ECONOMICS AND TECHNOLOGY HELP SPARK GULF DEEPWATER PROJECTS

A.D. Koen
Senior Editor-News

Improved economics, better technology, and growing experience are converging in the Gulf of Mexico's ultra-deepwater areas to fuel a new era of U.S. offshore development.

After more than a decade of steady commitment in which gulf operators for the first time profitably produced oil and gas from reservoirs in more than 1,000 ft of water, operating units of a handful of mostly major oil companies have begun developing bigger strikes in 2,000-3,000 ft of water-or more.

As more companies gain confidence in their ultradeepwater capabilities to become involved in the play, more prospects are proceeding to development. The growing activity is especially promising because it comes at a time of weak oil and gas prices.

Whether more announcements of big projects in gulf ultradeepwater areas surface soon, if development under way stays on schedule production in extreme water depths by the end of the century will be a big part of gulf-wide oil and gas production.

To gauge the effects of the deepwater projects, the energy research team at Howard, Weil, Labouisse, Friedrichs Inc., New Orleans, in early 1994 calculated that deepwater projects under development in the gulf in fall 1993 could be producing more than 700,000 b/d of oil equivalent (BOE) by 1999. That volume would equal about half of the production decline expected across the entire U.S. and more than offset the gulf's projected production decline.

Since then, plans have been disclosed for two projects to start production in 1997. Their combined flow is to peak at about 85,000 b/d of oil and 230 MMcfd of gas before 2000.

ECONOMICS THE KEY

Companies taking the plunge into deeper water credit better economics with providing most of the impetus to begin exploiting discoveries. Lower finding, development, and production costs make some of the gulf's larger reservoirs in very deep water competitive with many other offshore prospects, U.S. or non-U.S., in any water depth.

Exploration costs are being trimmed with 3D seismic data that allow operators to avoid drilling some costly dry holes. Improved seismic data help companies site delineation wells at the best locations and anticipate downhole problems.

Meantime, better drilling capabilities are lowering deepwater drilling costs and improving the quality of wellbores in ultradeep water. Top drives and other rig floor equipment add efficiency to deepwater drilling. Some operators report successes with horizontal and extended reach wells in deep water.

Perhaps most important to the gulf's deepwater operators is the new flexibility allowed by recent advances in offshore production systems. Gulf of Mexico operators in the past couple of years have chosen tension leg platforms (TLPs), floating production systems (FPSs), and most recently a production spar to begin developing deepwater prospects.

Also, improvements in subsea technology have aided operators in all stages of activity.

ADDING UP THE GAINS

Taken together, recent technological improvements can help operators bring ultradeepwater reserves on stream faster than is possible with traditional production schemes based on fixed steel jacketed platforms, greatly increasing present values of revenue streams.

Operators in many cases not only can hold down upfront investment because of the more mobile production systems, but also have the option of moving a floating production unit to a new site after a field in the gulf's ultradeep water reaches the end of its life.

Further supporting oil and gas development in water depths previously unchallenged in the gulf was the November 1994 start-up of Viosca Knoll Gathering System (VKGS), a 94 mile, 20 in. line tracing the edge of the gulf's Outer Continental Shelf off the Louisiana delta.

Owned 50-50 by Tenneco Gas and Leviathan Gas Pipeline Partners LP, both of Houston, VKGS was built to function as a header system for deepwater projects in the Viosca Knoll federal planning area. The system extends from a Shell Offshore Inc. platform on Main Pass Block 252 to links with a Tennessee Gas Pipeline Co. line on South Pass Block 55 and a line of Sonat Inc. unit Southern Natural Gas Co. on Main Pass Block 289.

"VKGS can access deepwater projects almost for its entire length," said Jim Gotcher, director of supply development for Tennessee Gas.

Throughput on the 350 MMcfd pipeline system has been averaging about 160 MMcfd. Capacity of the $64 million system could be expanded to about 600 MMcfd, and Gotcher said VKGS transportation volumes could climb to as much as 300 MMcfd by late 1997 "because of production from key deepwater projects like Ram-Powell."

Shell and partners last January unveiled plans to develop their Ram-Powell prospect with a TLP installed in 3,218 ft of water on Viosca Knoll Block 956, less than 20 miles at the closest point from VKGS (OGJ, Jan. 30, P. 41).

DEEPWATER ACTIVITY

Deepwater Speculative Gas Pipeline (116168 bytes)

The spate of development activity in ultradeep water is reflected in activity summaries.

