NEED SEEN FOR MORE PIPELINES IN DEEPWATER GULF OF MEXICO

A.D. Koen
Senior Editor-News

More deepwater pipeline infrastructure is needed in the Gulf of Mexico to assure orderly development of marginal deepwater discoveries.

For now, deepwater pipelaying activity in the gulf is riding the coattails of recent and pending production start-ups of stand-alone developments in record water depths.

For each deepwater production record claimed in the gulf, a pipelining mark of equal note is being set by the companies designing and installing project gathering and flow lines.

Many operators and offshore contractors expect most pipeline infrastructure will expand into the gulf's deep water as flow and gathering lines for deepwater discoveries large enough to be profitable on their own. Thus as capacity becomes available on the transportation systems of stand-alone projects with the onset of normal production decline, smaller prospects nearby can tie in.

While large, stand-alone developments traditionally have driven pipeline extensions in the gulf, the impetus for pushing pipeline infrastructure into ever deeper water will differ with water depths and with need. Some companies are planning pipeline header systems that would move the gulf's infrastructure closer to deep water, lowering upfront development costs for some deepwater discoveries.

To be sure, the outlook for oil prices weighs heavily on development decisions for deepwater prospects of any scope. For all but the largest deepwater discoveries, operators commonly must achieve profitability by finding ways to lower capital or operating costs a few percentage points.

That affects a sizable number of deepwater developments in the gulf. Minerals Management Service (MMS) estimates average reserves of fields discovered in 601-1,200 ft of water at 62.6 million bbl of oil equivalent (BOE) and 78.3 million BOE for fields in 1,201 ft of water or more. For some marginal deepwater discoveries, lower transportation costs could allow development to proceed.

Adequate technological capabilities exist in the gulf to allow installations of production facilities and pipelines in water 3,000 ft deep and more. But whether enough deepwater gulf oil and gas pipeline capacity expands soon likely will come down to how willing operators are to cooperate in regional, phased development schemes.

HISTORICAL EXTENSIONS

The first offshore pipelines in the Gulf of Mexico were laid south from shore to link with large stand-alone developments on the Outer Continental Shelf (OCS). Next, pipeline systems generally expanded to the east and west to accommodate oil and gas flows from discoveries between northbound and southbound lines.

As the gulf's offshore pipeline infrastructure extended into new producing areas on the OCS, incremental costs of putting reserves on line decreased. As a result, many prospects were developed on the shelf that alone could not have supported the cost of installing a stand-alone, dedicated pipeline system. That process has been repeated time and again in the Gulf of Mexico and elsewhere.

Among recent deepwater pipelays in the gulf:

• McDermott International Inc. in April 1993 used a J-lay technique to lay the deepwater portions of the 12 in. oil and gas flowlines for Shell Offshore Inc.'s Auger tension leg platform (TLP), to be set by early 1994 in 2,860 ft of water on Garden Banks Block 426 (OGJ, Dec. 6, p. 25). After installation of Auger TLP, McDermott's derrick barge 50 (DB-50) is to install the last 3 miles of both lines with a diverless lateral deflection tie-in.

• Oryx Energy Inc., Dallas, earlier this year began transporting 60 MMcfd of gas through flexible subsea flow lines from subsea wells in as much as 2,088 ft of water on Mississippi Canyon 400 unit to a platform on West Delta Block 152 (OGJ, Nov. 22, p. 33). The flow line connecting 400 unit's 1 Mississippi Canyon Block 445 well to the West Delta platform claimed the world records for water depth and length for an all flexible gas flow line.

• Enserch Corp., Dallas, last summer began transporting more than 70 MMcfd of gas through flow lines from six subsea wells-three in 1,519 ft of water and three in 1,411 ft of water-on Mississippi Canyon Block 441. Gas flows 6 miles to a fixed platform in 380 ft of water on Ewing Bank Block 482 (OGJ, Sept. 27, p. 20). Enserch assembled the project's integrated oil and gas flowline and control umbilical bundles on Matagorda Island near Bay City, Tex., and bottom towed the bundles 500 miles to Block 441.

