A dose of reality for enhanced oil recovery (EOR) projection
The October 1 Commentary showed a huge discrepancy between the National Petroleum Council’s (NPC) projection for enhanced oil recovery (EOR), and the history of actual EOR results.
NPC projected that EOR production worldwide would reach 20 million b/d in 2030 (1). Such a projection is unachievable given that actual production was 1.8 million b/d in 2006. In the U.S. where EOR was pioneered, EOR production peaked in 1992 at 761,000 b/d, and slipped to 649,300 b/d by 2006 (2).
With their projection, NPC perpetuates the misguided belief that EOR might be successfully applied to the full spectrum of oil fields worldwide, thus extracting additional oil from formations that have been depleted of primary and secondary reserves. Royal Dutch Shell promoted the same belief in 2006. In its webcast, Shell declared that extracting an additional 10 percent of original oil in place (OOIP) from the world’s oil fields with EOR, also called tertiary recovery, would yield another 500 billion barrels of oil (3).
Shell’s statement is merely hypothetical, with little resemblance to reality. In a series of Commentaries here, we will see that EOR processes have been narrowly confined to only two categories of resources.
- Highly permeable reservoirs containing heavy, viscous oil respond to thermal methods, e.g., steam injection.
- Reservoirs with poor permeability containing light oil respond to carbon dioxide or nitrogen injection at miscible pressures.
Reviewing how the industry methodically developed EOR technologies over 50+ years reveals EOR’s high level of maturity. Consequently, EOR development in the U.S. is a powerful indicator of where EOR can be applied to oil resources worldwide, and where applications have negligible potential.
The Advent of EOR
EOR was born in the prolific Permian Basin of West Texas. In 1945, Atlantic-Richfield discovered an unusual field that they named Block 31. They calculated that the reservoir contained 300 million barrels of light, gassy OOIP with pressure exceeding 4,000 pounds per square inch (psi). Problem was, the reservoir rock was quite impermeable, around 1 millidarcy (md). [Permeability quantifies the ease with which fluid passes through porous media.]
Well rates were pitifully low. However, studies of fluid movements within the reservoir showed that injecting natural gas at pressures sufficiently high that it became miscible with oil created an oil/gas phase that was much more mobile than oil alone. Thus the oil/gas phase could permeate through the reservoir toward wellbores. In 1949, Atlantic-Richfield began compressing and injecting natural gas from a nearby source into Block 31. The field began to produce, slowly at first, but production grew steadily. By 1965 cumulative production from Block 31 approached 90 million bbl. The industry hailed the success at Block 31, recognizing that miscible gas injection could extract oil that would remain in the ground under conventional methods (4).
With such poor permeability, no oil was extracted under primary or secondary methods; all production was tertiary. In 1966, to avoid using marketable natural gas, Atlantic-Richfield developed a system to inject flue gas (deficient in oxygen but rich in nitrogen and carbon dioxide) from a nearby processing plant (4).
Production gradually increased to a peak of 20,000 b/d in 1978. However, production slid steadily thereafter, to 2,500 b/d in 1998, with average production per well 15 b/d (5).
The success at Block 31 led to application of gas injection at miscible pressures 400 miles to the east. The Fairway field, a 200 million barrel field discovered in 1960, was the largest discovery on land since 1948. Reservoir and fluid properties were similar to those of Block 31, although permeability was somewhat higher, 11 to 18 md. Miscible injection of natural gas began in March 1966 (6).
By 1980 operators estimated that all production at Fairway resulted from miscible injection, and not merely due to pressure maintenance. During 1967 through 1998 Fairway produced 187 million barrels of oil, the vast majority of which was attributed to miscible injection (2).
The Kelly-Snyder field, discovered in 1948, containing 3 billion bbl OOIP of light, gassy oil, became one of the largest and most successful oil recovery projects using miscible gas injection. Like its predecessors, Kelly-Snyder (KS) formations had poor properties: 4% porosity, 19 md permeability. Primary recovery in the early 1950s dropped reservoir pressure to near critical levels. Operators quickly recognized that pressure maintenance was vital to preserving the field. They began water injection in 1954, which stabilized and then slowly raised reservoir pressure (7).
Ongoing reservoir studies showed that injecting carbon dioxide (CO2) at high pressures, sufficient to achieve miscibility in the reservoir, would best increase the recovery factor of OOIP. A major source of CO2-rich gas was available 230 miles south of KS, so operators developed a system of pipelines, compressors, and a treatment plant to provide injectant (8).
Operators began miscible injection across 78 square miles in January 1972 to augment water injection. Production climbed to a sharp peak in 1974, only to plunge 57% by 1980. Nevertheless, operators estimated that EOR accounted for 20% of total field production in 1980, with increasing portions thereafter, reaching 90% by the mid-1990s. Despite the heavy contribution from EOR, field production continued to drop through 1998, to only 4% of its peak in 1974 (5).
Can EOR be Applied to All Oil Fields?
Early applications of miscible gas EOR succeeded where extensive formations have poor permeability, i.e., where conventional pressure maintenance either became or was always ineffective. The major unanswered question in 1980 was, can a variety of EOR processes extract a greater portion of OOIP from the vast majority of oil fields, i.e., those with good permeability? We will explore that question in the next Commentary.
Tom Standing began his career as a chemical engineer in refinery operations and later shifted to work as an engineer for the San Francisco water system. He is self-taught in the sciences of petroleum production, geology and geochemistry.
1. National Petroleum Council, “Facing the Hard Truths about Energy,” Executive Summary, p. 7, July 2007
2. Oil and Gas Journal, “CO2 Injection Gains Momentum,” April 17, 2006
Field-by-field EOR surveys typically appear in April issues of even-numbered years.
3. Ibid, “Shell’s Interest in Enhanced Oil Recovery Grows,” November 20, 2006
4. Ibid, “Miscible Flood Hikes Block 31’s Oil Output,” October 27, 1969
5. Ibid, tabulations of production and estimates of ultimate recovery for giant U.S. fields appear annually in “Forecast and Review,” the last week of January. Tabulations were last published January 25, 1999.
6. Ibid, “Texas Approves Unit Plan for Giant Fairway Field,” October 4, 1965
7. Ibid, “SACROC: An Engineering Conservation Triumph,” August 17, 1970
8. Ibid, “Carbon Dioxide Injection May Drive High SACROC Recovery,” April 10, 1972
(Note: Commentaries do not necessarily represent ASPO-USA's positions; they are personal statements and observations by informed commentators.)
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