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 α-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.

Summary As part of our investigations of a new chemical imbibition idea (using surfactant or brine formulations) to stimulate oil recovery from shale, we are studying oil flow through and, especially, brine intake into shale to displace oil. Our first studies in this area focused on an outcrop shale, specifically the Odanah member of Pierre shale in North Dakota, USA. We studied porosity, permeability to oil, permeability to water, and spontaneous brine intake for the Pierre shale. We found that porosities for Pierre shale cores were relatively high—from 25 to 35%. Porosities for our measurements of Bakken cores averaged less than 3%. Bakken oil imbibed into dry Pierre shale cores (up to 5 mm in thickness) to the same extent as could be achieved by forced injection of oil (i.e., achieving the same oil saturations for both processes). Permeability to a clean mineral oil (Soltrol 130™) was higher than for Bakken oil—apparently because of deposition of wax/asphaltenes/particulates on the Pierre core faces when injecting Bakken oil. Permeability to oil for Pierre shale cores (with no water present) ranged from 3.32×10–5 to 2.19×10–4 md when injecting Bakken oil and from 4.85×10–4 to 2.34×10–3 md when injecting Soltrol 130. Permeability to Bakken oil for a Bakken core (with no water present) averaged 4.84×10–4 md. In Pierre shale and Bakken cores with thicknesses ranging from 0.65 to 5 mm, permeabilities were basically independent of flow rate, in agreement with expectations from the Darcy equation. Saline brine spontaneously entered into oil-saturated Pierre cores, yielding recovery values up to 41% of original oil in place (OOIP). During exposure to brine, our results indicated an increase in permeability—presumably by mineral dissolution during forced brine injection and by cracking (possibly caused by clay swelling) during spontaneous brine intake. This result is encouraging for the application of imbibition to enhance oil recovery from shale. Before these studies, we feared that exposure to brine might reduce shale permeability because of clay swelling. The laboratory results will help during a current study of surfactant and brine imbibition in the Bakken formation.

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By use of existing methods, typical oil-recovery factors from the Bakken and other shale formations are low, typically less than 5% of original oil in place (OOIP). We are investigating the use of surfactant imbibition to enhance oil recovery from oil shale or other tight rocks. Much of our previous work has measured surfactant-imbibition rates and oil-recovery values in laboratory cores from the Bakken shale, Niobrara chalk/shale, and Eagle Ford formations. With optimized surfactant formulations at reservoir conditions, we observed oil-recovery values up to 20% of OOIP incremental over brine imbibition. However, whether surfactant imbibition will be a viable recovery process depends on achieving sufficiently high oil-production rates in a field setting. This, in turn, depends on three factors: the area of formation contact (through fractures and microfractures) when/where the surfactant formulation is introduced; the rates of surfactant imbibition; and the distances of surfactant imbibition into the rock and ultimate oil-displacement effectiveness. In this paper, we use analytical models to scale laboratory surfactant-imbibition rates to a field scale in fractured-shale formations.In laboratory cores, we observed imbibition rates that varied inversely with time. Dimensionless scaling groups were applied that compensate for the effects of sample size and shape, boundary conditions, permeability, porosity, and viscosity. Calculations were made of available fracture area, assuming typical horizontalwell lengths and transverse-induced-fracture spacing in typical Bakken wells. These fracture areas were coupled with our imbibition-scaling groups to estimate oil-recovery rates in a field setting. Considering realistic timing, surfactant imbibition will generally not proceed more than a few meters into the low-permeability shale/chalk formations. These calculations indicate insufficient fracture area to provide a viable imbibition process if only the induced-fracture area is considered. However, recent results from geological, microseismic, and pressure-transient studies indicate considerably greater area associated with natural microfractures in our target formations. When the increased area suggested by the presence of microfractures is included in our analyses, the surfactant-imbibition process appears quite promising.

