Enhanced Hydrocarbon Recovery In Tight And Shale Reservoirs Using Surfactants And Supercritical CO2
Date of Award
Doctor of Philosophy (PhD)
The tight and shale oil reservoirs have been becoming increasingly important energy resources. However, the flow and storage mechanisms of oil in tight and shale reservoirs are still ambiguous. The inorganic pores, organic pores, and kerogen skeleton in shale oil reservoirs can store hydrocarbons. Besides, the oil recovery of tight and shale oil reservoirs is extremely low even with the assistance of hydraulic fracturing and horizontal drilling. The surfactants and CO2 are commonly used to enhance the oil recovery in tight and shale reservoirs. A comprehensive review of CO2 and surfactants EOR is shown in Chapter Ⅱ.
The spontaneous imbibition is a very important mechanism for oil production from fractured reservoirs. The counter-current spontaneous imbibition experiments and nuclear magnetic resonance (NMR) were combined to study the imbibition and the fluid distribution in eight core samples. NMR is able to detect fluid distribution in different sizes of pores ranging from micropores to fractures. Before the experiments, the Middle Bakken and Berea cores were saturated with air. Then imbibition experiments with one end open (OEO) and two ends closed (TEC) boundary conditions were carried out. The numerical solutions of spontaneous imbibition models match quite well with experimental results by adjusting model parameters. The capillary pressure and relative permeability curves were obtained from the matching. The imbibition experiments, mathematical models, and nuclear magnetic resonance (NMR) results are discussed in Chapter Ⅲ.
Surfactants are very common chemicals for EOR in fractured tight reservoirs. We experimentally investigated EOR using various kinds of surfactants. Six core samples were obtained from the Middle Bakken Formation in North Dakota. Before the imbibition experiment, petrophysical analyses were conducted for the samples. XRD method was used to analyze the mineral composition. Nitrogen adsorption and SEM methods were combined to study the pore size distribution and microstructures. Then I performed brine imbibition and surfactant imbibition in six Bakken cores and two Berea sandstones. Before the experiment, the cores were fully saturated with Bakken crude oil. The core plugs were then submerged into the brine and surfactant solutions with an all-face-open (AFO) condition. Experiments of brine and surfactant imbibing into oil-filled cores were carried out with the recording of recovered oil volume using imbibition cells. Different types of surfactants such as cationic, anionic, and nonionic, were tested in the study. Those experiments and the results are presented in Chapter Ⅲ.
The shale oil reservoirs have much complex storage and flow mechanisms. The inorganic pores, organic pores, and kerogen matrix are important media to store water and oil in shale rocks. We present a vacuum imbibition method to identify the volume of water and oil in these media. Before the experiments, comprehensive rock characterizations were carried out on shale samples from Shahejie Formation combining various methods including N2 adsorption, scanning electron microscope (SEM), X-ray diffraction, and RockEval pyrolysis. Then, vacuum imbibition experiments were conducted on shale samples using water and n-dodecane. The accurate volumes of water in organic pores, oil in inorganic pores and organic pores, and the volume of dissolved oil were determined from vacuum imbibition experiments. The effects of thermal maturity (Ro) on shale storage were analyzed. Furthermore, novel mathematical models of oil and water vacuum imbibition in shale were proposed. The water imbibition in inorganic pores is a capillary flow. The oil imbibition in shale includes capillary flow in pore structures and diffusion in kerogen. The pore-kerogen double diffuse layer (PKDDL) physical model was proposed for the mechanisms of the hydrocarbon mass transfer between pore structures and kerogen. The capillary pressure and the dissolution rate constants were obtained by matching mathematical models with experimental results. This method is crucial for evaluating the water and oil storage and transfer in organic-rich shale and advances the crucial mechanisms for the evaluation and development of shale reservoirs. The experimental method, mathematical models, and results of the vacuum imbibition study are in Chapter Ⅳ.
The oil recovery of shale reservoirs is very low due to the extremely low permeability and the existence of organic matter. CO2 injection in shale oil reservoirs is a feasible method for CO2 geological sequestration and enhanced oil recovery. However, the mechanisms of mass transfer in inorganic pores and organic matter (kerogen) are still ambiguous. Thus, the mechanisms of diffusion and extraction were investigated. A novel pore-kerogen diffuse layer (PKDL) model was proposed for mass transfer between kerogen matrix and pores (inorganic pores and organic pores). Mathematical models for hydrocarbon mass transfer in spherical and cylindrical shaped rocks were derived. The predicted responses of the mathematical models closely matched the experimental data of CO2 injection experiments. Hydrocarbon recovery of shales shows a delayed effect compared to tight rocks due to the additional extraction process between supercritical CO2 and kerogen. Hydrocarbons were extracted out of the kerogen matrix and then diffused through the inorganic and organic pores. This theoretical research advances the diffusion and extraction theories in shale oil. The models and results are shown in Chapter Ⅴ.
Zhang, Shaojie, "Enhanced Hydrocarbon Recovery In Tight And Shale Reservoirs Using Surfactants And Supercritical CO2" (2020). Theses and Dissertations. 3397.