The chance to recover billions of barrels of oil that remain in Oklahoma fields represents geological, engineering, and statistical challenges to oilmen willing to take risks.
Most emphasis in the state the past 20 years has been on natural gas, especially in shales, but the oil is still there, somewhere, writes Dan T. Boyd, a geologist with the Oklahoma Geological Survey.
The prize: Boyd estimates the state’s thousands of oil fields will ultimately yield only 19% of the more than 84 billion bbl of original oil in place at present decline rates.
“Every 1% of the remaining oil in place represents a staggering 680 million bbl of incremental recovery,” Boyd wrote. Indications are that a lot of the oil is in reservoirs from which recovery factors can be increased.
Boyd describes the potential in the February issue of the quarterly publication of the Society of Independent Professional Earth Scientists, based in Dallas.
A new effort called Energy Libraries Online could help by improving access to previously scattered, inaccessible, and incomplete well and production data (OGJ, Feb. 23, 2009, p. 34).
Oklahoma oil’s decline
Oklahoma’s oil production peaked in 1927.
The state has produced about 170,000 b/d in recent years, down from a later peak of 620,000 b/d in the 1960s when Tulsa newspapers still had oil departments and this editor broke into oil journalism. Tulsa was also Oil & Gas Journal headquarters for most of its existence until the 1990s.
Oklahoma got its last 100 million bbl oil field, Postle in the Panhandle, in 1958 and its last 10 million bbl field, Wheatland just west of Oklahoma City, in 1981, when this editor joined OGJ.
Most of the state’s oil wells average 2 b/d, oil drilling is down to 1,000 wells/year, and without large discoveries “future reserve additions must come from improvements to the recovery in existing fields,” Boyd wrote.
Oil drilling is sparse despite recent high oil prices. Economics of gas are better, and operators are concerned whether prices will be sufficient to recoup large initial investments and whether enough producible oil remains to justify large-scale improved recovery.
The oil is there
Cumulative production for the three main reservoir classes are blanket sandstones 2.592 billion bbl, carbonate shelf reservoirs 2.74 billion bbl, and fluvial-dominated deltaic sandstones 9.478 billion bbl.
Recovery factors are estimated at 44.1% for blanket sandstones, 10% for carbonate shelf reservoirs, and 21.2% for FDD sandstones.
Boyd points out, however, that 50% is possible in the best blanket sandstone reservoirs and that recovery was less than 30%—and often substantially less—in about half the reservoirs he studied.
“For the roughly half of the FDD channel-fill reservoirs in which EUR is less than 20%, a more detailed review is certainly warranted,” he wrote. These reservoirs have the best possibilities.
“A great deal of the secondary recovery work done so far has been piecemeal,” Boyd found. Except in the largest fields, many waterflood units have been subdivided and are operated in isolation or at cross purposes, and units operated since 1979 cover less than half of the state’s currently producing oil leases.
Modern examples
Boyd cited instances in which operators have improved recoveries by innovative means.
In West Carney field in Lincoln County, a dewatering technique elevated a Hunton carbonate shelf reservoir with cumulative production of 38,000 bbl and 500 MMcf to one with reserves of 2.2 million bbl and 16 bcf.
Dewatering involved pumping and disposing of water at rates sufficient to “reduce the reservoir pressure until the associated gas in the unproduced oil expands.” Boyd wrote, “This oil can then be pushed into the fracture system and ultimately the wellbore.”
Another operator used dewatering to increase incremental recovery in Mount Vernon field in Lincoln County by 1.26 million bbl of oil, 18.5 bcf of gas, and 1.77 million bbl of condensate.
First steps
The effort to digitize early data, which is in need of funding, is starting on two important fronts.
Energy Libraries Online is scanning hand-drawn strip logs from 104,000 Oklahoma wells drilled with cable tools, of which 62,000 were oil wells. These logs are the only subsurface data for more than one fourth of the state’s oil wells, one fifth of all wells, and nearly all wells drilled before 1935.
ELO is also digitizing hard-copy data that will extend the availability of monthly oil production data, now available only since 1970, back to 1935.
