In situ fluid dynamics and CO2 injection in porous rocks

Abstract

Understanding multiphase fluid flow in porous rocks implies knowledge of fundamental properties such as wettability, relative permeability and capillary pressure. These parameters, as well as the extent of fractures and their permeability and interconnection, are vital information needed to predict oil recovery, select production scenario and initiate EOR strategies in the reservoir. In this thesis, wettability, relative permeability and capillary pressure are measured directly from in situ saturation and pressure data and the impacts on oil recovery from capillary continuity across fractures have been studied. Finally, injection of CO2 to enhance oil recovery is investigated at different wettabilities and when varying a wide range of injection scenarios. Conventionally, relative permeability curves are generated from capillary pressure curves using best-fit analyses of the production data. Experimental methods to measure relative permeability include unsteady-state methods which are based on production data and average pressure drop across entire core samples. They may thus fail to capture capillary end effects and local variations and heterogeneities. The steady-state methods claim to describe dynamic properties but rely on pressure or saturation equilibrium. Alternatively, some steady-state methods are based on simultaneous injection of one wetting and one non-wetting fluid phase but aim to describe the properties of either drainage or imbibition processes. An alternative, explicit method to calculate relative permeabilities has been reviewed and slightly modified in this thesis, and dynamic capillary pressure curves have been measured at different wettabilities based on in situ saturation and phase pressure data collected during continuous flooding. Both methods utilize dynamic measurements to describe the properties of relative permeability and capillary pressure as opposed to most conventional methods. The relative permeability curves showed consistency with wettability, and a good match with conventional curves at strongly water-wet conditions was obtained. The capillary pressure curves corroborated data obtained from centrifuge experiments at strongly water-wet, less water-wet and near neutral-wet conditions. In addition, the proposed methods for obtaining both relative permeability and capillary pressure curves are time-saving, and in situ data increased the accuracy and confidence of the input to numerical simulators used to predict reservoir fluid flow. A drawback with the conventional Amott-Harvey Index of wettability measurement method is the time consumed from obtaining spontaneous imbibition data. The possibility to capture local heterogeneities is also limited in this method, as the data collected from imbibition and subsequent water- or oilfloods are average measures obtained from whole core samples. In this work, local wettability indices are measured during continuous flooding from in situ saturation and local pressure data by identifying the separate contributions to oil recovery from spontaneous imbibition and viscous displacement. The obtained wettability indices demonstrate an excellent match with the conventional data. Previous work has shown that wetting phase bridges across an open fracture establish capillary continuity between two mixed-wet matrix blocks and increase oil recovery exceeding the end-point for spontaneous imbibition. However, the wetting phase produced from the inlet matrix block during drainage of strongly wetted systems forms a film on the outlet end and fails to establish capillary continuity across the fracture. In this work, capillary continuity in strongly wetted systems has been established during drainage processes by packing the separating fracture with micro-particles. Capillary continuity was determined by monitoring the volume accumulated by the capillary end effect during continuous injection of the non-wetting phase. The demand for enhanced oil recovery in mature oil fields combined with carbon neutral solutions and high quality in situ data is increasing. Several projects have been initiated worldwide to capture CO2 from fossil fuel-fired power plants and other industrial processes, and CO2 is thus becoming more available for EOR projects. In order to further increase the understanding of multiphase dynamic fluid flow in porous media, MRI was used to monitor in situ saturation development during injection of liquid or supercritical CO2 at different wettabilities and at miscible conditions. A series of experiments was initiated to study oil recovery potential from injection of compressed CO2 at secondary and tertiary conditions, monitor in situ fluid flow and investigate oil recovery mechanisms in low-permeable outcrop chalk. Qualitative analysis of the MRI images indicated oil swelling at the front as the CO2 propagated through the cores, and enhanced oil recovery ranging from 9.4 %PV to 67 %PV was determined from material balance calculations. During tertiary injection of liquid CO2 in a fractured core sample, MRI images suggested that the oil in the middle and outlet end of the core was bypassed due to high fracture permeability. The results obtained from the various experiments emphasize the importance of using high spatial resolution saturation imaging, providing increased understanding of multiphase in situ fluid flow in porous media, assisting in predicting recovery mechanisms and improving input data used in numerical simulators.