Barbara Saunders
Staff Writer
Mahogany platform exemplifies the risks and rewards of subsalt operations. Individual wells have come on stronger than anticipated, but bringing them on can be slow and challenging when drilling through salt layers that can be more than 3,500 ft thick. Photo courtesy Anadarko Petroleum Corp.
A tight rig market and the challenges of operating in a geological environment are dampening some of the enthusiasm industry once exhibited in the subsalt play in the Gulf of Mexico.
Because of the high costs that can be involved, subsalt exploration is proving to be a game only for the hardy and well-heeled: Along with spectacular successes in the last few years have come some equally spectacular failures.
A dry hole can cost $30 million, and drilling through salt sills a half-mile or more thick can push technology to expensive new limits and cause frustrations to mount, operators acknowledge.
Nevertheless, companies continue to drill to subsalt targets, pinning their hopes on better methods of predicting what's beneath the gulf's thick salt-and on the belief that one significant commercial success may offset the cost of several dry holes.
Ultimately, the stakes are highly promising, with estimated reserves of 1.2 billion bbl of oil and 15 tcf of natural gas in 25 significant subsalt accumulations, according to available industry data on what's been found so far.
What's been found
In the 31/2 years since subsalt exploration has taken off in earnest, 29 subsalt wildcats have been drilled and 11 have yielded discoveries.
That indicates a success rate of about 38%. But the odds of success appear to have improved in the last 2 years: Nine of 21 subsalt wildcats drilled since the beginning of 1995 have hit oil for a success rate of about 43%.
The first subsalt discovery to be commercially developed, the 1993 Mahogany strike by a Phillips Petroleum Co.-led group, is now producing. Three more-Enchilada, Chimichanga, and Agate-are being readied to go on stream, and at least two more- including Gemini and Monazite-are being evaluated for potential development.
That's steady progress, given that before Mahogany's discovery only 16 subsalt and saltweld (drilled between two faults) wells had been drilled in the gulf starting in 1983 with a well operated by Placid Oil Co. Most wells that followed in the 1980s were accidental salt penetrations that occurred while operators were drilling to test reflections onto salt that mimic hydrocarbon accumulations, according to the U.S. Minerals Management Service.
While no oil was found during the first 7 years of the subsalt search, operators were encouraged by finding reservoir-quality sands.
Then, in 1990, Exxon hit pay with its 1 Mickey well, drilled in 4,300 ft of water. Mickey found five hydrocarbon zones at 10,000-13,000 ft that contain an estimated 100-200 million bbl of oil. But due to water depth, Mickey has never been developed, and its future commercial viability has yet to be determined.
Three years later, Phillips successfully teamed with Anadarko Petroleum Corp. and Amoco Production Co. The group's 1 Mahogany strike, in 370 ft of water about 75 miles off Louisiana, is producing on Ship Shoal South Addition Blocks 349/359. The field is providing the industry's first gulf experience developing an oil field below the tricky salt sills.
A spate of successful drilling followed, and a new subsalt era began to unfold. Within the span of 1 year, industry had three more subsalt successes-1 Teak discovery, 2 Mahogany appraisal, and 1 Enchilada discovery- and 1995 brought four more successful wells, 3 and 4 Mahogany appraisals and the 1 Chimichanga and 1 Gemini discoveries (OGJ, Mar. 4, 1996, p. 37).
Imaging advances
The success of Phillips and other operators with subsalt exploration is largely due to advances in seismic imaging.
As recently as 5 years ago, drilling through and beneath salt formations was largely a hit-or-miss proposition, as salt severely distorts seismic reflections. Since then, once-proprietary 3D seismic technology has come into more widespread use, providing a cube of data versus the slice available in 2D.
The methods used to process seismic images have improved, as well, considerably reducing distortions posed by salt (OGJ, Sept. 27, 1993, p. 41; May 2, 1994, p. 33).
In the past, seismic images were presented in terms of "time migrations," or how quickly a reflected signal travels. They also were typically analyzed after all seismic signals were processed, known as post-stack.
Today, supercomputers can convert seismic images to actual depth projections and assess data before the signals are processed, or pre-stack. The most accurate images are derived from 3D, pre-stack depth migrations, but they are very time-consuming, costly processes, about 10 times more expensive than a conventional 3D time migration, according to John Cramer, geophysicist for Diamond Geophysical Corp., Houston.
Currently, the gulf is hopping with multi-client 3D seismic acitivity, Cramer said, but it's a slow, tedious process: mapping one block requires mapping nine blocks surrounding it to record all necessary information. One multi-client 3D survey of a 60-block portion of the gulf's subsalt play requires about 18 months to complete, Cramer said.
But better imaging hasn't been a boon to everyone exploring beneath the salt. Louisiana Land & Exploration Co., New Orleans, for instance, is postponing further subsalt work after participating in three wells that were either dry or non-commercial. The company believes seismic imaging of the subsalt still needs improvement, an official said.
Houston's Vastar Resources Inc. late in 1996 plugged a $15 million dry hole, but said at the time it intends to keep a strong subsalt focus. More recent statements by the company indicate that Vastar has tempered its position, and will focus for the time being on other gulf plays.
