1,500 water, moving production by pipeline to the Mississippi Canyon 397 platform. Production from the project, designated Zinc, will begin early in 1992.
In the other project, called Alabaster, Exxon will set a conventional platform in 468 ft of water on Block 397 and drill directionally to develop a reservoir under 1,400 ft of water. Exxon first announced the projects in August 1986.
OTHER ULTRADEEPWATER WORK
Placid's experience with rapid production declines isn't unique.
Conoco Inc. unsuccessfully tried high risk completions in low resistivity sands in the multiple pay field it is developing with its Jolliet tension leg well platform (TLWP) in 1,760 ft of water on Green Canyon Block 184.
Flow rates from the shaly and silty sands declined rapidly despite drillstem test results indicating good recovery and high initial results. But those problems don't jeopardize the project, Conoco says.
It plans to develop 50-60 of about 100 pay sands in the field during 20 years. The good sands have performed well.
Jolliet is the world's first TLWP and holds the world platform water depth record.
On Mississippi Canyon Block 109, BP Exploration Western Hemisphere will install the gulf's first conventional four leg jacket in more than 1,000 ft of water. It will set the 1,060 ft jacket in 1,032 ft of water in July 1991 and start production in first quarter 1992.
BP expects output to peak at 20,000 b/d of oil and 20 MMcfd of gas.
Texaco U.S.A. hasn't decided whether to proceed with a TLWP project on Viosca Knoll Block 869 and is studying other options.
"We fully expect that Texaco will be participating in a well in that area this year," says MacKay. He says water depth of the well will be 1,800-2,000 ft.
In the same area, Shell, Amoco, and Exxon continue to discuss development of their Viosca Knoll 912 Unit Ram/Powell prospect. "I still think that's going to be developed," says Shell Offshore's Howard.
Earlier this year, Amoco disclosed a world record water depth flow test in the unit at 1 Sidetrack 2 Viosca Knoll 957 (OGJ, Feb. 5, p. 29). The well flowed 22.5 MMcfd of gas and 2,670 b/d of condensate through a 46/64 in. choke with 2,800 psi average flowing tubing pressure during tests. Water depth is 3,492 ft.
CALIFORNIA ROADBLOCKS
Giant fields proposed for development off Central California represent some of the biggest discoveries in U.S. waters.
Of two major projects currently active, one is on track after years of permitting difficulties.
The other remains stymied by environmental opposition inflamed anew by headline-grabbing oil spills off Alaska and California in the past 15 months.
The main issue hampering both projects has been transportation of Offshore California crude. The state and Santa Barbara County have objected to any increase in tankering in the Santa Barbara Channel.
Their policies require companies to transport offshore oil via onshore pipelines to a refinery of the companies' choice unless such a pipeline is unavailable or technically or economically infeasible.
SANTA YNEZ UPDATE
Exxon is on schedule with plans for further development of fields in the Santa Ynez Unit in the Santa Barbara Channel.
Project go-ahead came with a formal agreement with Santa Barbara County (not an informal commitment, as reported incorrectly in OGJ, Dec. 18, 1989, p. 14) to ship Santa Ynez crude via Celeron Corp.'s All American Pipeline (AAPL) to Texas if the pipeline tariffs are reasonable. The county makes the determination of tariff reasonability.
Exxon currently is tankering production from an offshore storage and treating (OST) vessel in the eastern portion of Hondo field, which produces about 27,000 b/d of oil.
During 1980-87, Exxon shipped Hondo crude to its Baytown, Tex., refinery because its Benicia, Calif., refinery was no equipped to handle the heavy, high sulfur, high metals content crude. During the past 3 years, however, Exxon has cut transportation costs by landing the crude in California, primarily for sale to Los Angeles refineries now capable of handling the crude after recent upgrading projects.
Exxon is working on details of pipelining Santa Ynez crude to Texas. Once those are ironed out and new platforms in the unit are on stream, Exxon will decommission and remove the OST and ship all Santa Ynez crude via AAPL to Texas.
Exxon plans to begin construction this fall of onshore oil and gas processing plants at Las Flores Canyon. It set jackets for Platforms Harmony and Heritage last year and is fabricating topsides for both platforms. Exxon expects to install the topsides in mid-1991.
Drilling on both platforms would begin in mid-1992. Production would start from Pescado field and the western portion of Hondo field by second quarter 1993. Santa Ynez output is expected to reach 90,000 b/d in 1994-95.
