Experimental and field studies have indicated that surfactants enhance oil recovery (EOR) in unconventional reservoirs. Rock surface wettability plays an important role in determining the efficacy of this EOR method. In these reservoirs, the initial wettability of the rock surface is especially important due to the extremely low porosity, permeability, and resulting proximity of fluids to the solid surface. This study is designed to investigate the effect of oil components, rock mineralogy, and brine salinity on rock surface wettability in unconventional shale oil/brine/rock systems. Six crude oils, seven reservoir rocks, and seven reservoir brine samples were studied. These oil samples were obtained from various shale reservoirs (light Eagle Ford, heavy Eagle Ford, Wolfcamp, Middle Bakken, and Three Forks) in the US. SARA (saturates, aromatics, resins and asphaltenes) analysis was conducted for each of the crude oil samples. Additionally, this study also aims to provide a guideline to standardize the rock sample aging protocol for surfactant-related laboratory experiments on shale reservoir samples. The included shale reservoir systems were all found to be oil-wet. Oil composition and brine salinity showed a greater effect on wettability as compared to rock mineralogy. Oil with a greater amount of aromatic and resin components and higher salinity rendered the surface more oil-wet. Rock samples with a higher quartz content were also observed to increase the oil-wetness. The combination of aromatic/resin and the quartz interaction resulted in an even more oil-wet system. These observations are explained by a mutual solubility/polarity concept. The minimum aging time required to achieve a statistically stable wettability state was 35 days according to Tukey's analysis performed on more than 1100 contact angle measurements. Pre-wetting the surface with its corresponding brine was observed to render the rock surface more oil-wet.
Abundant resources being left behind at the end of the short production life of an unconventional liquid-rich reservoir (ULR) well has inspired many to investigate methods to improve the recovery. One eminent method is through the addition of surfactant during the completion stage of the well. Through numerous published laboratory studies, it can be concluded that this process possesses a promising potential in improving overall well productivity. Several field-scale results gathered from public data sources also confirmed the laboratory-scale study by correlating the effect of surfactants to the improvement of the estimated ultimate recovery (EUR). However, the absence of independency on those field-scale results often casts doubt on the actual efficacy of the method. The lack of field-scale information in the realm of scientific publications contributes to the limited understanding of surfactant application. This study is to fulfill the obvious need of field-scale studies on the application of surfactant by surfactant-assisted spontaneous imbibition (SASI) during completion of wells in the ULR. Numerical-based upscaling through modification of capillary pressure and relative permeability of the laboratory-scale experimental results provides a view on the effectiveness of this method on the field scale. Comparison is performed between the initial oil production rate, cumulative oil, and cumulative water production. A complete set of the laboratory-scale experimental studies is also included and consists of interfacial tension, contact angle, zeta potential, adsorption isotherm, and CT-assisted spontaneous imbibition. CT-scan technology is incorporated as well in the construction of a core-scale numerical grid model to model the heterogeneity of the shale core plug sample. In the end, sensitivity analysis is also executed to analyze the effect of different reservoir properties and SASI-related completion parameters on the efficiency of the method. There are four main takeaways of this comprehensive study. First, a complete and robust workflow on investigating SASI performance is compiled and tested. This workflow consists of a laboratory-scale experimental study as well as a numerical-based field-scale investigation and can be applied to different shale reservoirs as well as different surfactants. Second, three different surfactants are tested in this study with significant well production improvement observed, thus confirming the increment of production observed in the laboratory-scale study. These results are also compared to other lab-scale experiments conducted with different ULR samples to verify and strengthen the effectiveness of SASI. Third, sensitivity analysis shows that SASI improves well productivity for a variety of fracture and matrix properties. We observed a range of matrix and fracture properties where SASI performs optimally, and last, an independent field data study is provided. This actual case study is done carefully to isolate the effect of SASI on the well production. An agreement on the range of production improvement by SASI between the field data analysis and the numerical field-scale model is also observed.