Among those companies still active, the euphoria touched off by a string of early discoveries has given way to a more subdued pragmatism, as operators cope with some very real challenges.
Getting there
Drilling through salt is not new; it has been done for decades in the Gulf of Suez and in portions of the North Sea (see related story, p. 22).
But those areas can't be compared directly with the Gulf of Mexico, operators say, due to differences in geology.
In areas where subsalt activity has occurred before outside the gulf, the character of the subsalt rock was generally well-known-older and, typically, more stable.
In the Gulf of Mexico, older Jurassic salt has been horizontally thrust into younger Tertiary sediments, in a fashion similar to the U.S. Overthrust belt, so Tertiary sections can occur beneath the salt. Horizontally emplaced salt-which underlies about 30% of the gulf-is what makes the play promising, but it's also what's creating a host of challenges for operators, in addition to working often in deep waters.
In the gulf, drilling through thick salt into unstable rock is providing the industry a learning experience that may prove useful in other parts of the world with complex subsurface geology under salt layers.
"It's like toothpaste inside layers of sand," explained Diamond Geophysical's Cra- mer. "It wants to squirt up. Well bores can collapse."
Learning curve
"Everything we're doing right now is part of a giant learning curve," explained Tom Early, Phillips's subsalt exploration manager.
As of the end of June, combined output from three Mahogany wells was about 16,000 b/d of oil and 22 MMcfd of natural gas. A fourth well was drilling ahead. Phillips expects peak rates of 33,000 b/d and 40 MMcfd from six wells.
Although well on its way to anticipated peak output, work is behind schedule, and Phillips has been frustrated by a variety of operating difficulties. Some of the early challenges included having to modify a heat exchanger to cool hotter-than-expected crude (OGJ, May 12, 1997, Newsletter).
Lately, it's been slow going with the drill bit and there has been trouble keeping the hole clean, according to Phillips. Not helping matters, wells are now producing water for reasons not yet ascertained. That has kept oil and gas output from climbing during May and June despite the third completion.
Jeff Ogilvie, exploration geophysicist for Texaco U.S.A., operator of Gemini, detailed some of the challenges that company has faced.
"As prospects go, we probably had one of the least severe salt problems. We drilled very quickly through the gumbo zone," an area beneath the salt where the rock is soft and extremely high pressure often exists. "We did not have casing problems at that point, something we had anticipated."
Said Ogilvie, "Just because it's well-imaged does not mean you can understand the structure...Predicting when things should come in at what depth, making structural maps, those are still major issues."
Another problem that Texaco and other operators noted has been the need to switch from water-based to synthetic oil-based drilling mud or water-based mud that's super-saturated with salt to get through salt layers.
"Synthetic mud compromised certain evaluation programs," Ogilvie said. "We could not run certain tools," such as HC (hydrocarbon) typing.
Added to this, high pressures and extreme depths often require use of heavy-walled intermediate casing strings.
Sticker shock
These challenges, combined with higher day rates in a tight rig market, add up to extremely high operating costs.
"Everyone's experiencing sticker shock right now," said one source. "The slightest glitch can be very costly.
"What might have cost $250,000 to overcome a year or two ago might cost $1-2 million now."
The high costs and slow pace of subsalt drilling can make for a rocky career ride for oil and gas executives, also.
Said one insider: "It's almost like musical chairs, how quickly you'll see senior managers with subsalt expertise shifted around. They survive by going to other companies, but it's hard to follow org (organization) charts these days."
Despite the challenges, about a dozen companies are still active in the gulf's subsalt play and have established strong lease positions.
Ups and downs
Even among the most successful companies, subsalt exploration has had its ups and downs.
Not long after the Mahogany discovery, for instance, Phillips and Ana- darko discovered Teak in about 295 ft of water in South Timbalier Block 260 off Louisiana.
In the best of four tests, the well flowed 3,742 b/d of oil and nearly 6 MMcfd of gas; the worst test yielded only water.
Still, the well provided experience operating in a different type of subsalt trap from Mahogany, noted Jim Fox, Phillips' subsalt exploration manager. But it was a costly lesson: Teak cost $20 million and took 8 months to drill.
Similarly, Anadarko had to plug and abandon its Monazite discovery well due to extensive sand production during testing, but it plans to drill a second well on the prospect by late this year.
The company has fared better with Agate, owned 50-50 with Phillips, which flowed 4,100 b/d of oil and 24 MMcfd of gas on test.
Agate, on Ship Shoal South Addition Block 361, will be tied back to the nearby Mahogany platform. Production is slated to come on stream by mid-1998.
But en route to success, Anadarko encountered four dry holes at Siskin (South Timbalier 310), Eagle (South Timbalier 231), Alexandrite (Ship Shoal 337), and Mesquite (Vermilion 349). Still, a company official said Anadarko expects the successful wells will offset its dry hole costs.
Buoyed by its good experiences, Anadarko is now drilling with operator BHP Petroleum Pty. Ltd. on the Lion/Emerald prospect on South Timbalier Block 299.