POINT ARGUELLO WRANGLE
Point Arguello start-up, delayed now for almost 3 years, may be another 2 years away.
Again, the key problem is transportation of Arguello crude. A group of 18 companies led by Chevron Corp. has been unsuccessful in starting up flow from three Point Arguello platforms that could reach 100,000 b/d in the mid-1990s.
After wrangling over various permit concerns for 2 years while the platforms sat idle, costing $500,000/day in interest, Chevron received in 1989 a permit for interim tankering to Los Angeles from Santa Barbara County. But local groups appealed that permit to the California Coastal Commission, which voided the permit amid the uproar following the Exxon Valdez oil spill.
Chevron and partners sued to overturn the CCC decision and refiled their permit with the county while conducting a study of transportation alternatives. That study, by Arthur D. Little Inc., sparked the controversy afresh late last year when it found that the only feasible pipeline alternative available in less than 3 years was AAPL, which it said carried a heavy transportation penalty in comparison with tankering.
Celeron and Four Corners Pipe Line Co. disputed the study with their own proposal for pipelining through existing facilities to Los Angeles.
A subsequent Little study narrowed the gap between tankering and pipelining Arguello crude, but Chevron, the county, and the two pipelines remain at odds. The Santa Barbara County planning commission will issue a final decision, probably in October, on whether a pipeline alternative is feasible for Arguello. Early indications by county officials in response to the Little studies cast doubt on tankering.
Chevron might find a way to accommodate concerns of the county and still keep the Arguello project economic with a commitment to a pipeline while interim tankering proceeds. If so, given tanker construction lead times and other negotiations likely to ensue, Point Arguello could start up in 1992.
ALASKAN CONTROVERSIES
New development projects planned for Alaska's nearshore Beaufort Sea oil discoveries are plagued by uncertainty over the direction of state tax policies and federal environmental permitting.
ARCO may be resolving the tax issues that have hurt development prospects for Point McIntyre field. However, disputes over the use of gravel causeways in the Beaufort Sea and concerns over the direction of federal wetlands policy continue to loom over new development off Alaska.
ARCO and BP Alaska Inc. each have drilled two additional delineation wells in Point McIntyre field in the shadow of Prudhoe Bay production facilities. Reserves are estimated at more than 300 million bbl of oil. Exxon is the other partner in the project.
BP for 2 years has pursued plans for development of marginal 58 million bbl Niakuk field accessible from a 1.25 mile gravel causeway in the Beaufort just east of Prudhoe Bay.
ARCO and BP are continuing to evaluate data from the most recent wells at Point McIntyre, which they hope to bring on stream by 1993.
ARCO is proceeding with permits to construct gravel roads and pads at Point McIntyre, including a drillsite at Dockhead 3 of Prudhoe Bay's West Dock.
Changes in Alaska's severance tax formula last year cast a cloud over Point McIntyre development (OGJ, Aug. 14, 1989, p. 26). ARCO wants to produce the field through existing facilities in nearby Lisburne oil field, but there were questions over whether the commingled production would result in a heavier tax burden for Lisburne and how to determine a tax rate for Point McIntyre.
ARCO is working with the state to determine a method for calculating tax rates for the two production streams. It has proposed using production tests of the Point McIntyre delineation wells while metering Lisburne flow to determine a formula for allocating production for separate tax treatment.
Separately, ARCO thinks the development of an offshore drillsite at West Dock should not be tied to the issue of gravel causeways.
CAUSEWAY DISPUTE
The use of gravel causeways in the Beaufort Sea long has been a point of contention between the federal government and North Slope operators.
Federal agencies, notably the U.S. Army Corps of Engineers, contend the causeways affect water circulation, temperature, and salinity nearshore, inhibiting the passage of fish. That led to installation of breaches in the causeway to Endicott field, currently producing more than 100,000 b/d.
The corps recently raised the issue anew, at first opposing new causeways in the Beaufort and later indicating it would find BP in violation of its permit at Endicott unless BP adds another 1,300 ft of breaching at a cost of about $40 million. There have also been suggestions that the corps might seek to have large breaches installed in the West Dock causeway.
Industry officials contend the causeways are not a problem for marine life and maintain that banning them could squelch all Beaufort Sea development or even possible development in the Arctic National Wildlife Refuge, where a dock similar to the West Dock would be needed to land equipment and the huge modules for development.
After about a year since the original ban was announced and later rescinded (over a procedural error), the corps still has not moved on the causeway issue.