Chris Oynes, Minerals Management Service (MMS) director for the Gulf of Mexico region, said deepwater drilling in the gulf in the past year has been a constant drum beat, increasing to an average 15 active rigs in 1,000 ft of water or more in fourth quarter 1994 from only five rigs early in the ),ear.

"Now it's still at 12-13 active rigs, and has been for weeks," Oynes said.

"So even though the number of total rigs drilling in the gulf has dropped a bit, we're still at a very high level of deepwater activity"

Earlier this month, Offshore Data Services Inc. (ODS), Houston, in its weekly Gulf of Mexico rig utilization survey counted 115 rigs working in the gulf, down from 143 in November 1994. Deepwater drilling activity, meantime, held steady with nine rigs drilling in more than 1,000 ft of water.

The ODS weekly rig locator of Mar. 3 reported that all nine units working at deepwater sites were in water 1,800 ft deep or more. The deepwater wells in progress all were spudded since October 1994, including four in February 1995.

Shell in early March was the gulf's most active deepwater driller with four wells under way, all in more than 2,000 ft of water. Shell's A-14 well in 2,945 ft of water on Mississippi Canyon Block 807 and Auger-20 well in progress on the Auger TLP on Mississippi Canyon Block 426 were the gulf's two deepest water development drilling sites.

BP Exploration Inc. was drilling a delineation well in 3,859 ft of water on Mississippi Canyon Block 935, the deepest water active wildcat location in the gulf.

Ken Miller, managing director at Simmons & Co. International, Houston, said the strength of deepwater drilling activity is but one indicator that the gulf's deep water will be a focal point of development for a long time. Another sign that the deepwater play will persist is the number and types of projects for which operators are seeking contractor and supplier bids.

Earlier this year, an official of a company providing subsea engineering and installation services for offshore flexible piping, umbilicals, and remotely operated vehicles reported that requests from operators for bids on deepwater projects was running at the highest level in 5 years.

Similarly, Oryx Energy Co., Dallas, and CNG Producing Co, New Orleans, stirred industry interest last November when they disclosed plans to employ the gulf's first production spar to develop Neptune field in 2,000 ft of water on Viosca Knoll Block 826 (OGJ, Nov. 21,1994, P. 33).

Dick Standaert, Oryx's general manager of the U.S. offshore, said other operators interested in learning more about spars began contacting the service companies involved as soon as Neptune development was announced. Many reportedly had specific deepwater prospects in mind.

"I have a sense that a lot of things are going to come out of the woodwork pretty quickly," Standaert said of the outlook for deepwater activity.

ADAPTING TECHNOLOGY

Miller and others attribute much of the recent burst of gulf deepwater activity to U.S. operating units of non-U.S. multinational companies that are adapting offshore technology used first in other places. The theory is borne out by the gulf's two most aggressive deepwater players, Shell and BP Exploration.

In that context, applications of new deepwater technology in the gulf are part of a global trend in which the same capabilities are spreading from centers in the North Sea and off Brazil to deepwater plays in other parts of the world.

Miller said, "Essentially, the idea is U.S. operators are employing technologies in the deepwater gulf that have been proven to reduce the marginal costs of developing oil reserves in deep water."

And while that essentially is accurate, it also could be argued that even U.S. operating units of non-U.S. companies working in the gulf until recently have been limited by the capabilities of upstream technology

For example, Shell and BP share the distinction of installing the two deepest water fixed platforms in the gulf. Shell's Bullwinkle platform rests in 1,353 ft of water on Green Canyon Block 65, while BP last summer installed Pompano platform in 1,290 ft of water on Viosca Knoll Block 989.

Development operations continue on the 40 slot Pompano platform, where BP is tying back and completing the last of 10 wells predrilled for phase one of development. More wells are to be drilled from the platform.

Six Pompano wells at the end of February were producing about 23,000 b/d of oil and 14 MMcfd of gas. The company plans to boost production of platform wells to 40,000 b/d of oil and 50 MMcfd of gas, then bring on only enough new supply to hold that level of production.

Dan Huxley, BP Exploration operations manager, said Pompano phase two field work is to begin this summer with installation of a 10 slot drilling-production template in about 1,800 ft of water on Mississippi Canyon Block 28. BP expects to start drilling wells through the template in September 1995 and continue for about 1 1/2 years.

The energy services unit of Brown & Root Inc. is fabricating the template at its Greens Bayou yard east of Houston.

Pompano phase two production is to begin coming on line in summer 1996, at which time the project's output is to begin increasing, lifting project oil production capacity to about 60,000 b/d.

