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.