Abstract Field observations and laboratory experiments have proven the possibility of production enhancement of shale oil wells through surfactant addition into completion fluid and perhaps, surfactant injection for EOR. This study numerically upscaled laboratory data for multi-stage hydraulic fracturing treatment and injection process proposed for the Wolfcamp formation. A combination of rock mechanic and reservoir numerical modeling was used to approximate the field-scale performance of both techniques. Novel completion fluid formulations and optimum surfactant injection schemes were designed, based on actual completion and production data. Surfactant-Assisted Spontaneous Imbibition (SASI) experiments data for two surfactants investigated on the core-scale were upscaled to model production response of a hydraulically fractured well in Upton County, Texas, with realistic fracture geometry and conductivity. Core plugs were saturated and aged with their corresponding oil to restore the original oil saturation. Contact angle, interfacial tension (IFT), and zeta-potential were measured to investigate the role of capillary pressure for surfactant tests. We use a dual-porosity compositional model to determine the surfactant transport and adsorption. With the proposed methodology, we show that lateral heterogeneity may limit both hydraulic fracture propagation and uniform distribution of EOR fluids, which cannot be ignored for the sake of simplicity. The primary production mechanism of aqueous phase surfactant EOR is wettability alteration and the reduction of IFT. Laboratory-scale SASI experimental results revealed that 2 gpt of surfactant solutions recovered up to 30% of the original oil in place (OOIP), whereas water alone recovered 10%. Capillary pressure and relative permeability curves were generated by scaling group analysis and history-matching the results of imbibition experiments on CT-generated core-scale model. On the next step, these curves were applied to surfactant completion and injection simulation models. The field-scale model was achieved from history-matching actual well production data. We tested different soak times, injection pressure, and number of cycles in surfactant injection simulations to provide an optimum design for this scheme. Simulation results indicated that surfactant injection has further potential for higher recovery factor in addition to the incremental Estimated Ultimate Recovery (EUR) observed with application of surfactant as a completion fluid alone. Also, we investigated water-injection after primary depletion (water without surfactant) to provide another possible method for unconventional liquid reservoirs (ULR). Instead of referring to Huff-n-Puff which implies gas injection, in this manuscript we use the terminology Multi-Cycle Surfactant-Assisted Spontaneous Imbibition (MC-SASI) to describe surfactant Huff-n-Puff for EOR. This paper provides a complete workflow on SASI-EOR that has been evaluated in laboratory experiments, during the completion phase, and after primary depletion. In addition, we assessed the potential of water-injection after primary depletion in enhancing EUR. The numerical models were developed by accounting for geomechanics based on actual data combined with surfactant EOR laboratory experiments, field data, and industry-accepted simulators. A new modeling workflow for SASI-EOR is proposed to unveil the actual potential of surfactant additives.
Abstract Observations from pilot wells along with laboratory experiments have revealed the significant potential of CO2 as an EOR agent in unconventional liquid reservoirs (ULR). This study focuses on unveiling the mechanisms of gas injection EOR through a combination of experimental results, ternary diagram analysis, and core-scale simulation. In addition, laboratory results were upscaled to the field-scale to evaluate the effectiveness of the CO2 injection in production enhancement from ULR. Gas injection experiments were performed at different pressures, and the laboratory results were upscaled to evaluate the production enhancement through gas injection EOR in ULR. A CT-generated core-scale model was utilized to investigate the mechanisms of gas injection EOR. Mechanisms such as diffusion and multi-contact miscibility were determined from core-scale simulation through history-matching experimental results, then upscaled to the field-scale model. Ternary diagrams reveal that EOR by gas injection is only effective at pressures greater than the Minimum Miscibility Pressure (MMP). Alteration of the injected gas and composition of crude oil clearly has an implication on changing the ternary diagram. The primary production mechanisms of CO2 EOR are multi-contact miscibility, vaporizing/condensing gas drive, oil swelling, and diffusion. Gas injection experiments recovered up to 45% of the Original Oil In Place (OOIP) at 3,500 psi, but the recovery factor was less than 5% when operating below the MMP. Diffusion has a minor effect in enhancing oil recovery in ULR based on the core-scale history-matching results. The multi-contact miscibility is found to be the primary driving mechanism for oil extraction during gas injection. Ternary diagrams analysis clearly demonstrates that MMP plays a significant role in gas injection and that miscible conditions need to be achieved for EOR projects in ULR. CT-scan technology is utilized to demonstrate the movement of the fluids inside the cores throughout the experiments. Thus, we can determine the high flow path regions of the core plugs. Additionally, the impact of injection pressure and the start time of the gas injection process were analyzed using the field-scale model. The simulation results indicate that gas injection has significant potential of enhancing oil production in ULR. This study not only reveals the mechanisms of gas injection in ULR, but also provides a method for designing and optimizing gas injection for Huff-n-Puff EOR. This study challenges the paradigm that diffusion is the dominating parameter of CO2 injection EOR in ULR. The novelty comes from the establishment of gas injection EOR mechanism in ULR through a thorough analysis of laboratory experiments, core-scale simulation, and ternary diagram analysis. In addition, a new modeling workflow for the design of gas injection strategies is proposed to unveil the real potential of gas injection.