BP Exploration Vice Pres. Jack Golden said the company believes it is moving faster up the deepwater development learning curve. Drilling technology figures prominently among deepwater capabilities BP has advanced in recent years. Concepts such as geosteering contributed to the company's deepwater drilling successes.

Although still risky, costly, and difficult, Golden said, BP has been able "to do successful horizontal drilling in deep water and some recent extended reach drilling that 5 years ago we would not have contemplated."

BP this month is to complete an extended reach well on the Pompano platform that was among the 10 predrills. The well's horizontal deviation is about 15,500 ft, its measured depth nearly 21,000 ft, and true vertical depth 10,000-11,000 ft.

"Not just ourselves, but other companies are using some of the newer techniques from other places and applying that technology very effectively," Golden said.

Miller said the number of announcements by major and medium size companies in the past 2-3 months about subsea projects in the North Sea and Gulf of Mexico has been enormous.

An oil and gas industry analyst for the past 25 years, Miller tempers his enthusiasm about the gulf's growing deepwater development with a healthy dose of industry cyclicality. Yet he concedes, "We're seeing more deepwater, subsea development projects being announced than I can recall, maybe ever."

Recent Gulf of Mexico Wells in More Than 900 m of Water (43167 bytes)

DEVELOPMENT TIMETABLES

Armed with better tools, explorationists have steadily improved their knowledge of deepwater formations. More familiarity has revealed the gulf's deepwater reservoirs to be of world class, larger and more productive than expected.

Growing assurance of their ability to work in ultradeep water and more knowledge of the quality of prospects has led to a shift in thinking among companies pursuing the play.

As a result, companies ave begun developing prospects previously considered too risky or uneconomic. Other more recent, larger, deepwater discoveries are proceeding into development more quickly than was considered prudent just a few years ago. Shell's recently announced Mars and Ram-lowell TLP developments reflect the two trends.

Shell in spring 1994 broke its own water depth record for production in the gulf when its Auger TLP went on stream in 2,860 ft of water on Garden Banks Block 426. The previous gulf record was 1,350 of water, set by Shell's Bullwinkle platform on Green Canyon Block 65. Bullwinkle eclipsed the water depth production record held by Shell's Cognac platform in 1,025 ft of water on Mississippi Canyon Block 194.

The Auger TLP was barely nearing the end of assembly in fall 1993 when Shell and partner BP in October said they had agreed to use another TLP to develop the Mars prospect in 2,933 ft of water on Mississippi Canyon Block 807.

Shell and BP, with 71.5% and 28.5% interest, respectively, drilled the Mars discovery well in 1989 on Mississippi Canyon Block 763 and announced the strike in 1991. Delineation drilling and 3D seismic surveying appraised the field as productive, and MMS in December 1992 approved the partners' unitization plan.

If the Mars TLP begins production in 1996 as scheduled, the wells would begin flowing about 7 years after the field was discovered, 5 years after the find was announced, and only 3 years after the announcement that development would proceed.

By contrast, Shell drilled the Ram-Powell discovery well in May 1985 on Viosca Knoll Block 912, nearly a decade before partners announced they would proceed with development and more than 12 years before Mars production is to begin in late 1997.

NEW MINDSET

The choice of TLP based production systems and timing of the Mars and Ram-Powell development decisions were influenced heavily by the availability of better deepwater production technology. But other significant factors contributed to the pace of progress at those and other projects.

Reaching agreement on partners' responsibilities and financial contributions tends to delay development decisions, as does simply agreeing on how fast activity should advance.

"Undoubtedly, technology plays a role in determining how and when a prospect is developed," one deepwater operator said. "But partner relationships also are part of it, as are price forecasts."

Yet upstream capabilities in ultradeep water have changed so much in the past 5 years that operators' thinking also has begun to evolve.

"It's a different mindset," said Susan Cunningham, exploration manager in the Gulf of Mexico deepwater for Amoco Production's worldwide business group. "The economics of production technology have changed. Improvements have been incremental but significant.

"We don't feel we need to build a mammoth platform in such deep water anymore. The technology was too costly and inadequate for very deep water, anyway."

In addition to its 31% interest in Ram-Powell, Amoco at the beginning of March was evaluating three 1993 Amoco operated discoveries in the gulf, all in 3,200 ft of water or more.

Most advanced was the Marlin prospect in 3,200 ft of water on Viosca Knoll Block 915, where Amoco with 75% and Shell with 25% were considering whether to proceed to commercial development or drill a third delineation well.

