Subsea technology progress buoys Gulf of Mexico deepwater action

Enserch Exploration Inc. is drilling a subsea well from a floating drilling-production unit in more than 2,100 ft of water in Cooper oil and gas field in the Gulf of Mexico. Photo courtesy of Enserch Exploration.

Subsea technology is opening a new era of oil and gas development in the Gulf of Mexico. Used only sparingly in the gulf through the early 1990s, subsea equipment in the past 2-3 years has begun finding more applications on the gulf's deepwater frontier.

By tying back subsea wells to host facilities-either floating production systems (FPS) or platforms in shallower water on the Outer Continental Shelf-operators are able to develop discoveries that otherwise would not be economic.

Barriers persist for subsea wells. In part based on past problems with paraffin and hydrate formation in wells both on the shelf and in deep waters, many producers are reluctant to use an offshore production option that makes well maintenance and workover troublesome and costly.

Still, more operators are opting to use subsea production systems because scores of technical advances and new tools have improved the reliability and expanded the capabilities of the equipment.

At the same time, industry cooperative ventures such as the American Petroleum Institute's Committee 17 and the DeepStar group are leading efforts to standardize subsea components and tools. As a result, costs of using subsea technology-as well as the attendant risks-are declining.

Basic production options

As subsea technology expands into deep waters, operators in the gulf are using subsea production systems based on template and well cluster designs.

Enserch Exploration Inc., Dallas, has developed deepwater fields in the gulf with two template based options.

The company in April 1993 started production from the gulf's first successful deepwater, template-based subsea system (OGJ, Apr. 26, 1993, p. 95). In that project, wells produced from two templates in 1,410-1,520 ft of water on Mississippi Canyon Block 441 to a fixed platform 6 miles away in 380 ft of water on Ewing Bank Block 482.

Enserch in September 1995 started production in Cooper field. Production from two wells on Garden Banks Block 388 flows through 3 mile tiebacks to a floating drilling and production unit, also on Block 388.

Shell Offshore Inc. and partners in April 1995 disclosed plans to install the gulf's first subsea cluster production system, in Popeye field (OGJ, Apr. 10, 1995, p. 26). Popeye field produces gas from 2,000 ft of water on Green Canyon Block 116. Production flows from six wellheads to a subsea manifold and via subsea pipeline to Cougar platform, 24 miles away on South Timbalier Block 300.

Subsea cluster systems are gaining favor among deepwater operators because they allow more flexibility to deal with shallow water flow (SWF). SWF occurs during drilling operations in roughly the first 1,000 ft of clay formations below the seabed.

With SWF, overburden literally squeezes water from the formations, forming undersea rivers of usually fresh water. Drillers have ways of overcoming the phenomenon, but it can wash out cement jobs and create other drilling problems downhole if not checked.

Beyond reach of TLPs

At yearend 1995, only a handful of subsea wells in the gulf was producing in more than 2,000 ft of water.

But as costs have declined and reliability improved, operators have begun using subsea completions in ever-greater water depths.

Last month, Shell Offshore Inc. and BP Exploration Inc. claimed a regional water depth record for subsea production with a satellite well tied back to Mars tension leg platform (TLP) in 2,940 ft of water on Mississippi Canyon Block 807, (OGJ, Aug. 26, p. 21). Mars TLP is the first such facility in the gulf to host a subsea well.

The feat bodes well for an offshore region in which many believe success will depend on operators' ability to use subsea technology to develop fields in water deeper than any locations producing to date.

Opinions vary, but many estimate current TLP technology is capable of producing oil or gas in water as deep as 4,500 ft. Significant breakthroughs in tendon technology could extend that water depth capability to 5,000 ft.

If the view is true that the future of the Gulf of Mexico is in water depths beyond the reach of TLP technology, as one industry official said recently, "You've got to know how to do subsea, if you're going to play the game in the 1990s."

Spreading across the gulf

As subsea technology moves into deeper water, its use is spreading across the gulf.

Data compiled by Derrick Booth, Subsea Data Services, Austin, show more subsea wells will be completed in the gulf this year than were on line at yearend 1995. By 2000, that number could jump fourfold.