In addition, another federal agency has entered the fray. The Environmental Protection Agency has urged the corps to take some action to resolve the impasse on Endicott. At presstime, it was expected that either EPA or the corps was to announce a decision on the Endicott causeway-reportedly to require BP to add the 1,300 ft of breaching or be found in violation of its permit.
Meantime, Alaska Gov. Steve Cowper has approved BP's plans for Niakuk development. BP had hoped to begin drilling at Niakuk in 1989. Until the Endicott causeway issue is settled, it is unlikely that there will be any decision on Niakuk development.
Also affecting prospective North Slope work is a federal policy taking shape on wetlands. Alaska must be exempt from proposals to require no net loss of federal wetlands in development permitting if North Slope work is to proceed.
Virtually the entire North Slope could be considered wetlands, although industry development could not affect wildlife habitat there, say industry officials.
BEAUFORT EXPLORATION
The western Beaufort Sea will see its first wildcat in more than 5 years.
ARCO and partners Phillips Petroleum Co. and Elf Aquitaine Inc. plan to drill two exploratory wells on the Fireweed prospect 15 miles off the National Petroleum Reserve-Alaska between Point Halkett and Smith Bay.
ARCO plans to move the Canmar single steel drilling caisson to location in August and to spud the first well in early fall, pending permit approval. The well is on farmout from a combine of Shell Western Exploration & Production Inc., Conoco Inc., and Unocal Corp., which acquired the tract in Outer Continental Shelf Sale 71 in October 1982.
CHUKCHI PROGRAMS
Shell is expected to return to the Chukchi Sea this year after drilling one wildcat and starting two others there in 1988-89.
Shell plugged the first test, on the Klondike prospect in 140 ft of water off Icy Cape (see map, OGJ, Mar. 27, 1989, p. 27).
Shell suspended the second Chukchi test, Burger, after drilling to about 5,500 ft in about 145 ft of water. It drilled the third, Popcorn, to 545 ft before suspending for the onset of ice encroachment.
Beginning about mid-July, Shell plans to reenter and finish drilling both wells this summer. The company has a permit for a wildcat on a fourth prospect, Crackerjack, depending on the ice season.
Shell has the Canmar Explorer III ice strengthened drillship under long term contract for the Chukchi campaign.
Uncertainty over ice encroachment frames the length of the Chukchi's weather window, according to Clarence Cazalot, Texaco Inc. general manager for frontier exploration.
"In 1988, we had the worst ice year ever in the Chukchi Sea. In 1989, we had the second best year in the past 20 years," he said.
Texaco has submitted to Minerals Management Service an exploration plan and an oil spill contingency plan for its Chukchi Sea campaign.
The plans cover as many as 51 drilling locations on 13 prospects. Drilling depths are 9,000-15,000 ft.
The first well is to spud in early July 1991 on the Diamond prospect. Site is in 150-170 ft of water about 50 miles off Northwest Alaska, 120 miles west of Point Barrow.
Texaco plans to use the Beaudril Kulluk conical drilling vessel for its Chukchi wells.
Its partners in the program are ARCO, Chevron, Unocal, American Petrofina Inc., Murphy Oil Corp., and Ocean Drilling & Exploration Co.
If ice conditions allow, Texaco would spud a second Chukchi well to probe the Tourmaline prospect farther west, about 80 miles offshore. Site is between Shell's Popcorn and Klondike wells.
Both wells are permitted to 15,000 ft.
Cazalot estimates individual well costs in the Chukchi Sea at $50-70 million.
He noted the wide variety of structural plays in the Chukchi, including domal structures, faulted anticlines, and truncation traps.
"The beauty of exploration in the Chukchi is that there is a multitude of opportunities out there. If one doesn't work, that doesn't mean the next one won't," he said.
COOK INLET PLANS
Alaska's Cook Inlet will see something of an exploratory revival this year.
A major concern for operators there, however, is Redoubt volcano, which earlier this year shut down Cook Inlet operations when eruptions hampered shipping at the Drift River terminal.
Conoco plans to slant drill a prospect in Cook Inlet from an onshore lease near Trading Bay field.
Independent Stewart Petroleum Co., Anchorage, plans a $6-7 million wildcat to tap a prospect on native land southwest of McArthur River field in Cook Inlet. Plans call for a 15,000 ft test directionally drilled to the prospect south of shut-in West Foreland gas field.
In addition, ARCO may drill a Cook Inlet basin offshore wildcat between Kalgin Island and the mouth of Drift River.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.