Wettability Survey in Bakken Shale With Surfactant-Formulation Imbibition

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, 150to 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. Introduction Shale rock is an important source of oil and gas in a number of sedimentary basins in North America. Most shale reservoirs have a low porosity and ultralow permeability with natural fractures. Shale formations have long been considered important source rocks, capable of producing oil at economic rates when completed by hydraulically fractured horizontal wells. Surfactant-formulation optimization is a key step in our investigation of chemical imbibition (with the use of surfactant or brine formulations) to stimulate oil recovery from shale. Initial surfactant screening and optimization involved the balancing of pH, salinity, and divalentcation content of the injected aqueous fluid that promote imbibition while minimizing clay swelling and formation damage (Wang et al. 2011a, b). However, the effectiveness of a surfactant formulation can also depend on wettability alteration. In this paper, we investigated whether our initial optimized surfactant formulations can modify Bakken shale wetness. As a relatively thin, clastic unit, the Bakken formation in North Dakota consists of three informal units that are named the Lower Shale, Middle Member, and Upper Shale. The Middle Bakken Member ranges from 40 to 70 ft in thickness, with lithologic content varying from argillaceous dolostones and siltstones to clean, quartz-rich arenites and oolitic limestone with shale (Phillips et al. 2007). Measured core porosities in the Middle Member range from 1 to 16% and average approximately 5% by plot vs. permeability. A few high-pressure mercury-injection measurements indicate that in-situ porosities are on the order of approximately 3%. Measured permeability ranges from 0 to 20 md in the Middle Member and typically is low, averaging 0.04 md by plot of porosity vs. permeability. As burial depth increases, permeability in sandstones in the Middle Member has been shown to decrease from a range of approximately 0.06 to 0.01 md, where the adjacent shales are immature, to a range of approximately 0.01 to 0.01 md, where these shales are mature. The temperature of the Middle Member ranges from 80 to 120 C (Pitman et al. 2001). On the basis of the chemical analysis of Bakken formation water by the Environmental Analytical Research Laboratory at the University of the North Dakota, the brine salinities range from 150,000 to 300,000 mg/L (15 to 30 wt%) total dissolved solids (TDS) in the Williston basin (Wang et al. 2011a). Also, the statistical data from 200 well samples in the pre-Mississippian rocks (of which the Bakken is the top formation; Iampen and Rostron 2000) proved this range. Generally, wettability strongly affects fluid flow behavior. In a water-wet status, water can be imbibed into bypassed zones by capillary forces. Alternatively, if the porous media are oil-wet, capillary force prevents water from entering the bypassed zones (Sharma and Mohanty 2011). For most shale reservoirs, waterflooding has limitations because of relatively higher clay content, even though waterflooding is favorable for neutral-wet status. The mechanism of wettability alteration involves surfactant added related with capillary pressure. As wettability is altered, the capillary pressure changes from negative to positive, and countercurrent imbibition mobilizes more oil. Furthermore, the relative permeabilities and residual saturations are changed to provide a higher oil recovery from the core. Several previous studies were performed with the use of surfactant imbibition to alter wettability in carbonate and chalk reservoirs, with rock permeability ranging from 1 to 15 md and porosity up to 29.1%. Zhang and Austad Copyright VC 2012 Society of Petroleum Engineers