Vapor‐phase and suspended particulate (<50 µm) samples were collected on polyurethane foam (PUF) and quartz fiber filters in rural North Dakota to determine the air concentrations of pesticides in an area where agriculture is a primary source of semivolatile pollutants. Samples were collected at two sites from 1992 to 1994 that were at least 0.4 km from the nearest farmed fields and known application of pesticides, and analyzed for 22 different organochlorine, triazine, and acid herbicide pesticides. Fourteen pesticides were found above the detection limits (typically <1 pg/m3). The most prevalent species found in the PUF extracts were endosulfan I and II (6,7,8,9,10,10‐hexachloro‐1,5,5a,6,9,9a‐hexahydro‐6,9‐methano‐2,4,3‐benzodioxathiepin 3‐oxide, exo‐ and endo‐isomers, respectively) at <1 to 2200 pg/m3 and <1 to 500 pg/m3, respectively, trifluralin (2,6‐dinitro‐N,N‐dipropyl‐4‐trifluoromethylaniline) at 3 to 700 pg/m3, and 4,4′‐DDE (1,1‐dichloro‐2,2‐bis‐(4‐(chlorophenyl)ethylene) at 6 to 200 pg/m3. The most prevalent pesticides in filter extracts included carbofuran (2,3‐dihydro‐2,2‐dimethyl‐7‐benzofuranyl methylcarbamate) at <0.5 to 470 pg/m3, atrazine (2‐chloro‐4‐ethylamino‐6‐isopropylamino‐l,3,5‐triazine) at <0.4 to 46 pg/m3, 2,4‐D ((2,4‐dichlorophenoxy)acetic acid) at <0.4 to 1800 pg/m3, and chlorothalonil (2,4,5,6‐tetrachloro‐1,3‐benzenedicarbonitrile) at <13 to 7800 pg/m3. Concentrations of polychlorinated biphenyl (PCB) congeners were much lower (<50 pg/m3 in all cases) than many of the pesticides. These results demonstrate that pesticides are among the most prevalent chlorinated semivolatile pollutants present in rural North Dakota, that significant transport of pesticides occurs both in the vapor‐phase and on suspended particulate matter, and that blown soil may be a significant mechanism for introducing pesticides into surface and ground waters.

This paper investigates an idea for chemical imbibition using surfactant formulations to stimulate oil recovery from oil shale. One goal of this research is to identify a formulation that promotes imbibition while minimizing clay swelling and formation damage. Experiments directed toward this goal involved balancing the temperature, pH, salinity, and divalent cation content of aqueous fluids to enhance oil recovery from the shale with ultra-low porosity and permeability in the middle member of the Bakken formation in the Williston Basin of North Dakota. The ultimate objective of this research is to determine the potential of surfactant formulations to imbibe into and displace oil from shale, and examine the viability of a field application.Using spontaneous imbibtion, 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 where brine and surfactant (0.05−0.2 wt % concentration) imbibition yielded recovery values of 1.55 to 76% OOIP at high salinity (150−300 g/L: 15−30 wt %) and temperatures ranging from 23°C−120°C. Six key observations were noted: (1) an ethoxylate nononic surfactant, an internal olefin sulfonate anonic surfactant, and an amine oxide cationic surfactant were more stable than the other surfactants for temperatures from 105−120°C. They were effective in imbibing and displacing oil at high temperature. (2) Adding alkali to surfactant formulations increased oil recovery from Bakken shale. However, sodium carbonate reacted with divalent cations and precipitated when added to our highly saline brines. To counter this effect, sodium metaborate was added to surfactant solutions to reduce or prevent precipitation. (3) An ethoxylate nononic surfactant and an internal olefin sulfonate anionic surfactant were more tolerant of high salinity than other surfactants and display higher oil recoveries at high temperature. For Bakken cores, surfactants did not imbibe effectively using distilled or low salinity water. (4) Varying the hardness of the surfactant formulation had a major effect on imbibition and oil displacement. (5) In some cases, clay flaking from the shale was observed when contacting brine (without surfactant) or contacting amine oxide cationic surfactant with higher alkane numbers in brine. However, for the later situation, it could be improved by changing pH of surfactant solution. (6) For a given surfactant, oil recovery can be maximized by identifying the optimal surfactant concentration, brine salinity, sodium metaborate concentration, and divalent cation content.

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