• Exxon Co. U.S.A. in January 1993 used a diverless lateral deflection tie-in to connect three 6 mile long flow-lines, including two 8 in. and one 4 in., to the Zinc multiwell, satellite subsea template in about 1,500 ft of water on Mississippi Canyon Block 354. Exxon laid the Zinc lines in July and August 1992 and in December 1992 began installing Zinc template (OGJ, Dec. 14, 1992, p. 23). Zinc output flows to Alabaster platform in 468 ft of water on Mississippi Canyon Block 397. Zinc gas flows to shore from Alabaster via a 60 mile, 20 in. Southern Natural Gas Co. pipeline, the gulf's deepest water, big diameter subsea line (OGJ, Aug. 24, 1992, p. 33)

PIPELINE HEADER SYSTEMS

Leviathan Gas Pipeline Partners L.P., Houston, is one company seeking to expand Gulf of Mexico pipeline infrastructure into deep water, irrespective of development of a stand-alone deepwater prospect.

Leviathan was formed in 1989 to acquire and construct gas pipelines in the gulf near existing and prospective fields off Louisiana and Texas. Today, the company's offshore pipeline system in the gulf includes five active lines with a combined length of more than 660 miles and capacity for as much as 4.8 bcfd of gas from wells in four service areas on the gulf's OCS, Flex trend, and deepwater areas.

Studies indicate that Leviathan pipelines through the mid-1990s will have access to reserves adequate to maintain average throughput. But longer term, each system must gain access to new reserves to offset natural production decline of wells currently connected.

Much of the new system supply could come from the gulf's deepwater frontier. According to MMS, gulf operators in the past decade have announced more than 22 Flex trend and deepwater discoveries in Leviathan's service areas, about half of which remain under appraisal. In addition, MMS has leased more than 150 deepwater tracts since 1990, and Leviathan expects another 15-20 Flex discoveries to be announced by yearend 1995.

By connecting Flex trend and deepwater discoveries near its pipelines, Leviathan in the mid to late 1990s could increase the throughput of its gas pipeline system in the gulf, company officials reckon.

VIOSCA KNOLL GATHERING SYSTEM

In June 1993, Leviathan and Tenneco Gas unit of Tenneco Inc., Houston, disclosed plans to jointly build a gas gathering system to transport reserves to be developed in the deepwater Viosca Knoll and Main Pass areas.

According to preliminary plans, phase one of Viosca Knoll gathering system (VKGS) would extend almost 40 miles in 200-300 ft of water from the extreme southeastern corner of Main Pass area through the southernmost tier of Main Pass blocks. VKGS phase two pipeline would:

• Drop down about 6 miles from Main Pass to Phar Lap prospect of Leviathan affiliate Tatham Offshore Inc., Houston in as much as 1,100 ft of water on Viosca Knoll Blocks 772, 773, 774, 817, 818, and 861.

• Head more than 30 miles southwest across Viosca Knoll in water as deep as 600 ft and along the border separating Mississippi Canyon and South Pass areas. The terminus would be at Tenneco's gathering platform on South Pass Block 55, which is connected to the 500 Line of Tenneco unit Tennessee Gas Pipeline Co.

Leviathan and Tenneco are promoting VKGS as a transportation option to a number of producers with deepwater discoveries in the area. But no firm decisions have been made, and no estimate is available about when construction of the header might begin. If it is built, VKGS likely will be one of several regional pipeline headers to extend the gulf's transportation infrastructure to within reach of marginal deepwater oil and gas discoveries.

PATH TO MARKET

In theory, the costs to such companies as Tenneco and Leviathan of laying a header system plus the costs to operators of laying flow lines to the header would be less than the combined costs to operators of laying individual flow lines from each prospect to existing pipeline infrastructure without the header.

Tenneco and Leviathan would benefit by tying their offshore gas pipeline systems to new sources of supply. For operators with nearby deepwater discoveries, eliminating the upfront costs of laying lengthy flow or gathering lines could reduce upfront development costs. That could allow some marginal deepwater prospects to come on line individually, resulting in earlier start-up of production and cash flow than would be possible otherwise.

Jim Gotcher, Tenneco Gas's director of supply development, estimated VKGS would cut to 8-10 miles from 35-40 miles the distance to pipeline infrastructure from many deepwater discoveries in the Main Pass and Viosca Knoll areas. By virtue of VKGS's interconnect with the 500 Line, Gotcher rated the project as part of one of the best proposals yet offered for undeveloped deepwater gas prospects in the area to reach markets in the U.S. Northeast.

"Strategically, laying a header system right down to the edge of the shelf gives people all along its 90 mile length a way to get that gas back to market," he said. "No one single project out there would support a pipeline project of this magnitude and make the economies of scale work for everybody."

Leviathan and Tenneco are studying the gulf to find other areas where pipeline headers would provide similar benefits.

