LOW GAS PRICES SLOW ACTION IN GULF OF MEXICO

A.D. Koen
Gulf Coast News Editor

Fears that low gas prices will persist in the U.S. are putting a damper on exploration and development in the Gulf of Mexico.

But the gulf's Central and Western areas remain the most accessible parts of the U.S. federal offshore.

The Bush administration's Outer Continental Shelf lease sale schedule for 1992-97 retains area-wide leasing for the Gulf of Mexico's two main producing regions. It generally restricts leasing elsewhere.

Compared with the current leasing schedule, the proposed plan envisions fewer sales and offers less acreage in each (OGJ, Mar. 4, p. 16). It follows President Bush's decision last June to delay for at least a decade eight controversial lease sales off the East and West Coasts and in the gulf off Florida.

In the Atlantic, meanwhile, plans remain on hold for Mobil Exploration & Producing U.S. Inc.'s first well in the Manteo area, 45 miles off North Carolina.

The company's plans to start drilling on Manteo Block 467 last July snagged on state opposition and a further delay imposed by the 1990 oil spill liability law. Mobil has appealed to the Department of Commerce.

Except in the Gulf of Mexico and off Alaska, therefore, access to prospects remains difficult.

GULF SLOWDOWN

Even in the gulf, operators are moving cautiously, in some cases deferring drilling until more certainty returns to post-war oil and gas markets.

In the first quarter of 1991, there were an average of 1215 fewer rigs at work in the gulf than during the comparable period of 1990.

Operators continue to contend with the region's technological challenges, from the ultradeep waters of the gulf's Texas and Louisiana frontiers to the hot, caustic, high pressure Jurassic Norphlet formation in Mobile Bay off Alabama.

During the past year, operators drilled the gulf's first two horizontal wells. And improving economics of subsea well completions are allowing development to proceed in some areas.

Minerals Management Service plans to continue area-wide leasing under its new 5 year OCS leasing schedule, which will keep a variety of prospects available to operators of all sizes.

Independents are taking larger interests in ventures and operating more leases than before. Concentrating in shallow waters, they are focusing on bringing production on stream as quickly as they can.

This year's drilling slowdown has reduced costs. Several offshore contractors have moved rigs out of the gulf. But rig and equipment supplies remain adequate.

Seismic contractors continue to shoot speculative area-wide three dimensional surveys, covering the full range of water depths. As a result, operators are funding fewer proprietary contract shoots and increasing their purchases of speculative data.

MAJOR GULF PLAYERS

Although major companies continue working better known prospects in relatively shallow water, their most important projects involve activity in ultradeep water and other plays requiring heavy applications of technology and large capital investments.

Mobil is working on development in Mary Ann natural gas field in Mobile Bay, which will increase Norphlet production there to more than 130 MMcfd. The company's activity on Mobile Block 823 in the central gulf is expected to result in the first production in federal water off Alabama.

In Mobile Bay, Mobil has completed another well in Norphlet strata more than 22,000 ft deep on Mobile Bay Block 77. It also has expanded to more than 100 MMcfd the capacity of its Mary Ann gas processing plant in southern Mobile County, Ala.

Exxon Co., U.S.A. is well along with plans to spend $3 billion to start Norphlet gas production in Mobile Bay. Exxon's activity surrounds Mobil's Mary Ann development.

By late 1993, Exxon expects to begin moving about 300 MMcfd of gas from 12 Norphlet wells to an onshore treating plant in southern Mobile County.

ULTRADEEP DEVELOPMENT

Elsewhere in the gulf, Exxon plans to spend about $500 million to develop two fields in ultradeep Mississippi Canyon blocks, 50 miles south of Grand Isle, La.

It plans to set Platform Alabaster in 468 ft of water on Mississippi Canyon Block 397 to receive production from Mississippi Canyon Block 354 via the Zinc multiwell subsea system set in 1,500 ft of water.

Zinc production is expected to begin early in 1992 from 22 wells in water 7,00015,000 ft deep. During the 20 year life of the project, production is to peak at 115 MMcfd of gas and 2,500 b/d of condensate.

The Zinc production and gathering system will be Exxon's first application in the gulf of deepwater subsea technology proved more than a decade ago.

Shell Offshore Inc. (SOI), which holds 37% of all deepwater acreage in the gulf, continues to advance several ultradeepwater projects.

