We present the first comprehensive experimental evaluation of CO2 EOR in organic rich shale. Experiments in preserved core demonstrated the potential of CO2 to extract the naturally occurring oil in organic rich shale reservoirs, whereas tests in re-saturated core plugs were used to compute accurate recovery factors, and evaluate the effect of soak time, operating pressure, and the relevance of slim-tube MMP on recovery. 18 core-flooding experiments were conducted in sidewall cores from different shale plays.
The cores re-saturated with crude oil, were first cleaned by Dean-Stark extraction, and submitted to porosity and compressibility determination. The re-saturation, confirmed by CT-scanning, was attained by aging the core plugs at high pressure for two to four months. In all experiments, glass beads surrounding core samples were used to simulate the proppant and physically recreate in the laboratory a hydraulic fracture connected to the shale matrix. The slim-tube MMP was measured with CO2, and core-flooding experiments were performed below, close to, and above the MMP. The displacement equipment was coupled to a medical CT-scanner that enabled us to track the changes in composition and saturation taking place within the shale cores during the experiments. Continuous CO2 injection and huff-and-puff were evaluated using soak time from zero to 22 hours. Fixed reservoir temperature was used in all the experiments.
Recovery factors ranged from 1.7 to 40%. The wide variation was the result of different experimental conditions for pressure and soak time. Both operational parameters were found to significantly affect the recovery. Increasing soak time at constant pressure consistently resulted in significant increase in recovery. The increase varied from 78 to 464% for different pressures and oil composition. Similarly, increasing operating pressure at constant soak time resulted in significant increase in recovery factor from 44 to 338% depending on soak time and oil composition. Unlike the typical response during CO2 EOR in conventional rocks, in organic rich shale, further pressure increases beyond the slim-tube MMP continued to increase the recovery factor significantly. In all runs, almost all oil recovery occurred within three days from the start of the experiment, and in all huff-and-puff tests the highest rate of recovery was observed in the first cycle, implying oil recovery with CO2 is a fast process, in comparison to oil re-saturation of the samples which occurs at a significantly slower rate.
This investigation demonstrates CO2 EOR is a technically feasible method to extract significant amounts of crude oil from organic rich shale reservoirs and it provides operational understanding of how to manage pressure and soak time to maximize recovery. The recovery factors obtained in this investigation, in the context of the vast reserves of crude oil contained in organic rich shale, can sustain a second shale revolution and further capitalize oilfield infrastructure.
We investigated the combined contributions of gravity drainage and miscibility as recovery mechanisms during CO2 flooding. The effects of gravity stable and unstable CO2 fronts under immiscible, near miscible and miscible displacements of crude oil by CO2 are presented. We contrast our results in porous media, with slim tube experiments, core floods, and bead packed tubes.
Standard slim-tube, vertically and horizontally oriented bead packed tubes, as well as vertical and horizontal reservoir core flood experiments, were used to investigate the role of the gravitational forces in improving oil recovery under different conditions regarding the crude oil – CO2 miscibility. Three crude oils with different minimum miscibility pressure (MMP) values were used in this study.
Our results show the gravity drainage mechanism has a much greater significance than previously thought when compared to the effects of phase behavior or the miscibility alone. Not surprisingly, vertically stable, downward displacement resulted in better performance compared to horizontal displacement in all cores and bead packed tubes in our experiments. Recovery is only slightly higher in the gravity stable floods when miscibility is achieved. However, in immiscible and near miscible displacements, recovery is significantly higher in the gravity stable floods, reaching up to 90% RF at 250 psi below the MMP value, compared to only 33% in horizontal floods. Our results suggest that achieving miscibility is not necessary to obtain high recovery efficiency during a gravity-stable displacement. Breakthrough is reached faster in horizontal floods as a consequence of fingering and gravity override.
This work challenges the paradigm that miscibility is required to achieve high recovery factors during CO2 flooding, and highlights the overlooked role of gravity drainage as a displacement mechanism. This finding has an essential impact on field operations as it allows for lower operating pressures in CO2 flooding processes under stable gravity displacement that will result in positive impact on economics. The relevance of our results is exacerbated by the current low crude oil price environment.
