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Study: Gas sales would increase Prudhoe Bay hydrocarbon recovery
Kristen Nelson Petroleum News Editor-in-Chief
In the short term, natural gas sales from the Prudhoe Bay field on Alaska’s North Slope would likely reduce liquids recovery.
But in the long term, a study performed for the Alaska Oil and Gas Conservation Commission found, there would be a gain in overall hydrocarbon recovery, and natural gas production is also likely to extend the life of the field.
While the report itself, done for the commission by Blaskovich Services Inc., is confidential because it used data from the North Slope producers that the commission does not have the right under statute to make public, the commission did a non-confidential summary.
The Blaskovich study analyzed reservoir simulations run by the Prudhoe Bay unit working interest owners. The major Prudhoe Bay owners are BP Exploration (Alaska), the Prudhoe Bay field operator; ConocoPhillips Alaska; and ExxonMobil Production Co. Overall hydrocarbon recovery increased The commission said the study found that oil-only production from Prudhoe Bay would recover more than 13 billion barrels of hydrocarbon liquids — crude oil and condensate and natural gas liquids. To date, cumulative production is 11.2 billion barrels.
Gas sales, the commission said, will likely add 3-4 billion barrels of oil equivalent and will also likely extend the life of the field.
There will, however, be negative impacts on liquids recovery from gas sales, “because reservoir energy in the system will decline as a natural consequence of gas withdrawal for sales.”
The worst case estimates of decreased liquids production as a result of gas sales show “a loss of as much as several hundred million” barrels of liquids. The worst case was a 2010 gas sales start date with nominal off-take of 4.3 billion cubic feet per day from Prudhoe Bay only and no mitigating measures. In this worst case, field life would not be extended.
The study found that the magnitude of decreased liquid recovery “depends upon the timing of sales, the average annual gas off-take rate, the composition of the gas sold, field depletion plan optimization and the number of years that field producing life may be extended by gas sales.” Study results estimates only The commission called the study results “order of magnitude estimates. They are not conclusions.” The study was based on preliminary work by the working interest owners, and the commission said the owner companies “have stated that they plan to continue updating existing models and methods to improve operating strategies in an effort to maximize oil recovery.”
Two gas rates were evaluated: 2.9 bcf per day and 4.3 bcf per day, with the beginning of gas sales varied from 2010 to 2020. Total hydrocarbon recovery by 2031 and 2050 was then compared for the gas sales cases, compared to a no-gas sale case.
The assessment also evaluated ways to mitigate gas sales, and found the most promising method evaluated “was to increase water injection into the gas cap when gas sales are begun.”
The commission said water injection into the gas cap began last year to mitigate declining reservoir pressure. The nominal water injection rate planned is 650,000 bpd. Gas cap water injection increases liquids recovery The working interest owners evaluated increasing gas cap water injection to 1.05 million bpd with a gas sales rate of 2.9 bcf per day and a 2010 start of gas sales. Study results indicated this option increased liquid hydrocarbon recovery by 70-100 million barrels compared to the same gas sales case without increased gas cap water injection.
“Based upon the work reviewed so far, it appears that delay of gas sales and decreased off-take rate will reduce the negative impacts upon ultimate total liquid hydrocarbon recovery,” the commission said.
But it noted that the possibility of leaving North Slope gas stranded must be weighed against potential liquid losses.
The commission said that by 2030 a gas sales case of 2.9 bcf starting in 2010 results in overall hydrocarbon recovery increase of 2.5 billion barrels of oil equivalent over the result without gas sales.
“At year 2050, all gas sales cases evaluated result in nearly the same hydrocarbon recovery” with 3.5 billion boe incremental to a case with no gas sales.
“Hence, while total liquid hydrocarbon recovery is expected to decrease because of gas sales, it appears that overall hydrocarbon production near end of field life will be relatively insensitive to the start-up date of sales (2010-2020) and sales rates (2.9-4.3 bcfd).
“In fact,” the commission concluded, “significant hydrocarbon reserves (oil, gas and gas liquids) may not be recovered unless there are gas sales.” Further studies needed The commission said the studies it evaluated were done in 2001 and 2002 and were done “to scope scenarios for the pipeline evaluation effort” not “to maximize or optimize total liquid hydrocarbon or gas recoveries.”
Further studies, with better predictive tools, would require much more time than the 2001 and 2002 studies.
“However,” the commission said, “it is clear from this work that a critical aspect of this project will ultimately be trade-offs between oil and gas recovery.” It said gas reserves are usually produced only after liquid hydrocarbons, because maintaining reservoir pressure generally improves liquids recovery, while reducing reservoir pressure improves gas recovery. “
The commission said the owner companies plan to update reservoir and facilities models to better understand the liquids-gas tradeoff, and noted that increased water injection in the gas cap is a “promising but risky” mitigation technique. The gas cap water injection now under way at Prudhoe Bay “needs to be monitored closely for several years to ensure that water injected will not adversely affect liquid hydrocarbon recovery.”
The commission said that other Prudhoe Bay reservoirs and other North Slope fields need to be included in any final analysis to determine broader impacts of gas sales, and said the working interest owners have assured the commission that it will be included in more comprehensive future studies, which would avoid a “costly duplication of effort” estimated at $500,000 to more than $1 million, for independent studies by the state.
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