1997, the future
So far, 1997 has brought only one subsalt discovery, at the Conger prospect in Garden Banks Block 215.
A well drilled to 21,652 ft in about 1,500 ft of water tapped about 300 ft of net pay both above and below the salt (OGJ, June 9, 1997, p. 28). Operator Amerada Hess Corp. plans an appraisal well in the third quarter.
If the field proves commercial, plans are to tie a future production well back to the compliant tower platform at Amerada's nearby Baldpate field in the Garden Banks area (see related story, this page).
Perhaps sobered by the high costs of some expensive failures, most of the industry's efforts this year appear to be centered on acquiring a better seismic picture of what underlies the gulf's salt deposits.
Drilling activity is down from last year's peak, when 11 subsalt wells were spudded in the gulf.
So far in 1997, only four subsalt wells have been spudded compared with seven of the total 11 at this time last year.
Operators stress caution will be the future watchword for the gulf's subsalt play, as they seek answers to the basic questions: Where can substantial reserves be found, and how economically can they be brought on stream?
Poseidon pipeline expands in Gulf of Mexico
More crude oil pipeline infrastructure is planned or has been completed in the Gulf of Mexico to accommodate mounting production.
Poseidon Oil Pipeline Co. LLC, which has the capacity to move as much as 400,000 b/d of crude to Gulf Coast area refineries from fields in deep and medium-depth waters off Louisiana, has entered into new life-of-reserve commitment agreements on Baldpate field output with operator Amerada Hess Corp. and partner Sun Operating Ltd. Partnership.
Poseidon is a 50-50 joint venture of units of Texaco Inc., Leviathan Gas Pipeline Partners LP, and Marathon Oil Co.
Poseidon
The system totals about 200 miles of 16-in., 20-in., and 24-in. trunk pipeline (OGJ, Jan. 20, 1997, p. 37).
It extends from a platform in 1,100 ft of water serving Garden Banks Area Blocks 72/117 and Spectacular Bid and Spend-A-Buck fields, operated by Flextrend Development Co. LLC, a Leviathan unit (OGJ, Oct. 23, 1995, p. 40), to Caillou Island off Louisiana.
From there, oil is moved to shore via a combination of Texaco Pipeline Inc.-operated 8-in., 10-in., 12-in., and 16-in. pipelines to a Texaco tank farm at Houma, La., for shipment west to Port Arthur on a Texaco-operated 22-in. pipeline; north from Houma via a 16-in. segment to a terminal at St. James, La., for further shipment to Exxon Corp.'s Baton Rouge refinery; and east via a 24-in. segment to complexes at LaRose and Clovelly, La.
New areas, companies served
Current work involves laying a new segment from Caillou Island to Houma in a third work phase, involving 48 miles of 24-in. pipeline.
New offshore spurs were completed recently.
A new 16-in., 17-mile spur handles production in 1,650 ft of water from Baldpate field, straddling Garden Banks Area Blocks 259/260. The spur connects with the 117-mile, phase one-segment on South Marsh Island Area South Addition Block 205, where Mobil Exploration & Producing U.S. Inc. operates a platform.
Poseidon phase one includes both 16-in. and 20-in. pipeline.
Phase one includes production from a platform on Vermilion Area South Addition Block 398, operated by Newfield Exploration Co., Houston. Also, phase one takes subsalt output from Phillips Petroleum Co.'s Mahogany platform, developing reserves from Ship Shoal Area South Addition Blocks 349/359 (see related story, p. 19).
Oil from Shell Offshore Inc.'s Boxer and Bullwinkle platforms is shipped to the Eugene Island area by separate pipeline. Marathon, Shell, and BP Exploration Inc.'s planned Troika subsea development in more than 2,600 ft of water will be tied into Bullwinkle. Troika is slated to begin production by yearend.
A 15-mile flowline will be tied back to Bullwinkle platform in about 1,350 ft of water and will set a Gulf of Mexico distance record. The second of two pre-drilled wells is currently drilling ahead.
What phase two involves
New spurs totaling 58 miles of 16-in. pipeline link Marathon/Texaco production in the Ewing Bank Block 873 area with a platform on Ship Shoal Block 141 via a platform on South Timbalier Area Block 212.
The segment was contributed to Poseidon by Marathon and Texaco. It connects with Poseidon's 24-in., 79-mile, phase-two segment, beginning at Ship Shoal Area South Addition Block 332.
Phase two plans call for tie-ins with Tatham Offshore Inc.'s Sunday Silence field development, covering Ewing Bank Blocks 958, 959, 1002, and 1003 in 1,312-2,625 ft of water, and Enserch Exploration Inc.'s Allegheny project on Green Canyon Block 254 in about 3,200 ft of water.
Tatham, a Leviathan affiliate, is a stand-alone company owned 37% by DeepTech International Inc., Houston.
Tatham was the first company to receive approval by the U.S. Minerals Management Service for royalty relief under the 1996 Deep Water Royalty Relief Act.
Copyright 1997 Oil & Gas Journal. All Rights Reserved.