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.
Abstract Field experience along with laboratory evidence of spontaneous imbibition via the addition of surfactants into the completion fluid is widely believed to improve the IP and ultimate oil recovery from unconventional liquid reservoirs (ULR). During fracture treatment with surface active additives, surfactant molecules interact with the rock surface to enhance oil recovery through wettability alteration combined with interfacial tension (IFT) reduction. The change in capillary force as the wettability is altered by the surfactant leads to oil being expelled as water imbibes into the pore space. Several laboratory studies have been conducted to observe the effectiveness of surfactants on various shale plays during the spontaneous imbibition process, but there is an insufficient understanding of the physical mechanisms that allow scaling the lab results to field dimensions. In this manuscript, we review and evaluate dimensionless, analytical scaling groups to correlate laboratory spontaneous imbibition data in order to predict oil recovery at the field scale in ULR. In addition, capillary pressure curves are generated from imbibition rate theory originally developed by Mattax and Kyte (1962). The original scaling analysis was intended for understanding the rate of matrix-fracture transfer for a rising water level in a fracture-matrix system with variable matrix block sizes. Although contact angle and interfacial tension (IFT) are natural terms in scaling theory, virtually no work has been performed investigating these two properties. To that end, we present scaling analysis combined with numerical simulation to derive relative permeability curves, which will be imported into a discrete fracture network (DFN) model. We can then compare analytical scaling methods with conventional dual porosity concepts and then progressed to more sophisticated Discrete Fracture Network concepts. The ultimate goal is to develop more accurate predictive methods of the field-scale impact due to the addition of surfactants in the completion fluid. Correlated experimental workflows were developed to achieve the aforementioned objectives including contact angle (CA) and IFT at reservoir temperature. In addition, oil recovery of spontaneous imbibition experiments was recorded with time to evaluate the performance of different surfactants. Capillary pressure-based scaling is developed by modifying previously available scaling models based on available surfactant-related properties measured in the laboratory. To ensure representability of the scaling method; contact angle, interfacial tension, and ultimately spontaneous imbibition experiments were performed on field-retrieved samples and used as a base for developing a new scaling analysis by considering dimensionless recovery and time. Based on the capillary pressure curves obtained from the scaling model, relative permeability is approximated through a history matching procedure on core-scale numerical models. CT-Scan technology is used to build the numerical core plug model in order to preserve the heterogeneity of the unconventional core plugs and visualize the process of water imbibition in the core plugs. Time-lapse saturation changes are recorded using the CT scanner to visualize penetration of the aqueous phase into oil-saturated core samples. The capillary and relative permeability curves can then be used on DFN realizations to test cases with or without surfactant. The results of spontaneous imbibition showed that surfactant solutions had a higher oil recovery due to wettability alteration combined with IFT reduction. Our upscaling results indicate that all three methods can be used to scale laboratory results to the field. When compared to a well without surfactant additives, the optimum 3-year cumulative oil production of well that is treated with surfactant can increase by more than 20%.
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.
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