The Impact of Surfactant Imbibition and Adsorption for Improving Oil Recovery in the Wolfcamp and Eagle Ford Reservoirs

Abstract

Improving oil recovery from unconventional liquid reservoirs (ULR) is a major challenge and knowledge of recovery mechanisms and interaction of completion fluid additives with the rock is fundamental in tackling the problem. Fracture treatment performance and consequent oil recovery can be improved by adding surfactants to stimulation fluids to promote imbibition by wettability alteration and interfacial tension (IFT) moderate reduction. Also, the extent of surfactant adsorption on the ULR surface during imbibition of completion fluids is an important factor to take into account when designing frac jobs. The experimental work and modeling presented in this paper focuses on analyzing alteration of wetting behavior of Wolfcamp and Eagle Ford reservoir rock with the introduction of surfactants additives. We focus on effectiveness of surfactant additives for improving oil recovery as well as the extent of surfactant loss by adsorption during imbibition of surfactant-laden completion fluid. Altering the wettability with the use of surfactant additives is accompanied by alteration of the IFT as well as surfactant adsorption. We carefully evaluate these interactive variables as key constituents of imbibition capillary pressure to improve oil recovery. We assume this is a free imbibition process with no confining pressure on the rock sample. During imbibition spontaneous imbibition, as the sign of the capillary pressure changes from negative (oil wet) to positive (water wet). Original rock wettability is determined by contact angle (CA) at reservoir temperature. Then, different types of surfactants, anionic, anionic-nonionic, and cationic, at concentrations utilized in the field, are evaluated to gauge their effectiveness in altering wettability and IFT. Wettability is also studied by zeta potential to address water film stability on the shale rock surface as an indication of wetting fluid affinity and to determine the surfactant electrostatic charges. Moreover, surfactant adsorption measurements are performed using an ultraviolet–visible spectroscopy. Calibration curves for surfactants are determined by relating their concentration to light absorbance and used to calculate the amount of surfactant adsorption into the shale rock. Next, potential for improving oil recovery via surfactant additives in ultralow permeability Wolfcamp and Eagle Ford shale core is investigated by spontaneous imbibition experiments at reservoir temperatures. In order to visualize the movement of fluid as it penetrates into liquid rich shale samples, we use computed tomography (CT) methods to determine fluid imbibition in real time. In addition, oil recovery is recorded with time to compare the performance of surfactants and water alone. Finally, laboratory data are used in numerical simulation to model laboratory results and upscale these findings to the field. The results showed that aqueous solutions with surfactants altered rock wettability from oil-wet and intermediate-wet to water-wet and reduced IFT to moderately low values. In addition, cationic surfactant presented the highest adsorption capacity following a Langmuir type adsorption profile. Spontaneous imbibition results showed that aqueous solutions with surfactants had higher imbibition and were better at recovering oil from shale core compared to water without surfactants, which agrees qualitatively with wettability and IFT alteration. However, rock lithology and surfactant type play an important role in adsorption capacity and oil recovery. Our upscaling result shows that compared to a well that is not treated with surfactant, a 24% increase on the initial peak oil rate as well as a 8% increase on the 3-year cumulative oil production are observed. For the results obtained, we can conclude that the addition of surfactants to completion fluids can improve oil recovery by wettability alteration and IFT reduction, maximizing well performance after stimulation from Wolfcamp and Eagle Ford unconventional reservoirs.

Efficiency of castor oil–based polyurethane foams for oil sorption S10 and S500: Influence of porous size and statistical analysis

“…49 Small pores are important in the sorption capability because the capillary effects create a sorption force of the liquid, facilitating the oil’s retention. 49–51 The PU C presented a balance between great and small pores, contrasting with PU D-E , and a wider pore distribution (4.9 a 131.4 μm). This distribution tends to influence the sorption capacity.…”

A Literature Review of CO2, Natural Gas, and Water-Based Fluids for Enhanced Oil Recovery in Unconventional Reservoirs

“…The spontaneous imbibition of 4 wt % KI (potassium iodide) into Permian Basin cores resulted in the recovery of 11% OOIP after about 150 h. , Similar experiments with cores from the Wolfcamp formation resulted in the recovery of ∼8% OOIP after about 100 h or ∼2% OOIP after 65 h, and 2% OOIP from an Eagle Ford core after about 50 h . In a thorough study of the characteristics of several ULRs, imbibition of water into short, 2.5 cm diameter Bakken, Wolfcamp, or Eagle Ford cores was slow and required 100–200 h of immersion in order to reach an ultimate oil recovery of only 3–8% OOIP …”

“…266 The authors concluded that the shale could be viewed as a semipermeable membrane that initially promotes the flux of water into the shale at a greater rate than the high salinity formation brine, leading to increased oil recovery due to osmosis. 266,267 The spontaneous imbibition of 4 wt % KI (potassium iodide) into Permian Basin cores resulted in the recovery of 11% OOIP after about 150 h. 247,268 Similar experiments with cores from the Wolfcamp formation resulted in the recovery of ∼8% OOIP after about 100 h 269 or ∼2% OOIP after 65 h, 270 and 2% OOIP from an Eagle Ford core after about 50 h. 269 In a thorough study of the characteristics of several ULRs, imbibition of water into short, 2.5 cm diameter Bakken, Wolfcamp, or Eagle Ford cores was slow and required 100− 200 h of immersion in order to reach an ultimate oil recovery of only 3−8% OOIP. 69 Other tests conducted with Bakken cores noted a higher recovery of oil with LSW than high salinity brine during the long imbibition process; however the cores had very different permeability values: 58% of the oil was recovered using 2 wt % KCl brine in 14 days from a 0.94 mD Bakken core, while it took 23 days to recover 43% of the oil using 24 wt % KCl brine from a 0.001 mD Bakken core.…”

“…Surfactant formulations should be designed for the specific formations under consideration. − There are many examples of surfactant solutions for hydraulic fracturing, ,,− ,,,− and for EOR in conventional formations. ,,,,,− ,− , Here, we will focus on publications focused on surfactant solutions for EOR in ULRs. Many papers state that their results related to EOR in ULRs could also benefit the fracturing process.…”

Discussion of shale rock wettability and the methods to determine it

“…Based on Alvarez et al's measurements of contact angles and zeta potentials, the Wolfcamp cores and the Eagle Ford cores demonstrated intermediate wet to oil wet. But, their cores were aged for 4 weeks or 6 months.…”