Zhang, Fan (Texas A&M University) | Saputra, I. W. R. (Texas A&M University) | Niu, Geng (Texas A&M University) | Adel, Imad A. (Texas A&M University) | Xu, Liang (Halliburton) | Schechter, David S. (Texas A&M University)
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
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%.
The application of surfactants to improve oil recovery in conventional reservoirs via wettability alteration and enhancement of spontaneous imbibition has been extensively studied in the literature. However, little work has been performed yet to investigate the interaction of these surfactants with ultra-tight oil-rich shale reservoirs such as Wolfcamp shale. The use of horizontal drilling and massive multistage hydraulic fracturing has made primary oil recovery from these ultra-tight oil-rich shale reservoirs possible. With declining production from existing shale wells, it is essential to explore potential "beyond primary" strategies in shale oil development. This paper analyzes the potential of surfactants in altering wettability and improving the process of spontaneous imbibition in oil rich shales demonstrating nanodarcy range permeability, relevant to stimulation and "beyond primary" chemical EOR applications in shales.
Novel proprietary surfactant blends along with traditional nonionic surfactants were investigated in this study using Wolfcamp shale core samples exhibiting nanodarcy permeability. X-ray diffraction analysis was performed which indicated that Wolfcamp shale has mixed mineralogy, with quartz, calcite, and dolomite acting as the major minerals in varying proportions depending on the interval depth. Contact angle and interfacial tension measurements were performed at reservoir temperature to identify the state of native wettability and the impact of surfactants in altering wettability. Thereafter, spontaneous imbibition experiments were performed using 3D computed tomography methods to understand the improvement in the magnitude of imbibition penetration due to surfactant addition. Contact angle and spontaneous imbibition experiments showed that Wolfcamp shale is intermediate-wet and surfactants have the potential to alter the native wettability to a preferentially water-wet state and improve oil recovery due to enhanced spontaneous imbibition.
Surfactants which altered the wettability significantly, but lowered the interfacial tension only slightly showed the highest oil recoveries due to the creation of strong capillary driven forces directly responsible for effective spontaneous imbibition. The potential of surfactants in altering wettability and improving oil recovery via enhanced spontaneous imbibition in ultra-tight oil-rich shales was verified in this study. The effectiveness of traditional nonionic surfactants in altering wettability and improving oil recovery was found to be comparable to that of novel, more expensive proprietary surfactant blends, and hence, the traditional nonionic surfactants provide a cost effective option for stimulation and EOR applications in Wolfcamp shale. Overall, this paper presents the theory behind surfactant interaction with ultra-tight shales and provides experimental results to validate the viability of surfactant induced improved oil recovery in shales.
We present a technique that enables the determination of the minimum miscibility pressure (MMP) of a CO2 – oil system using a short 20 ft slim tube in less than two weeks, about a third of what it normally takes using the conventional 80 ft slim tube. MMP is a crucial parameter in designing a CO2 enhanced oil recovery project and its value needs to be known with a degree of accuracy that cannot be provided by the use of equations of state or correlations, and therefore, needs to be determined experimentally. The slim tube technique is recognized to be the most accurate experimental method for determining the MMP, however its use has not been favored because it is time consuming.
We determined the MMP for five CO2 – crude oil systems from the North Burbank Unit and the Oklahoma/Texas Panhandle. The reduction in the length of the slim tube from 80 ft to 20 ft resulted in a decrease in the total time of the experiment. The validity of our technique was proven with performing recovery factor measurements using a conventional 80 ft long slim tube. The MMP values obtained are valid when the length of the slim tube is sufficient to host the mixing zone and the velocity of the displacement is slow enough to enable the transverse dispersion to eliminate viscous fingering. In the case of light oil, the use of the 20 ft slim tube is justified as the length of the mixing zone is shorter. We support our results with the use of numerical simulation.
The reduction in the time required for slim tube experiments results in a fast, economic and accurate technique for the determination of MMP in CO2 – light crude oil systems. Taking into account that CO2 flooding is the most applied EOR technique in the US and that it is mainly applied to light oil reservoirs, this work can be of great impact by providing a rapid and reliable method to determine the MMP for designing a CO2 enhanced oil recovery project.