Amoco also was studying results of its first delineation well on the Kings Peak prospect in 6,500 ft of water on Mississippi Canyon Block 217 and Desoto Canyon Block 133. On Mississippi Canyon Block 84, Amoco was trying to decide whether a delineation well was needed to confirm results of a wildcat drilled in 5,500 ft of water to test its King prospect.

CONTINUING ENCOURAGEMENT

Rich Pattarozzi, general manager of Shell Offshore's deepwater division, said his company's views on deepwater project cost structures have changed considerably since 1991. General expectations for lower oil and gas wellhead prices "have forced us to figure out more cost effective ways of doing things," he said.

On the other hand, production at projects like Bullwinkle and Auger showed that deepwater wells can produce at higher rates than originally thought.

"As our knowledge base has continued to improve, our view of deepwater well productivity has continued to improve," Pattarozzi said. "We have been able to bring costs down on the Mars TLP and Ram-Powell TLP below what Auger TLP cost. All of those things have continued to encourage us to move ahead."

On billion dollar deepwater projects like Auger, Mars, and Ram-Powell, wells must produce at higher rates to generate cash flow as quickly as possible, he said. "So it's nice we have the size of discoveries we have to work on."

Standaert said Oryx and CNG decided to use a production spar to develop Neptune field, even though a spar never had been used as a deepwater production structure, because of the Three Cs:

Cost control-With an estimated fabrication and installation cost of about $106 million, a production spar was a lower cost development option.
Cash flow management-The structure's relative low cost allowed Neptune partners more flexibility to phase development and reduce upfront costs.
Cycle time-The option will allow Oryx and CNG to begin Neptune production within 3 years of the field's development announcement.

Fabrication of major Neptune spar components was scheduled to begin Mar. 1. J. Ray McDermott, New Orleans, is to design and fabricate Neptune spar's topsides, procure production equipment, and transport and install the unit's mooring system, topsides, hull, and oil and gas pipelines. Rauma Offshore Contracting, Finland, is to fabricate the hull at its Pori, Finland, yard.

Longtime production spar advocate Deep Oil Technology Inc., Irvine, Calif., is to provide engineering services for the Neptune spar's hull and mooring system design (OGJ, Feb. 20, p. 100).

"All the steel has been ordered. We're on schedule for 1997 production," Standaert said.

DEEPWATER OUTLOOK

Gulf of Mexico Deepwater Discoveries, June 1992-December 1994 (27956 bytes)

Andy Hardiman, manager of Gulf of Mexico business unit exploration for Chevron U.S.A. Production Co., said efforts to find ways to economically develop and produce deepwater discoveries forced many companies to rethink technical paradigms that had limited operating capabilities.

With many limitations overcome, deepwater economics in the gulf are beginning to compare favorably with those of other plays, such as Norphlet exploration and development and in the Viosca Knoll federal planning area. Because most companies try to assemble balanced lease portfolios, deepwater E&D spending in the gulf likely will continue to increase as long as deepwater economics are competitive. "At Chevron, we try to balance the risk and economic sides," Hardiman said. "Definitely, deep water is a bin in our portfolio."

Based on the premise that deepwater prospects will be able to compete with other opportunities in the gulf for investment dollars, Hardiman expects the window of opportunity in the gulf for deepwater projects to remain open for at least several more years.

Installation of more infrastructure will be strong incentive for many companies to start deepwater developments. Thus the number of deepwater projects under development in the gulf is sure to increase with time, with first round projects providing the seed infrastructure for a second round of development.

"Once we get the infrastructure in place, it makes the smaller projects more viable," he said. "If a project doesn't have to include the full cost of installing deepwater oil or- gas pipelines, it's that much easier to justify proceeding with development.

"So there's an opportunity for a second round of activity related to infrastructure that goes in for the first round of projects. With projects like Auger and Mars, there could be 50-60 projects underway in water 1,000 ft deep or more within the next 10 years," Hardiman said.

Though it hasn't focused on the gulf's deep water with the same intensity as companies like Shell or BP, Chevron is considering development options for its Green Canyon Block 205 prospect on a three tract leasehold in about 2,650 ft of water.

Chevron in late February finished drilling a well on the crest of the Mississippi Canyon 205 structure that appears promising. Including sidetracks, the company has penetrated the reservoir with 10 holes.

With that many holes, Herman J. Colligan, manager of Chevron Production's special projects group, said the company is confident it understands the formation well.

"We hope to make a decision by the first of June, do some preliminary and detailed engineering, do a cost estimate, and produce an appropriation request for our management by early 1996," Colligan said.