NOW READ OUR ARTICLES IN 40 DIFFERENT LANGUAGES.
HOME PAGE SUBSCRIPTIONS, Print Editions, Newsletter PRODUCTS READ THE PETROLEUM NEWS ARCHIVE! ADVERTISING INFORMATION EVENTS

Vol. 25, No.07 Week of February 16, 2020
Providing coverage of Alaska and northern Canada's oil and gas industry

Fine tuning Prudhoe: Seawater injection switch to add barrels

Click here to go to the full PDF version of this issue, with any maps, photos or other artwork that appears in some of the articles.

Kristen Nelson

Petroleum News

Ending seawater injection at two Prudhoe Bay drill sites and increasing seawater injection in the gas cap at the field will increase ultimate recovery from those drill sites, as well as increasing overall recovery by increasing field-wide pressure, field operator BP Exploration (Alaska) told the Alaska Oil and Gas Conservation Commission.

The company is applying to the commission to change depletion operations in a portion of the Prudhoe Bay miscible gas project to permanently cease seawater injection at drill sites 1 and 12 and transfer the seawater to another portion of the Prudhoe Oil Pool.

Frank Paskvan, a reservoir engineer and fieldwide team leader for Prudhoe Bay depletion planning, and reservoir engineer Gerrit Verbeek testified to the commission Jan. 21 on the application for what the company calls the Sea Water Optimization Plan, SWOP.

BP applied to make the change in December (see story in Dec. 29 issue of Petroleum News) and Paskvan said the testimony was to provide additional context for the application package.

SWOP benefits

BP itemized benefits of SWOP: expanding more efficient gas-based recovery mechanisms into Prudhoe waterflood areas in the drill sites 1 and 12 region; reducing waterflood impacts on the gravity drainage waterflood interaction boundary region; increasing fieldwide pressure by 50 psi over the life of the field; reducing injection management support work; will cause shut-in of Put River southern lobe, which is supported by a drill site 1 water injector; benefit is 20 million barrel oil recovery increase, result of 21 million gain from SWOP less 1 million from Put River southern lobe.

Gravity drainage

Gravity drainage, Paskvan told the commission, is at the heart of Prudhoe, with waterflood and miscible gas projects at the periphery, the boundary between them the gravity drainage waterflood interaction area, GDWFI, and the gas cap at the crest of the structure.

The SWOP area, primarily drill sites 1 and 12, is in southeastern portion of the field.

Seawater is injected at drill sites 1 and 12 and some at drill site 4, Paskvan said. All other injection is produced water because starting with seawater, produced water comes back, so other than those specific drill sites all the others in the Prudhoe Oil Pool are injecting produced water or miscible gas.

He said seawater diverted from drill sites 1 and 12 would go to the East Dock gas cap water injection project, also known as the pressure support initiative, which has been maintaining reservoir pressure at the field since 2002.

Gas-based recovery mechanisms are more efficient than waterflood, Paskvan said, and SWOP would reduce impacts of waterflood on the gravity drainage area because Prudhoe is a highly permeable reservoir and some of the injected water moves into the gravity drainage area.

Recovery mechanisms

Verbeek said original oil in place at Prudhoe was some 25 billion barrels, with 24 trillion cubic feet of free gas and an additional volume of some 16 tcf of gas in solution.

The current depletion plan attempts to keep the boundaries of the GDWFI stable, Verbeek said, which has resulted in a total field recovery of 50%, with 43% recovery from waterflood with miscible gas injection and 53% from gravity drainage supplemented with lean gas vaporization enhanced oil recovery.

Those differences in recovery are not driven by differences in investment or development history, he said, but occurred because gas is more efficient than water as a displacement mechanism for oil.

The core of the SWOP proposal, Verbeek said, is to remove the push from waterflood that is resisting gas moving down from the north, permitting gravity drainage to expand into the GDWFI area to allow gas-based recovery, the more efficient mechanism, to move into that area of the field.

Gas projects

Prudhoe production began with gravity drain gas cycling, Verbeek said. Then the central gas facility was built in 1986, enabling miscible injectant enhanced oil recovery in the waterflood area and enabling natural gas liquids production and lean gas vaporization.

The 1990s saw a series of gas handling expansions and an MI expansion, and more recently rich gas liquids have been targeted - focused on finding areas where gas has not been cycled that still have original condensate and gas liquids, he said.

