Reservoir optimization seen key to thriving today

Reservoir optimization is one of the key technologies for oil and gas companies as they strive to maximize asset values in the face of low oil prices. That was the focus of a talk, at the Offshore Northern Seas conference in Stavanger late last month, that related application of the concept to fields in Venezuela and off the U.K. In another presentation at ONS, deployment of one currently popular technology-floating production, storage, and offloading systems (FPSOs)-was revealed to have

Sept. 7, 1998

6 min read

Reservoir optimization is one of the key technologies for oil and gas companies as they strive to maximize asset values in the face of low oil prices.

That was the focus of a talk, at the Offshore Northern Seas conference in Stavanger late last month, that related application of the concept to fields in Venezuela and off the U.K.

In another presentation at ONS, deployment of one currently popular technology-floating production, storage, and offloading systems (FPSOs)-was revealed to have pitfalls.

IRO applications

Victor E. Grijalva, vice-chairman of Schlumberger Ltd., told delegates that integrated reservoir optimization (IRO) has four elements: reservoir characterization, development planning, field implementation, and reservoir monitoring control. Grijalva said they fit together in a closed loop to provide a clearer picture of the reservoir.

"Although IRO is applicable to a variety of fields," said Grijalva, "it is particularly attractive for: small, marginal fields where profitability hinges on optimized production strategies; for complex, older fields where specialized technology is needed; and for fields where operators have limited experience, insufficient resources, or require improved risk management."

Development of IRO is a long-term process still in its infancy, said Grijalva, and one that will evolve continuously in coming years. Much of the required technology is available and proven, but there are gaps.

"In the not-too-distant future," said Grijalva, "most of the components will be in place. Then the ultimate asset tool could treat the reservoir much as a modern plant using computer control, sophisticated sensors, actuating devices, system interrogation, and smart alarms to optimize its output in real time."

Venezuelan project

An example of an IRO project is the alliance between Lasmo plc, London, and Schlumberger for redevelopment of Dacion field in eastern Venezuela. Lasmo secured the contract last year in Venezuela's third licensing round.

"At the time of licensing," said Grijalva, "Lasmo had no infrastructure in place in Venezuela and needed an experienced local partner.

"The alliance is directed at maximizing asset value over the 20-year life of the contract-without Schlumberger taking equity-by applying an integrated reservoir management approach guided by joint multidisciplinary reservoir characterization and production enhancement teams."

Dacion currently produces about 10,000 b/d of oil from 111 wells. So far, the field has yielded more than 300 million bbl of oil, which is less than 14% of original oil in place.

"The project's goals," said Grijalva, "are to increase production to more than 90,000 b/d of oil and ultimate recovery to 35%.

"The initial development plan calls for the reactivation of more than 50 wells and the drilling of more than 200 production infill wells to achieve the production target by early 2001.

"A rigorous reservoir monitoring program will follow the performance at the well and formation level."

Northwest Hutton

Grijalva said redevelopment of U.K.'s Northwest Hutton field by Amoco (U.K.) Ltd. was not a full IRO project, but a major evolutionary step to IRO.

Amoco expected Northwest Hutton to fall below its breakeven production limit in 1996 and thought it would become, in 1997, the first U.K. North Sea field to be abandoned.

"Reservoir studies, however," said Grijalva, "indicated that factors other than natural decline could have been major contributors to poorer-than-expected performance.

"A joint Amoco-Schlumberger technical review concluded that there was a high probability of significant additional recoverable oil, up to 20-50 million bbl. A four-phase redevelopment plan was jointly proposed.

"The first phase involves well bore operations, gas lift optimization, and data acquisition; the second, a two-pronged approach to fracture and diagnostic matrix simulation to remove skin damage and provide additional reservoir data.

"The third phase hinges on generating opportunities to increase recoverable reserves, while the fourth focuses on seismic acquisition across the field."

Grijalva said the first two phases have been completed and raised production capacity to 10,000 b/d from 6,000 b/d. Current production is 8,000 b/d: "Significant, but somewhat below projection."

Phase 3 was deemed attractive when oil prices averaged about $22/bbl: "The drop to $13/bbl has led to a reevaluation of what further actions should be taken and when. In the interim, phase 4 seismic work has been approved and scheduled."

FPSO lessons

Chris Gray, new developments manager, Conoco (U.K.) Ltd., told ONS delegates about experience in FPSO development of MacCulloch and Banff fields off the U.K., the former with a leased converted tanker and the latter with a leased newbuild ship (see Industry Briefs, p. 42).

Gray said that, at the time of the development contract awards, the contracting community was not developed enough to provide reservoir management but appeared well-versed in FPSO projects.

"Our engineering and management experience on both MacCulloch and Banff," said Gray, "has led us to the conclusion that a totally 'arm's length' approach can lead to elements such as operability or schedule being worse than expected.

"If the contractor is only advised what is needed to be delivered, and little interaction occurs on 'how,' there is a degree of uncertainty around delivering the owners' expectations."

Conoco gave out only functional specifications for MacCulloch and Banff field developments: "There was freedom for the contractors to choose any development concept and the financial terms under which these would be provided."

Gray said the advantage of functional specifications is that they encourage innovative solutions, such as the use of a Ramform delta-shaped ship in Banff, a design previously used only in seismic survey ships.

"There is nothing inherently disadvantageous with converted tankers compared with newbuilds," said Gray. "However, there are complications if conversion is not managed effectively and they do not necessarily save as much time as originally expected."

Gray cited a 1997 survey that showed that construction of conventional newbuild hulls takes 22-27 months, converted hulls 12-15 months, and topsides 18-24 months.

The topsides set the critical path, and while the Banff hull was built in only 10 months, Gray said, Conoco found that the typical FPSO bidding process is forcing engineering work to be cut short.

"The state of engineering at the point of bid with a functional specification," said Gray, "is not very much more advanced than conceptual engineering. The bidders then have to perform preliminary engineering in 6-8 weeks, while also devising their commercial strategy.

"Far too much is going on in parallel with the inevitable incomplete definition at the time of placing equipment orders. The (lesson) from this is to allow enough time for the contractors to perform sufficient preliminary engineering during and after the bid."