Booth's data show the subsea production water depth record set this summer by Shell Offshore and BP with the Mars II subsea tieback will stand only about a year. Shell next year expects to move the mark to nearly 1,650 m with its Mensa subsea development on Mississippi Canyon Block 657 (OGJ, June 5, 1995, p. 30).

Booth and others expect Amoco Production Co. by 2000 to exceed Mensa's water depth with the Kings Peak prospect, to come on line in more than 2,000 m of water on Viosca Knoll Block 177.

TLP-based production systems enable operators to work on wellheads at the surface. But costs of such facilities increase rapidly with increasing water depths, creating economic pressures that for the most part have limited operators to developing and producing only the largest deepwater oil and gas fields.

Despite the technical hurdles presented by subsea production and well intervention, operators have big economic incentives to opt for subsea systems at fields in extremely deep water.

Curbing deepwater costs

Shell estimates the costs of using TLPs to develop Mars and Auger fields-the latter in 2,860 ft of water on Garden Banks Block 426-at about $1.2 billion each (OGJ, Apr. 8, p. 23).

Production spar technology offers a promising way for operators to curb deepwater development costs while retaining surface well completions. Oryx Energy Co., Dallas, and CNG Producing Co., New Orleans, later this year in the gulf plan to install the world's first production spar at Neptune field in about 2,000 ft of water on Viosca Knoll Block 826 (OGJ, Nov. 21, 1994, p. 33). Industry sources estimate Neptune partners will spend about $300 million on the development (OGJ, May 22, 1995, p. 22).

By comparison, Shell and partners CNG, BP, and Mobil Exploration & Producing Co. reportedly spent about $105 million to develop Popeye field. Shell estimates the cost of developing Mensa subsea at $230-290 million.

Clive Fowler, vice president of Amoco Corp.'s offshore business unit, says that because of the desire to avoid operating problems with paraffin or hydrates in deepwater, most operators prefer to use facilities with surface wellheads to water depths exceeding about 3,000 ft.

"Generally, if you have sufficient resources to justify a floating system, you tend to go in that direction, because you don't have to deal with the high-risk issues of paraffin crude," Fowler said. "Beyond 3,000 ft of water, people look to subsea alternatives more often than surface-piercing alternatives for a given reserve size."

Most deepwater fields

Subsea developments in the gulf consist mainly of fields with reserves of as little as 120 million bbl of oil equivalent (BOE) or smaller satellite fields that can be tied back to production facilities for large accumulations.

Industry sources estimate that 75% of the deepwater fields discovered to date in the gulf have reserves of 120 million BOE or less.

"That's a perfect opportunity to use subsea production systems," one official said.

Already as much as 80% of the gulf's developments in 1,000 ft of water involve subsea components or operations of some type. That percentage is destined to climb.

"There are going to be all sorts of satellite prospects around the big deepwater oil and gas fields that will be tied back by way of subsea developments," Fowler said.

Including second and third phase activity at deepwater fields, he said, "virtually all the deepwater projects that are out there in the gulf at the moment, sooner or later, will involve subsea components or aspects of subsea development."

Rick Hill, vice president of sales and marketing, Aker Omega Inc., Houston, says more reliable, more standardized subsea equipment is lowering the threshold of economic deepwater fields.

"We used to think in terms of 100 million bbl fields as being economic to develop in deep water," Hill said. "Today, we're talking more in terms of 30-50 million BOE."

ROV uses increasing

Greater water depth also affects operators' well maintenance and workover costs by limiting the types of tools and equipment required.

Because atmospheric diving systems (ADS) can be used to water depths of about 2,300 ft, having the option to use such a system is a key factor in determining whether an operator can use flanged connectors in a subsea production system.

Hill says that if a company can use an ADS, it doesn't have to use a mechanical connection system that must be deployed by more costly procedures involving remotely operated vehicles (ROVs).

"A company can do well intervention off a diving support vessel at a reasonable cost," Hill said. "If it has to move a rig to the well site, that can take a lot of money."

Hill says most of the deepwater developments in the gulf are using ROV capabilities in some way. The water depths reached so far by oil and gas developments in the region haven't challenged the depths to which ROVs can be used effectively.

What has changed, he says, is the reliability of mechanical connectors, deployment systems, and ROVs.

"That's an area companies have concentrated on," Hill said.

