Since Placid drilled a wildcat in 500 m of water on Mississippi Canyon Block 113 in the Gulf of Mexico in 1976, deepwater operations have become increasingly alluring.
Don Henery, Shell Offshore Inc.'s manager of offshore engineering and pipelines, told Offshore Northern Seas conference in Stavanger late last month that by yearend 1995, there had been almost 300 exploratory wells and more than 50 development wells drilled in Gulf of Mexico waters more than 450 m deep.
"At least 36 confirmed discoveries have been made to date in water depths greater than 450 m," said Henery. "Of these, 18 have been found by Shell. It appears that at least 2.4 billion bbl oil equivalent (BOE) reserves have been discovered to date, with two thirds of this from Shell projects. Further potential for Gulf of Mexico deepwater development is estimated at 8-15 billion BOE."
Henery said there are nine producing projects in deep water Gulf of Mexico: Jolliet, Auger, and Mars tension leg platforms (TLP); Cooper production semisubmersible; and Mississippi Canyon, Zinc, Manhattan, Tahoe, and Popeye subsea developments.
Projects under construction are Pompano and Mensa subsea developments, Allegheny production semisubmersible, Neptune and Vancouver spar platforms, an Amerada Hess Corp. compliant tower, and Ram/ Powell and Ursa TLPs.
"In 1995," said Henery, "the entire Gulf of Mexico produced 327 million bbl of oil and 3.4 tcf of gas. Of that, less than 4% was from water depths beyond 450 m. By the year 2000, however, it is likely that 25-35% of production from the Gulf of Mexico will come from deep water."
Higher well rates
The significance of individual well rates and reserves per well to deep water developments cannot be overstated, said Henery. Early Gulf of Mexico deepwater projects were based on producing in shallow Gulf waters, where 1,000 b/d output was good and 2,000 b/d wells rare.
Planning for Auger and Mars was based on 3,000 b/d per well, but Auger is producing 13,000 b/d from some wells and Mars, Ram/Powell, and Ursa are expected to yield 7,500-15,000 b/d per well.
"The availability of these world class wells has considerably improved the drilling cycle time," said Henery, "and has significantly reduced the number of wells required, which in turn has simplified the production design system."
Improved well deliverability also is expected for gas projects. Tahoe phase one is expected to deliver as much as 30 MMcfd/well, while phase two yields of 70 MMcfd per well are anticipated through use of larger tubing and horizontal wells. Popeye wells were expected to average 60 MMcfd, but some have produced as much as 105 MMcfd.
Greater water depths
"The industry has the ability to operate successfully in water depths up to 1,000 m," said Henery, "and we believe this can be extended to at least 1,650 m in Mensa in the next few years.
"Shell has explored previously in 2,200 m of water and is currently initiating exploratory drilling in 2,400 m. The next challenge will be to find if world class reservoirs exist in the ultradeep waters of the outer Gulf of Mexico."
Jon C. Cole, senior vice-president of Sonat Offshore Drilling Inc., said the Gulf of Mexico and Brazil account for almost 75% of all deepwater activity to date, with the remainder of the world relatively unexplored.
Of 150 wells drilled in water deeper than 1,000 m to date, said Cole, only six operators and four drilling contractors have drilled more than five. The six operators account for 86% of all deepwater wells, while the four contractors account for 95%.
Dynamically positioned rigs were used on 77% of these wells, although recently fourth generation semisubmersibles with chain/wire mooring systems have been used increasingly in deep water.
"The purpose of these statistics," said Cole, "is to illustrate the industry's relative lack of experience in deep water when compared with almost 55,000 offshore wells that have been drilled."
Cole said deepwater exploration is gathering momentum off West Africa, along Northwest Europe's Atlantic margin, and off several Southeast Asian countries.
"For the near term, however," said Cole, "proven deep water markets in Brazil and the U.S. Gulf of Mexico, combined with emerging demand off Norway and the U.K., will provide the impetus for growth."
Technology has played a major role in improving the economics of deepwater development, said Cole, with advances in 3D seismic and subsea and floating production systems combining with horizontal drilling to lower development costs greatly.
Cole cited Shell's Gulf of Mexico deepwater projects as an example of falling costs: the capital portion of daily production costs was $13.25/1,000 BOE/day with Auger in 1994 compared with an anticipated $6.80/1,000 BOE/day with Ursa in 1999.
"As the industry's experience in deep water grows," said Cole, "efficiency will improve and the high cost of deep water drilling will decrease. Through further technological advances and capital investment in the deepwater fleet, the future will provide numerous opportunities for growth."
Brazilian experience
Petroleos Brasiliero SA (Petrobras) is one of the key pioneers of deep water techniques, with research ahead of development work in Albacora, Maslim, and Barracuda fields resulting in the first production in more than 1,000 m of water.
Antonio Carlos de Agostini, managing director of exploration and production at Petrobras, told delegates Brazil's oil and gas reserves total 11 billion BOE, with 41% of that total located in 400-1,000 m of water and 22% in water deeper than 1,000 m.
"Brazil's current oil production is 820,000 b/d," said Agostini, "not enough to meet market demand of 1.4 million b/d. In 2005, Petrobras oil production could reach 1.65 million b/d, but we must develop further deepwater fields. Around 70% of our oil production will come from deep water in 2005."
Petrobras produces its deepwater fields with production semisubmersibles and floating production, storage, and offloading (FPSO) ships depleting subsea wells.
"I would like to share our vision of an ultradeep water production system," said Agostini, "where there will be a few high productivity subsea horizontal wells, connected to subsea manifolds, and then to subsea boosting systems.
"The wells may be equipped with an electric submersible pump. From the boosters the production will be sent to an FPSO located in 1,000-1,500 m of water through flexible or steel pipes.
"The produced oil will be transferred to a shuttle tanker connected in tandem, while the gas phase is compressed either for reinjection or to be sent to shore via steel pipelines."
Agostini said phased development, with risks and capital exposure minimized, will allow cash flow to finance subsequent phases: "This has been the Petrobras approach over the last few years, and we believe that it can be successfully applied worldwide."
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