Last summer, SOI let contracts valued at $475 million for construction and installation of components for its Auger development off Louisiana, where it plans to install a tension leg platform (TLP) in 2,860 ft of water.

Development costs for the Auger project, 214 miles southwest of New Orleans on Garden Banks Blocks 426, 427, 470, and 471, are expected to total $1.3 billion.

SOI expects to start Auger production in late 1993. At its peak, Auger is expected to produce 40,000 b/d of oil and 150 MMcfd of gas, with ultimate recovery estimated at 220 million bbl of oil equivalent.

The company expects to start production late this year on Green Canyon Block 65 in water 1,350 ft deep. Last year, it completed development drilling on the block from Bullwinkle, the world's tallest fixed platform.

SOI has a redevelopment program under way at its Cognac platform in 1,025 ft of water on Mississippi Canyon Block 194.

MANTEO WILDCAT

Though Mobil remains committed to drilling a wildcat well in Manteo Block 467 in 2,690 ft of water, 45 miles east-northeast of Cape Hatteras, N.C., Project Manager Jim Martin sees little chance of starting operation before 1992.

The Commerce Department could rule on Mobil's appeals as early as next summer.

But the oil spill law prevents MMS from issuing a permit until October 1991.

Martin said a provision attached to the legislation establishes a panel to review all available data and make a recommendation to MMS about adequacy of scientific information regarding leasing, drilling, and development in the Manteo area.

"The bottom line is it will be pretty tough to drill this well until 1992," Martin said.

He sees no danger in an independent panel's reviewing the environmental information Mobil has compiled for the Manteo project, a gas prospect.

"We're on record with the most comprehensive environmental study ever done for a single well exploration plan. We spent more than $3 million in special studies of that area, including things like sea bottom surveys using remotely controlled submarines and extensive evaluations of current patterns in the area for a long period.

"I don't think you'll find anywhere on Earth a well site that has been better documented in terms of environmental effects."

Mobil and its partners have invested more than $300 million to put together the Manteo drilling unit's twenty-one 5,000-acre blocks.

Mobil plans to drill the Manteo wildcat from a dynamically positioned, turret-moored drillship. Drilling costs are expected to total $25 million.

Martin said 10-1 5 years will be needed to begin production if there's a discovery.

GAS PRICE QUESTION

In the gulf, the major question is the future of gas prices.

"For a number of years, producers have been expecting higher gas prices next year, or certainly the year after," said Joe B. Foster, chairman of Newfield Exploration Co., Houston. "Now some companies are starting to believe the price of gas won't ever go up, so they're not going to continue aggressively drilling wells."

Companies that have emphasized exploitation in the gulf for the past couple of years are beginning to question the wisdom of continuing to drill gas wells "when they're shutting in producing gas wells," Foster said.

Newfield was formed 2 years ago by Foster, a former executive vice-president and director of Tenneco Inc., following Tenneco's sale of its oil and gas operations, which Foster headed.

"We're going to be prepared to compete and make money with gas markets in the $1.50-1.75/Mcf range," Foster said.

Newfield produces 20 MMcfd of gas and 700 b/d of oil from leases in the Eugene Island and Ship Shoal areas of the gulf. The company has drilled 10 wildcat wells and logged four discoveries on West Delta, West Cameron, and Ship Shoal blocks.

It expects to drill 10-12 wildcats and 3 development wells this year.

NEWCOMER STRATEGY

Also building acreage in the gulf is BHP Petroleum (Americas) Inc., which entered the region in 1986 by acquiring assets of Energy Reserves Group and Monsanto Oil Co.

At yearend 1989, BHP held 200,000 net acres, of which it operated 75%. In 1986 it held 100,000 net acres and operated 25%.

At OCS Sale 125 for the Western Gulf in August 1990, BHP spent $4.2 million on 12 blocks and increased its holdings to 316,000 not acres in 94 gulf blocks.

Ed Jones, vice-president of BHP's Gulf of Mexico business unit, said the company will drill about 10 wells as operator in the gulf, about what it drilled in each of the past 2 years.

The gulf, he said, is "more mature than some places in the world, but there's still a lot to find out there."

BHP's strategy has been to buy acreage somewhat less costly than average with correspondingly higher risks and potential. Its activity in Sale 125 was typical. While the average bid sale-wide was about $95/acre, BHP averaged $56/acre.

