Summary
For ultratight shale reservoirs, wettability strongly affects fluid flow
behavior. However, wettability can be modified by numerous complex interactions
and the ambient environment, such as pH, temperature, or surfactant access.
This paper is a third-phase study of the use of surfactant imbibition to
increase oil recovery from Bakken shale. The surfactant formulations that we
used in this paper are the initial results that are based on our previous
study, in which a group of surfactant formulations was examined--balancing the
temperature, pH, salinity, and divalent-cation content of aqueous fluids to
increase oil production from shale with ultralow porosity and permeability in
the Middle Member of the Bakken formation in the Williston basin of North
Dakota. In our previous study, through the use of spontaneous imbibition,
brines and surfactant solutions with different water compositions were
examined. With oil from the Bakken formation, significant differences in
recoveries were observed, depending on compositions and conditions. Cases were
observed in which brine and surfactant (0.05 to 0.2 wt% concentration)
imbibition yielded recovery values of 1.55 to 76% original oil in place (OOIP)
at high salinity (150 to 300 g/L; 15 to 30 wt%) and temperatures ranging from
23 to 120°C. To advance this work, this paper determines the wettability of
different parts of the Bakken formation. One goal of this research is to
identify whether the wettability can be altered by means of surfactant
formulations. The ultimate objective of this research is to determine the
potential of surfactant formulations to imbibe into and displace oil from shale
and to examine the viability of a field application. In this paper, through the
use of modified Amott-Harvey tests, the wettability was determined for cores
and slices from three wells at different portions of the Bakken formation. The
tests were performed under reservoir conditions (90 to 120°C, 150- to 300-g/L
formation-water salinity), with the use of Bakken crude oil. Both cleaned cores
(cleaned by toluene/methanol) and untreated cores (sealed, native state) were
investigated. Bakken shale cores were generally oil-wet or intermediate-wet
(before introduction of the surfactant formulation). The four surfactant
formulations that we tested consistently altered the wetting state of Bakken
cores toward water-wet. These surfactants consistently imbibed to displace
significantly more oil than brine alone. Four of the surfactant imbibition
tests provided enhanced-oil-recovery [(EOR) vs. brine water imbibition alone]
values of 6.8 to 10.2% OOIP, incremental over brine imbibition. Ten surfactant
imbibition tests provided EOR values of 15.6 to 25.4% OOIP. Thus, imbibition of
surfactant formulations appears to have a substantial potential to improve oil
recovery from the Bakken formation. Positive results were generally observed
with all four surfactants: amphoteric dimethyl amine oxide, nonionic
ethoxylated alcohol, anionic internal olefin sulfonate, and anionic linear
a-olefin sulfonate. From our work to date, no definitive correlation is evident
in surfactant effectiveness vs. temperature, core porosity, core source (i.e.,
Upper Shale or the Middle Member), or core preservation (sealed) or cleaning
before use.
© 2012. Society of Petroleum Engineers
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History
- Original manuscript received:
2 February 2012
- Meeting paper published:
14 April 2012
- Revised manuscript received:
26 September 2012
- Manuscript approved:
1 October 2012
- Published online:
6 December 2012
- Version of record:
27 December 2012
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