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Prudhoe depletion modifications, end of seawater injection at 2 sites
Kristen Nelson Petroleum News
BP Exploration (Alaska) has asked the Alaska Oil and Gas Conservation Commission to approve ending seawater injection at drill sites DS-01 and DS-12 at Prudhoe Bay and diversion of the seawater previously used in those areas to pressure maintenance in a different part of the Prudhoe Oil Pool.
The company said those actions would increase ultimate oil recovery from the Prudhoe Oil Pool.
The commission has scheduled a public hearing for Jan. 21 at 10 a.m. at its Anchorage offices and will accept written comments through the end of the hearing.
Sea Water Optimization Plan In its application the company describes a Sea Water Optimization Plan, SWOP, which “differs from current depletion operations and … would minimize waste while increasing ultimate recovery.”
The Prudhoe Oil Pool, POP, operates with “a peripheral pattern water flood” which uses miscible gas injection for enhanced oil recovery, the company said. The water flood area surrounds a central region operating under gravity drainage and using “oil vaporization by lean gas injection for EOR.” A narrow section of the reservoir, at the boundary between the gravity drainage and water flood areas, “is influenced by both GD and WF mechanisms, the Gravity Drainage-Water Flood Interaction (GDWFI) area,” BP said.
Depletion mechanisms and the areas to which they are applied have been “static since established in the mid-1980s,” the company said.
SWOP seeks to increase POP recovery by ending waterflood at drill sites 01 and 12, enabling “expansion of the more favorable gravity drainage and lean gas oil vaporization mechanisms while reducing WF impacts on the GDWFI boundary region.”
The roughly 60,000 barrels per day of injection water currently used at the two drill sites comes from the seawater injection system and would be diverted to the gas cap seawater injection project that has supported fieldwide reservoir pressure since 2002.
SWOP benefits BP said the Prudhoe waterflood has been successful, but is nearing its technical limit, with some wells at 98% water cut. Prudhoe has “highly effective gas-drive mechanisms” available and the gas cap seawater injection system is available to take diverted seawater.
Benefits of the proposed SWOP include:
*Expansion of “more efficient gas-based recovery mechanisms into waterflood areas” at Prudhoe;
*Reduction of waterflood impacts on GDWFI boundary region;
*Increasing “fieldwide pressure support from gas cap water injection”;
*Reducing injection management support; and
*Reducing water production rates.
Put River Southern Lobe BP said that ending seawater delivery to DS-01 “also stops water injection for a minor satellite, the Put River Southern Lope,” which would remain shut-in until alternate injection support was provided.
The company made a separate application to AOGCC to deal with the Put River issue, requesting contraction and redefinition of the Put River Oil Pool, an application which the commission approved Dec. 19.
The commission said BP’s request included contracting the Put River Oil Pool to the area of the Southern Lobe of the Put River sandstone, modifying an existing rule to allow continuation of downhole commingling of any PROP well with the Prudhoe Oil Pool and granting a gas oil exemption for wells in the Central and Western lobes of the Put River sandstone to allow collection of data for developing a reservoir development strategy for those sands.
The PROP was defined in 2005 including the three lobes “even though the three lobes contained hydrocarbons with different properties and reservoir pressures,” the commission said, with the Southern Lobe the only portion of the PROP that has been on long term production and has an active water injection project.
While there have been attempts to produce from the Central and Western Lobes, the commission said BP is still attempting to define a proper development method for those lobes.
“Due to the differing reservoir fluid properties and pressures, as well as the maturity of the methods of development for the three lobes it makes sense to treat them as separate pools instead of a single pool,” AOGCC said.
The commission contracted the affected area of the existing PROP to the Southern Lobe; the Central and Western Lobes will be separate undefined pools.
The commission also modified some of the rules to address the three lobes separately.
“Contracting the affected area of the PROP to the limits of the Southern Lobe of the Put River sandstone will not cause waste or jeopardize correlative rights and is based on sound engineering and geoscience principles,” the commission said.
Additional production BP told the commission that the SWOP project is expected to product an additional 19.6 million barrels of oil, gross. With the Put River Southern Lope the total would have been 20.7 million barrels.
“The SWOP project is attractive, and enables a greater ultimate recovery from Prudhoe Bay Unit even with the PRSL shut in,” the company said.
BP said the additional volumes are sales liquids recovery by 2060 - including oil, condensate and natural gas liquids.
In addition to increasing oil production, BP said SWOP also produces less water, 200 million barrels by the year 2050. “Since the seawater injection rate is maintained, diverted from pattern waterflooding to the gas cap water injection project, and water production is reduced, overall field reservoir pressure increases.”
Depletion plan concepts BP listed technical papers on Prudhoe Bay depletion from 1983 through 2018 in its application and told the commission that “both laboratory data and field performance demonstrate that gas-based recovery mechanisms are preferable to water-based mechanisms for oil recovery given Prudhoe Bay lithology and fluids.”
To date, the gravity drainage area oil recovery factor is 53%, BP said, while for the waterflood area it is 43%, with waterflood lagging 10% behind gas-based recovery mechanisms.
Field wide recovery for the initial participating area at Prudhoe is 50% to date, the company said.
API gravity for Prudhoe Bay sales liquid has changed over time, from an average of 26 degrees API for original production to 39 degrees today - occasionally reaching 40 degrees API, the company said.
Currently the bulk of field production, 50%, is condensates and natural gas liquids, which have higher API gravity than crude oil.
- KRISTEN NELSON
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