Also, service companies have developed new tools for use by ROVs, mostly as a result of operating needs.

"From the viewpoint of service companies, we can adapt to almost any connector technology an operator wants to use," he said. "As long as we can take the tool down and actuate, we don't care."

Tom Ames, an advanced senior engineer for Marathon Oil Co., says using ROVs to do more work in the gulf has been a continuing evolution for subsea technology. "Increasing the tasks an ROV can do subsea is a big factor in deep water," he said.

Subsea technological advances

As subsea wells have become more common in the gulf, a trend has emerged toward smaller, more compact, modular units that fit readily through moonpools of offshore rigs and production facilities.

More compact, easier-to-handle equipment packages enable operators to avoid costs associated with use of heavy lift equipment to install subsea manifolds.

Ames says another key to greater acceptance of subsea production systems is development of retrievable subsea components.

"Primarily, the control pod and choke are the two subsea components operators are most concerned about," Ames said. "But valve technology has evolved to the point where we see the gate valve itself as one of the most reliable components we have subsea.

"Of course, if anything goes wrong with the gate valves, we pull the entire tree."

Ames and others agree a host of incremental subsea advances-as well as some key giant leaps-have converged to help operators successfully take the technology into the gulf's deepwater. The latter category includes the advent of steel catenary risers, steel umbilicals, concentric completion-workover risers, and horizontal trees.

Steel catenary risers enable operators to install subsea flow lines at platforms and FPSs at such great distances from subsea wells that flexible steel pipe likely couldn't withstand the required manipulation.

More capable umbilicals

Steel umbilicals at some deepwater locations have replaced thermoplastic cased umbilicals, enabling operators to extend subsea direct hydraulic control systems for as much as 8-10 miles and expanding the pressure ranges umbilicals are able to handle.

At Troika field, in 2,721 ft of water on Green Canyon block 244, Marathon, BP, and Shell are studying a subsea plan that would involve using a 15 mile long, stainless metal umbilical to tie back subsea hydraulic facilities to Bullwinkle platform on Green Canyon Block 65.

Shell last year at Popeye installed the gulf's first concentric completion/workover riser, a design that extends riser water depth capabilities beyond 3,500 ft. The concentric design allows operators to apply much greater loads to the riser system. Shell next year plans to use the concentric completion/workover riser at Mensa.

Starting with Mensa and Troika, operators plan to install the gulf's first multiplex control systems at the lower workover package on the riser base, as opposed to direct hydraulic control lines used commonly in shallow water. The design reduces the size of line required, allowing more subsea functions in deeper water. Also, the system operates production system hydraulic controls by electric solenoid, shortening response time, an issue in deeper water.

Many in the industry consider horizontal trees to be a big advantage in deep water because the design allows operators to more easily reenter subsea wells for workover and maintenance and eliminates the need for a completion/workover riser.

Subsea integral to development

Given recent technical advances, more reliable subsea equipment and tools, and the trend toward standardization-as well as the extreme water depths thought to hold the gulf's best oil and gas prospects-it appears subsea technology is poised to blossom in the region.

But many factors beyond the control of technology-rig day rates, equipment availability, oil and gas prices-could reverse the decline of subsea development costs or raise the economic thresholds of deepwater fields.

For example, spending for drilling and completion can account for as much as 60% of the capital cost of developing a deepwater field. Meantime, rig rates in the gulf are increasing and expected to continue to rise.

Given potential effects of such nontechnical factors, trimming 10-15% from the cost of a subsea production system doesn't necessarily mean more deepwater fields will be economic to produce.

In addition, relative capabilities of deepwater drilling, completion, production, and pipeline equipment also could hamper subsea development. A company might be able to successfully drill and complete a well in 7,500 ft of water, for example, but be unable to install production equipment from the surface.

In essence, many subsea production issues boil down to whether or not to have that capability. Operators have to deal with well control issues, fluid control issues, well intervention issues, and more.

"At the end of the day, it doesn't matter whether a company is putting a spar at surface, a TLP, or whatever," Hill said. "To produce a deepwater field, it's still got to be able to case the well, complete it, and get the oil or gas into the template.

"Subsea technology is integral to that, period."

Copyright 1996 Oil & Gas Journal. All Rights Reserved.