Summary
Following a series of laboratory imbibition-cell experiments, field tests
were conducted to determine the effectiveness of surfactant-soak treatments as
a single-well enhanced-oil-recovery (EOR) technique. The tests were conducted
in the dolomite interval of the Phosphoria formation. Artificial intelligence
was applied to analyze the mixed test results. The analysis suggested that the
gamma ray log can be used to predict results and that a minimum amount of
surfactant is required to improve production.
Introduction
Water imbibition as a recovery process was tested in the Spraberry field
during the 1950s (Elkins and Skov 1962, 1963). This early work was followed by
a test of the process in Cottonwood Creek field during the 1960s (Willingham
and McCaleb 1967). Around the time of these field tests, a patent was issued
(Graham et al. 1957) that suggested surfactants could enhance the imbibition
recovery process. A later patent (Stone et al. 1970) implied that a Spraberry
field test was designed, but results were not reported. Forty years later,
researchers (Spindler et al. 2000; Standnes and Austad 2000; Chen et al. 2000)
returned to the subject of wettability alteration. One description of a field
test of the surfactant-soak process has been published (Chen et al. 2000). A
great deal of effort was expended during the 1970s and 1980s in designing
systems and field testing surfactant fluids with ultralow interfacial tensions
(IFTs) as a flooding EOR process. Maintaining the integrity of the chemical
slug from the injection well to the producing wells was fraught with problems.
However, slug-integrity problems are diminished in single-well EOR
applications.
Recent laboratory work focused on the easily performed and interpreted
imbibition-cell experiments. These experiments (with and without surfactants)
and the reported success of pressure pulsing at Cottonwood Creek prompted
further laboratory testing with reservoir rock and fluids (Xie 2002; Xie et al.
2004). This recent work indicated that a nonionic surfactant could
substantially increase recovery from Phosphoria wells in the Cottonwood Creek
field.
The shallow-shelf carbonate reservoir is characterized as a steeply dipping,
algal reef of the Phosphoria formation producing sour, 27°API, black oil from a
dolomitized interval. Thickness of the dolomite varies from 20 to 100 ft. The
average porosity is ≈10% with ≈1.0 md matrix permeability. The connate-water
saturation is ≈10%. Pan American Petroleum reported the low-pressure and
low-temperature reservoir to be naturally fractured and oil-wet (Willingham and
McCaleb 1967). Their description was based on laboratory core studies. Tests
performed in the 1990s generated U.S. Bureau of Mines (USBM) wettability values
of –0.1, –0.12, –0.18, and –0.26. The Cottonwood Creek field is located in the
Bighorn basin of Wyoming, as shown in Fig. 1, and is operated by Continental
Resources Inc.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
24 June 2004
- Revised manuscript received:
10 February 2006
- Manuscript approved:
16 March 2006
- Version of record:
20 June 2006
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