Print this story | Email it to an associate

North America's Source for Oil and Gas News
November 2001

Vol. 6, No. 16 Week of November 11, 2001

Prudhoe Bay field owners talk to AOGCC about gas cap water injection project

Injection process expected to increase oil production 200 million barrels; with a major gas sale, that could drop to 135 million barrels

Kristen Nelson

PNA Editor-in-Chief

The Alaska Oil and Gas Conservation Commission requires the Prudhoe Bay field owners to investigate ways to mitigate declines in pressure at the field and to provide an annual report to the commission on such efforts.

A requirement for such studies is no longer appropriate, field owners told the commission at an Oct. 30 hearing, because a project approved by field owners in June will lessen the drop in pressure at Prudhoe Bay, as well as improve oil recovery.

Reservoir pressure decline — a natural side effect of production at Prudhoe Bay — is adversely affecting all recovery methods, representatives of the Prudhoe Bay working interest owners — BP Exploration (Alaska) Inc., ExxonMobil Production Co. and Phillips Alaska Inc. — told the commission.

In June, field owners approved a gas cap water injection project which will mitigate pressure decline at the field and increase production by as much as 150 million to 200 million barrels of oil.

Field operator BP has already begun permitting for the project. (See Oct. 7 issue of PNA.)

At the Oct. 30 hearing, representatives of the field owners described the gas cap water injection project, which calls for ramping up to an injection rate of 650,000 barrels a day of seawater into the eastern portion of the Prudhoe Bay gas cap.

Team formed in 1991

Water injection projects are ongoing at the Prudhoe Bay oil rim, but those projects have limited pressure-support potential compared to the gas cap water injection project. The water projects have been justified based on recovery benefits, rather than pressure-support benefits, Perry Richmond, BP's east-west Prudhoe Bay water resource manager, told the commission.

In 1991, he said, the Prudhoe Bay working interest owners formed a multi-company pressure studies initiative team to evaluate pressure mitigation options for the Prudhoe Bay oil pool. The team looked at several options, Richmond said, but most were rejected because of high capital costs and/or limited recovery benefits.

Gas cap water injection, however, had both significant recovery benefits and reasonable capital costs. The process was recommended for more detailed study.

In June, the owners approved the Prudhoe gas cap water injection project.

Reservoir pressure would be maintained

Bharat Jhaveri, consulting reservoir engineer for BP, told the commission that average reservoir pressure at the Prudhoe Bay field has been declining at a rate of 25-35 psi per year, reducing the efficiency of every recovery mechanism operating in the field. The proposed gas cap water injection project, Jhaveri said, would maintain a level reservoir pressure until the end of water injection in 2022.

The increased pressure improves efficiency of all recovery mechanisms and BP estimates incremental liquid recovery of 150 million to 200 million barrels. Jhaveri said that the range reflects modeling uncertainties and the availability of seawater.

Commissioner Julie Heusser asked about seawater availability and Richmond said that a project to move produced water to where it would be most useful — “water wheel” — hasn't yet been approved. He said he didn't know when water wheel will be implemented, but said that when it is, it could provide additional seawater by making produced water available for injection at Point McIntyre. There will be more water and higher injection rates if the water wheel project is approved, he said.

Piston-like flood front the goal

Matt Maguire, senior reservoir engineer with Phillips Alaska Inc., told the commission that there are different objectives for water injection in different areas of the field. The location of the water injection wells was chosen to keep injected water in the eastern part of the gas cap, and to limit interference in three other areas of the field: In the gas injection area, he said, the goal is to avoid significant impact on gas injection wells, because reduced gas injection reduces oil production. In the water flood area, gas cap injection should complement existing water flood. In the gravity drainage area, the goal is to preserve oil recovery.

The key to achieving these objectives, Maguire said, “is to have an efficient piston-like water displacement process.”

In the gas cap, displacement of gas by water is very efficient and essentially piston-like because gas is 100 times more mobile than the water than displaces it. Gas cap water injection has only a small impact on gas injection which occurs primarily late in field life when the gas oil ratios are higher.

In the water flood area, oil recovery is slightly higher with gas cap water injection. Oil recovery is also slightly higher in the gravity drainage area because water limits gas encroachment and displaces some oil.

Less oil recovered with major gas sale

Lynn Schnell, who has worked on development and reservoir management of Prudhoe Bay with ExxonMobil Production Co. almost continuously since 1968, told the commission that a major gas sale would reduce the incremental oil recovery from gas cap water injection — but that gas recovery potential is virtually unchanged by gas cap water injection.

“In general,” Schnell said, “the water injection project will maintain reservoir pressure at a higher level under any currently foreseeable gas sales scenario.”

In the case of a major gas sale beginning in 2008, pressure in the reservoir will drop at about 135 psi per year through 2025. The pressure drop moderates in later years as gas sale rate declines due to pressure depletion. The higher pressure from gas cap water injection means, he said, that even with a major gas sale oil recovery mechanisms operate more efficiently.

If the Prudhoe owners move forward with a major gas sale, incremental oil recovery from gas cap water injection would be 135 million barrels — compared to a maximum of 200 million barrels without a major gas sale.

Schnell said there are three reasons for the reduction in oil recovery: The volume of gas available for injection is reduced; ability of injected gas to vaporize oil diminishes with lower reservoir pressure; and with lower pressure due to a gas sale the oil becomes more viscous, it drains more slowly and less is recovered.

Ultimate gas recovery, however, is essentially unchanged by gas cap water injection, primarily, Schnell said, because abandonment pressures can be realized with or without the project.

Why not 5 years ago?

Commissioner Julie Heusser asked Schnell why gas cap water injection was appropriate now — and not five years ago?

Schnell said that the oil rim was much less mature five years ago and there would have been a greater potential for adverse impacts because there were more barrels at stake.

Asked by Heusser about a timeline for consideration of gas cap water injection Schnell said that the companies have considered it from the beginning, but in the early years, he said, you could inject too much water too soon in relation to the life of the oil field.

Did you find this article interesting? Email it to an associate.
Print this story

Test Petroleum News - Phone: 1-907 522-9469 - Fax: 1-907 522-9583
[email protected] --- --- S U B S C R I B E