Fracture treatment performance in Bakken liquid-rich shale reservoirs can be improved by altering rock wettability from oil-wet to water-wet. The use of surfactant additives for altering wettability also results in alteration of the interfacial tension (IFT). The Young−Laplace equation relates the capillary pressure to IFT and contact angle. Thus, it follows that capillarity is significant in nanopores associated with unconventional liquid reservoirs (ULRs) and complex as the contact angle (CA) and IFT varies simultaneously. This study carefully evaluates these interactive variables and compares the performance of anionic, nonionic, blended, and complex nanofluid (CnF) surfactants in recovering liquid hydrocarbon from siliceous and carbonate Bakken shale cores through spontaneous imbibition experiments. In addition, we also analyze the effect of wettability, surfactant adsorption, and IFT alteration on the process. CA measurement is used in determining the original wettability of Bakken cores, as well as the wettability alteration effectiveness of each surfactant. The results show Bakken ULR original wettability in the oilwet region, but most importantly, all surfactants are capable of shifting the wettability of the core to the water-wet region at fieldused concentrations. However, we observed that the extent of wettability alteration strongly depends on rock lithology and surfactant type. These results were also corroborated by zeta potential measurements. In addition, IFT measurement of Bakken crude oil shows that all surfactants cause a reduction in IFT value. Surfactant dynamic adsorption measurements also show the dependence of rock lithology on surfactant performance giving higher adsorption values on carbonate rocks to negatively charged surfactants and higher adsorption values on siliceous surfaces to more positively charged surfactants. Last, the surfactant potential of improving oil recovery in ultralow permeability Bakken cores is investigated by spontaneous imbibition experiments. Through the experiment, oil recovery is recorded and the system is scanned using computed tomography (CT) in order to analyze the movement of fluid in the core and to compare the performance between surfactants and slickwater without an additive. The results suggest that surfactants are better on recovering oil from a shale core, displacing more oil, and having higher imbibition than slickwater with no additive. However, oil recovery depends on surfactant type and rock mineral composition. These findings are consistent with CA, zeta potential, surfactant adsorption, and IFT measurements. From the results obtained, it can be concluded that altering wettability and moderately reducing IFT when surfactant additives are added to aqueous solutions can improve oil recovery in Bakken cores. These findings give an important understanding for designing completion fluid treatments and flowback schedules for these ULRs.
Summary Improving oil recovery from unconventional liquid reservoirs (ULRs) is a major challenge, and knowledge of recovery mechanisms and the 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 moderate interfacial-tension (IFT) reduction. Also, the extent of surfactant adsorption on the ULR surface during the imbibition of completion fluids is a key factor to consider when designing fracture jobs. The experimental and modeling work presented in this paper focuses on the effectiveness of surfactant additives for improving oil recovery in Wolfcamp and Eagle Ford reservoirs, as well as the extent of surfactant loss by adsorption during the imbibition of surfactant-laden completion fluid. Original rock wettability is determined by contact angle (CA) and zeta potential. Then, distinct types of surfactants—anionic, anionic/nonionic, and cationic—are evaluated to gauge their effectiveness in altering wettability and IFT. Moreover, surfactant-adsorption measurements are performed using ultraviolet/visible (UV/Vis) spectroscopy. Next, the potential for improving oil recovery using surfactant additives in ultralow-permeability Wolfcamp and Eagle Ford shale cores is investigated by spontaneous-imbibition experiments, and computed-tomography (CT) methods are used to determine fluid imbibition in real time. Finally, laboratory data are used in numerical simulations to model laboratory results and to upscale these findings to field scale. 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 with water without surfactants, which agrees qualitatively with wettability and IFT alteration. However, rock lithology and surfactant type played a key role in adsorption capacity and oil recovery. Our upscaling result showed that, compared with a well that is not treated with surfactant, a 24% increase in the initial peak oil rate and an 8% increase in the 3-year cumulative oil production were 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.
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.
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