While searching for large reserves, BHP sometimes turns up unexpected opportunities.

In a West Cameron Block 472 well last April it encountered less gas than it hoped in the target reservoir but thought a shallower gas zone could be economic if developed quickly.

In May it bought a platform on a South Timbalier block 190 miles from the West Cameron site from Seagull Energy Corp. and had it towed ashore for relifting, using second hand production equipment adapted to company standards.

BHP installed the refitted platform at West Cameron less than 90 days after the salvaging operation at South Timbalier.

In mid-October, a pipelay barge laid a 6 in. flow line and installed the riser on the platform. Gas sales began in November.

"It's not a huge discovery, but we got it on stream quickly and at a low cost," Jones said. "And because of the multiple pay possibilities offshore, I think there are frequent opportunities for similar occurrences."

MAINTAINING FOCUS

Enron Oil & Gas Co. (EOG) tries to stick to its game plan in the gulf.

"It's important to know what areas of the gulf you want to play, and to focus heavily on those areas," said Mark Papa, EOG vice-president of operations.

EOG's offshore game plan focuses on well depths less than 12,000 ft and water depths less than 250 ft in the Matagorda Trend area, off Port O'Connor, Tex. The company also operates off Louisiana, but 80-85% of its offshore expenditures go into the Matagorda area.

Papa said EOG is trying to carve out a niche as a well-healed independent by establishing a dominant position off Texas. EOG doesn't expect to find huge new reserves in its area of focus that haven't already been identified. But it has increased its gas deliverability since 1988 by about a third.

EOG was one of the top bidders in OCS Sale 125 last August. It spent $11 million to acquire 71,000 acres under 5 year leases with one-sixth royalties, more than doubling its net offshore acreage. In all, the company was high bidder on 14 blocks, mostly in areas that promise to extend recent Matagorda discoveries.

EOG seeks the operator's role and takes 100% interests where possible.

Papa said the 5 year terms of leases acquired in Sale 125 fit EOG's long term plan, which presumes that gas supply and demand in the U.S. will "become more balanced." Under present market conditions, EOG will defer drilling on leases acquired last year.

If leases had shorter terms-especially in light of persistently low gas prices-Papa said, "We'd probably be swallowing pretty hard right now."

EOG has shifted its offshore drilling emphasis to development, he said.

"If gas prices in March or April go drastically downward, as they have in past years, then we might even have to rethink our current plan."

SEISMIC ACTION

An example of the gulf's brisk seismic activity is a 3D survey, now in its third year, that Western Atlas International is shooting 100 blocks at a time.

"We're virtually covering the entire deep offshore," said Damir Skerl, executive vice-president.

Early last year Western Atlas started shooting a belt of 100 block 3D surveys in water as deep as 100 ft, the same way it was collecting data in deep water.

When the shallow water survey is complete, the company will start gathering data in slightly deeper water.

Western Atlas will shoot 3D surveys as far east as the Mobile Bay area.

Skerl said Western Atlas has been surprised by the number of calls it has received for speculative 3D seismic data in shallow water.

"We have a much higher degree of interest from the independents because they moved into the shallower offshore as the older companies moved into deeper water," he said.

BHP's Jones said his company is beginning to use 3D seismic data in the gulf.

The company, he said, has been using 3D data "in areas that have seen a fair amount of drilling" but not in frontier areas or for significant stepouts.

EOG's Papa said his company is relying heavily on 3D seismic data for siting offshore development wells.

"Most of the step-out or development drilling we anticipate doing this year will be in areas where we've shot 3D seismic and will be based on our analysis of the 3D seismic," he said.

Papa said EOG bought much 3D seismic data during 1990 and has integrated it into working geophysical information. For EOG, 1991 will be a test year for the effectiveness of 3D information.

"This year, we're going to drill some step-out wells sited by 3D data," he said, "so we'll see whether it is a profitable tool for us."

Skerl said Western Atlas also has been shooting speculative diagonal 2D surveys.

The data enable operators to correlate existing perpendicular 2D data.

"By filling in areas with diagonal seismic lines, operators can verify geological interpretations projected from older data," Skerl said.

Copyright 1991 Oil & Gas Journal. All Rights Reserved.