For example, Leviathan since 1991 has been touting a proposed deepwater header system skirting across the shelf's edge in the central gulf along the southern boundaries of the south additions of East Cameron, Vermilion, and South Marsh Island areas. The header would interconnect Leviathan's Stingray and Green Canyon offshore pipeline systems, significantly improving marketing flexibility of deepwater producers in the Garden Banks and Green Canyon areas.

CASE FOR STAND-ALONE PROJECTS

Despite the shared benefits of strategically placed pipeline headers in spurring deepwater development, many gulf operators believe most future pipeline extensions into deep water will be dedicated to stand-alone projects.

Dick Kincheloe, Enserch oil and gas unit's senior vice president of offshore and international operations, said it's hard to justify laying pipelines in the gulf's deep water unless there is a specific need or the pipeline company can prearrange deals to transport production from new projects in the area.

"Normally, anybody building a speculative pipeline in the gulf has to have some solid transportation contracts in his pocket to finance the work," Kincheloe said. "The problem with that is the operator normally can build those pipelines for much less than he could pay someone else to build, and by letting someone else build the line for him, he's just carving out a profit for the other guy."

Rich Pattarozzi, general manager of deepwater exploration and production for Shell Offshore Inc., said decreasing flowline costs could alter economics enough on some projects to make them profitable.

"But I don't think it would be the deciding factor for any of our projects in the Viosca Knoll area," Pattarozzi said. "There are too many other things that affect deepwater developments other than just pipeline costs."

To get a deepwater project on line, a financially constrained independent operator might be willing to commit to using speculative pipeline infrastructure installed and operated by a pipeline company.

In fact, Enserch considered but decided against the possibility of using pipeline company infrastructure to tie in a 24 slot subsea drilling/production template it plans to install in 1994 in 2,190 ft of water on Garden Banks Block 388. That project includes two 12 in. pipelines-one oil and one gas-to run 54 miles to a processing facility in about 250 ft of water on Eugene Island Block 315.

Enserch in October awarded McDermott a $46 million lump sum contract to install the Garden Banks 388 infrastructure, including laying the pipelines, fabricating and installing the jacket and deck of the shallow water platform, and install the template on Block 388. McDermott is to start pipelay operations next spring using a S-lay system on a modified lay barge. Kincheloe said the 388 pipeline installation will be the deepest water S-lay in the gulf.

EXPANSION ALTERNATIVES

Kincheloe's firm is among the operators that believe deepwater pipeline infrastructure in the gulf is more likely to expand as:

• Pipeline companies acquire fixed platforms in the deeper water on the shelf and convert them to gathering and transportation facilities by replacing production equipment with compressors or pumps.

• Operators design excess capacity into new deepwater production and transportation facilities.

In that event, deepwater pipelines tied into existing infrastructure on the shelf already would be connected to sales outlets. In deeper water, some subsea templates likely will play similar gathering and transmission roles as fixed platforms do on the OCS.

Kincheloe said most companies installing production facilities in deep water will include incremental production and transportation beyond their own projects' needs. Enserch's deepwater development on Garden Banks Block 388 is a case in point.

The Block 388 template has 24 slots with extra oil and gas tie-in points on either side, more well positions than Enserch expects to need to develop Block 388 field. In addition, the design of Block 388 pipelines includes side taps to allow as yet unspecified prospects to tie into the 388 pipeline system.

If conventional pipelay techniques can be used, Kincheloe said the relative cost of installing larger deepwater flow lines than are needed for a given development is low, compared to the flexibility gained to respond quickly to unexpected opportunities to ramp up throughput.

"There's an incremental cost difference for the larger diameter but not that much difference," he said."We always try to build some cushion in, so if we have more production than we expect, we can handle it. But in many cases, it's a judgment call."

However, designing incremental excess capacity into deepwater components is not a given because it can mean building facilities on a speculative basis. Companies should be wary of installing large diameter pipe in deep water on speculation because operating and maintenance of big lines are too costly to construct capacity that might never be used.

SHELL'S DEEPWATER HUBS

Pattarozzi said stepping off into deep water from existing OCS infrastructure is a concept that has merit for deepwater development in the gulf. But as operators begin developing prospects in water 3,000 ft and deeper, farther from the edge of the shelf, there will be a need for infrastructure to step out even farther.

Providing infrastructure for marginal fields in ultradeep water is a role likely to be played exclusively by large, stand-alone developments such as Shell's Auger and Mars developments, he said.

Shell expects either or perhaps both of the projects to be used eventually as gathering installations by other deepwater operators, but it hasn't considered any such future role in deciding to proceed with either project.