Pattern waterflood was begun in 1981 and gas cap water injection - the seawater supplemental volume injection - in 2003.

Field wide pressure is now held constant at about 3,300 pounds per square inch from an initial pressure of 4,420 psi, Verbeek said.

Data from bottomhole pressures throughout the field fall primarily within a band of plus or minus 75 psi, he said, showing how connected Prudhoe is, and with high permeability and a lack of significant internal flow barriers, that allows pressure support for the field from somewhat remote areas.

Verbeek said itís another piece of evidence providing confidence that if pattern waterflood ceases at drill sites 1 and 12, and that seawater is injected miles away in the gas cap, there is enough connectivity at Prudhoe to provide pressure support between the areas, allowing the advantage of improved gas recovery mechanisms without pressure decline in the region.

The original estimate for ultimate recovery was 9.6 billion barrels and ongoing projects, with SWOP proposed as the next, have increased estimated ultimate recovery to more than 14 billion barrels, with some 12.5 billion recovered, 50% of the 25 billion barrels of original oil in place.

Verbeek said ultimate recovery estimates are based on a cessation of production date of roughly 2060, and Paskvan noted that the estimates are based on business environment factors such as the future oil price and cost of operations and said the 14 billion is an estimate of ultimate recovery.

Mature processes

Verbeek said both waterflood and gravity drainage are reaching maturity. Switching a waterflood area to gravity drainage provides opportunity for more production because residual oil saturation can be driven lower, he said.

He told the commission that gravity drainage results in residual oil saturation of roughly 20%, whereas waterflood has a residual oil saturation of roughly 28%. Each of the mechanisms has an associated enhanced oil recovery mechanism, with gravity drainage supplemented by oil vaporization by lean gas cycling.

The recovery mechanism at Prudhoe is somewhat unique because it was enabled by the installation of the central gas facility and by the fact that gas wasnít exported, which isnít typical at many oil fields, Verbeek said. Waterflood is supplemented with miscible gas injection, also enabled by the CGF, but miscible gas injection is limited by supply volume and the scale of Prudhoe.

After almost 30 years of operating a miscible water-alternating-gas project, weíve reached the saturations we have today, he said.

Gas processes

Prudhoe is increasingly dependent on gas processes, Verbeek said, and BP is increasingly seeking to exploit gas processes to drive ultimate recovery.

Prudhoe processes and reinjects some 6 billion cubic feet per day of dry, lean gas after it has been stripped of condensates, NGLs and miscible injectant. At surface conditions that gas is the equivalent of roughly 50 million barrels per day.

The CGF enables production of dry gas and when that is reinjected, some of the lighter hydrocarbon ends such as propane and butane are drawn into the gas, Verbeek said - and while the gas becomes heavier, it remains mobile compared to residual oil. That lean gas travels through the reservoir and comes back up the wellbore and is cycled through the CGF where the lighter hydrocarbon ends are stripped out.

Lean gas as an EOR mechanism recovers condensate and NGLs, he said.

The typical API gravities for Prudhoe were 26 degree API black oil from 1977 until the mid-1980s. After the CGF was constructed Prudhoe was producing miscible injectant EOR oil, where MI injectants draw lighter hydrocarbon ends into the oil, so shipped API gravity started creeping up and in the late 1990s was about 36 degrees API, he said.

For reference, Verbeek said, the lubricant WD-40, has an API gravity of roughly 40 to 42.

Prudhoe is thought of as a black oil field, as a conventional light oil field, he said, but whatís being shipped down the trans-Alaska oil pipeline today is approaching WD-40.

After the rich oil projects started in 2012, Verbeek said, Prudhoe is roughly 39 degrees API.

Paskvan noted that on the slides BP presented, for the total life of field recovery, 78% is black oil and 22% comes from the gas phase, whereas for the remaining recovery, 35% is black oil and 65% is from the gas phase. He said because the black oil component is currently only about a third of current output, theyíve started using the term sales liquids rather than oil sales.

The total life of field recovery, with 78% black oil, is split out between waterflood and gravity drainage and GDWFI, Verbeek said. The 22% is from vaporization EOR, NGL production and MI production. He said MI comes up the wellbore in the form of oil but since thatís only due to the CGF and gas processes, itís considered a gas-based recovery.

For remaining recovery, two-thirds is from the gas phase - lean gas vaporization, NGL production, targeting rich gas, and expanding that gas phase recovery is what SWOP is about, Verbeek said.

Recovery rates

Addressing the issue of Prudhoeís level of recovery, Paskvan said global recovery factors for fields have historically been around 15% but that includes a large number of small oil fields with just natural depletion, no reinjection.

With modern oil field techniques, 30 to 40% recovery is typical, he said, and Prudhoe is projected to get about 60% recovery.

Discussing SWOP benefits, Verbeek said some 9.4 million barrels are projected to come from the immediate SWOP area, with an additional 11.3 million barrels fieldwide because of a 50 psi reservoir pressure increase, for a total of some 21 million barrels. The goal with SWOP, he said, is to shift the GDWFI boundary south, reducing the waterflood area and allowing the gas recovery mechanism from the gravity drainage region to move into the areas of drill sites 1 and 12.

Since the same volume of water is being injected, but now into the gas cap, less water is produced up the wellbore because itís being reinjected farther from producers, with a roughly 50 psi reservoir pressure increase because volume is maintained inside the reservoir. Injected at drill sites 1 and 12, water is only some 1,500 feet from a producer, quickly cycles through and has to be treated at the surface, whereas water injected into the gas cap stays in the reservoir, he said.

Verbeek said SWOP reflects a shift from waterflood to gravity drainage and also reflects that treating Prudhoe as a gas field yields higher net recovery.

He said oil rate is expected to increase by 1,000 to 2,000 bpd through the life of the project and water rate is expected to decrease by some 20,000 bpd until 2045 - when the additional water injected into the gas cap begins to make its way back through the field.

The Put River southern lobe would be shut-in with SWOP, Verbeek said, for a total loss of some 1 million barrels, but a separate project to restore pressure support for that area is being evaluated, so that volume is deferred, not lost.

With the gain of some 21 million barrels, overall, and the deferral of some 1 million barrels at the Put River southern lobe, the net gain from SWOP would be 20 million barrels.

Verbeek said drill sites 1 and 12 were targeted because they are on the seawater injection system and it was technically and financially simple to cease water injection there and direct that volume of water to the gas cap injection.

He said SWOP reduces waterflood impacts on gravity drainage and waterflood interaction boundary and allows that boundary to shift south allowing gas-based recovery mechanisms at drill sites 1 and 12.

Field-wide pressure is increased by 50 psi over the life of the field, benefiting the entire field.

As to why BP is proposing this project now, Paskvan said waterflood was essential to maintain reservoir pressure and when waterflood was begun they didnít have the geological information necessary to move forward with the gas cap water injection project. Since that project came online in 2003 there is much greater confidence that the gas cap water injection project is viable, he said.

There has also been data collected and evaluated on vaporization that wasnít available earlier.

Paskvan said at Prudhoe theyíve been learning more about the depletion mechanisms and technology and improving understanding of the reservoir over time, allowing major project investments to be made.

The Prudhoe waterflood is very mature, he said, with 90% plus water cuts on the margin. With deeper understanding and the gas cap water injection project in place, SWOP is a natural next step for the field.

And just because waterflood will stop at drill sites 1 and 12, there are still tons of mobile water in the reservoir, Paskvan said, itís just that the water will be driven by an encroaching gas boundary.

Addressing the impact that diverting more water to the gas cap might have on recoverable gas reserves, Verbeek said gas sales were considered and SWOP would not impact gas recovery in a major gas sale.

Paskvan said analysis indicates that seawater injection into the gas cap displaces gas from the area, mobilizing it and making it available for gas sales. The concept development for a major gas sale would have seawater injection cease concurrently with the start of a major gas sale, he said. The field would start depressuring, dropping the psi toward 1,500 psi and doubling the gas volume as it is produced.

In general, he said, gas cap water injection increases the amount of gas available for a gas sales project.

- KRISTEN NELSON



Print this story | Email it to an associate.






Petroleum News - Phone: 1-907 522-9469
[email protected] --- https://www.petroleumnews.com ---
S U B S C R I B E

Copyright Petroleum Newspapers of Alaska, LLC (Petroleum News)(PNA)©1999-2019 All rights reserved. The content of this article and web site may not be copied, replaced, distributed, published, displayed or transferred in any form or by any means except with the prior written permission of Petroleum Newspapers of Alaska, LLC (Petroleum News)(PNA). Copyright infringement is a violation of federal law subject to criminal and civil penalties.

This story has 205 lines. and it is 5991 pixels high.
ERROR ERROR