"We're basing both Mars and Auger on what we know today," Pattarozzi said. "But beyond that, we visualize that these projects will play a role in the future, if they prove themselves to be viable projects over time, as part of the infrastructure that allows us to take that next step."

Acquiring unused transportation capacity on a project as large as Auger or Mars could take a long time.

Auger production is set to begin going on stream in early 1994, peak in 2001 at 46,000 b/d of oil and 125 MMcfd of gas. With recoverable reserves estimated at about 220 million BOE, another decade could pass before Auger output declines enough to open capacity to another producer.

Mars is expected to begin producing oil and gas in fourth quarter 1996 and increase gradually to a peak in 2000 of about 100,000 b/d of oil and 110 MMcfd of gas. Ultimate recovery of Mars phase one development is put at about 500 million BOE. Shell estimates Mars second phase recoverable reserves at about 200 million BOE.

While such a role seems certain for many large throughput, deepwater projects, the time tested mode of development in the gulf could delay substantially the start of production from marginal discoveries waiting to tie in.

DEVELOPMENT BARRIERS

Leviathan Pres. John Gray said operators of giant, stand-alone deepwater projects in the gulf are not eager to let other operators begin using dedicated deepwater pipeline systems. That is especially so when development costs are great and the companies have other apparently large deepwater discoveries in the vicinity.

"The problem we see with that is it limits the ability for marginal reserves to be developed in those areas," Gray said. "A deepwater development plan including a junction platform as a focal point of a pipeline system along the edge of the shelf allows everyone to develop marginal properties quicker than they could if only stand-alone projects with self-sufficient pipelines are being installed."

Kincheloe said another factor that could contribute to delaying development of marginal deepwater discoveries is the troubling dearth of large deepwater projects under development. While major companies account for most of the deepwater reserves booked to date, much deepwater activity is being driven by independent companies with smaller, marginal properties.

There also are questions about how much incremental transportation capacity could become available on the gulf's deepwater facilities.

Jim O'Sullivan, manager of Brown & Root Seaflo, a unit of Brown & Root Energy Services division of Halliburton, said deepwater production platforms tend to have smaller capacities than fixed structures on the shelf. That limits the size of flow lines needed in deep water.

"It's relatively easy to support large production and flowline capacities in shallow water where a company can install a fixed platform," O'Sullivan said. "But a big, eight legged fixed platform would cost a fortune in deep water, and it's hard to design deepwater alternatives such as TLPs or floating production systems (FPS) with large throughput Capacities."

O'Sullivan said a company laying a large diameter pipeline to a TLP or FPS in 2,500 ft of water likely would have to tie in other deepwater fields to fill the line. Even an 18 in. pipeline would strain the productive capacity of some deepwater platforms.

"Eighteen inch pipelines really aren't big enough to make good trunk-lines. But that is about as large as they're going to lay in water that deep in the gulf," he said.

O'Sullivan said companies could begin installing pipelines with diameters larger than 18 in. within 3-5 years, either by adapting lay or derrick barges currently in the region or by mobilizing new equipment to the gulf.

COOPERATIVE EXTENSIONS

Operators and pipeline company officials agreed more cooperation in the gulf will be needed to assure adequate deepwater pipeline infrastructure exists to support orderly development of deepwater oil and gas prospects.

Development in the North Sea is often cited as an example. There, operators first built big structures to produce large fields. Today, the emphasis is on using existing infrastructure as host production or transportation facilities for oil or gas from nearby satellite wells.

"I would think deepwater oil and gas development in the Gulf of Mexico will play out the same way," Pattarozzi said. "That already is what gulf operators do on the shelf."

O'Sullivan suggested MMS would be the best vehicle through which the federal government could shape a cooperative deepwater development policy to spur development.

"But the policy couldn't be a coercive thing, or people would resist it," he said. "Companies would have to feel they weren't forced into giving information away or limiting their investment and development options."

A host of companies expect to bring more deepwater production on line in the gulf within the next 2-3 years. But the pace of deepwater pipeline expansions will be slow, likely in step with exploratory activity in deep water.

O'Sullivan said marine contractors are working to be ready to fabricate the facilities needed as deepwater development advances. The best clue as to when deepwater activity will begin accelerating likely will come from oil prices, which underpin the profitability of oil and gas projects alike.

"If the question is when will deepwater development begin in earnest in the Gulf of Mexico-with $15/bbl oil, the answer is not tomorrow," O'Sullivan said.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.