Pore Scale Characterization Of Wettability And Displacement Mechanisms During Oil Mobilization Due To Waterflood Based Oil Recovery Schemes

We present the results of an extensive pore-scale experimental study of trapping of oil in topologically disordered naturally-occurring pore spaces. A unique miniature core-flooding system is built and then integrated with a high-resolution micro-computed tomography (micro-CT) scanner to create a new experimental platform, which enables us to conduct flow experiments on a small rock specimen, nominally 5-mm-diameter, at conditions representative of subsurface reservoirs while the sample is being imaged. We develop robust experimental procedures and state-of-the-art image analysis techniques to characterize in-situ wettability and accurately map the spatial distribution of fluid phases at the pore level during various multiphase flow phenomena. This indeed has the possibility to transform our understanding of these important flow processes and allows us to have a much more effective way of designing enhanced oil recovery schemes deployed in a wide range of geological systems. Below, we list four key applications of this new approach, which are achieved under this study. These include: (1) In-situ characterization of wettability and pore-scale displacement mechanisms; (2) Micro-scale investigation of the effects of flow rate on nonwetting phase trapping; (3) Systematic examination of the impact of brine salinity on residual phase saturation; and (4) Experimental study of the remobilization of trapped oil ganglia associated with CO2 exsolution during carbonated water injection. Initially, we perform several two-phase experiments on Berea sandstone core samples and characterize contact angle hysteresis for various fluid pairs. Afterward, we carry out a three-phase experiment including a secondary gas injection followed by a waterflood and then an oilflood. We generate in-situ oil-water, gas-water, and gas-oil contact angle distributions during each stage of this flow experiment and compare them with the two-phase counterparts to develop new insights into relevant complex displacement mechanisms. The results indicate that, during gas injection, the majority of displacements involving oil and water are oil-to-water events. It is observed that, during the waterflood, both oil-to-gas and gas-to-oil displacement events take place. However, the relative frequency of the former is greater. For the oilflood, gas-water interfaces only slightly hinge in pore elements. Pore-scale fluid occupancy maps and the Bartell-Osterhoff constraint verify the above-mentioned findings. Secondly we conduct a pore-scale experimental study of residual trapping on consolidated water-wet sandstone and carbonate rock samples. We investigate how the changes in wetting phase flow rate impacts pore-scale trapping of the nonwetting phase as well as size and distribution of its disconnected globules. The results show that with increase in imbibition flow rate, the residual oil saturation reduces from 0.46 to 0.20 in Bemtheimer sandstone and from 0.46 to 0.28 in Gambier limestone. The reduction is believed to be caused by alteration of the order in which pore-scale displacements took place during imbibition. We use pore-scale displacement mechanisms, in-situ wettability characteristics, and pore size distribution information to explain the observed capillary desaturation trends. Furthermore, we explore that the volume of individual trapped oil globules decreases at higher brine flow rates. Moreover, it is found that the pore space in the limestone sample is considerably altered through matrix dissolution at extremely high brine flow rates. Imbibition in the altered pore space produces lower residual oil saturation (from 0.28 to 0.22) and significantly different distribution of trapped oil globules. Thirdly, a series of micro- and core-scale flow experiments are carried out on mixed-wet reservoir sandstone core samples at elevated temperature and pressure conditions to examine the impact of injection brine salinity on oil recovery and accentuate governing displacement mechanisms. Individual core samples are cut from a preserved reservoir whole core, saturated to establish initial reservoir fluid saturation conditions, and subsequently waterflooded with low- and high-salinity brines. In addition to the preserved experiments, several samples are cleaned, subjected to a wettability restoration process, and then used for waterflooding experiments. The results indicate approximate waterflood residual oil saturations (S[subscript]orw) of 0.25 and 0.39 for LSWF and HSWF, respectively. These observations highlight the remarkably superior performance of LSWF compared to that of HSWF. LSWF tests show a more prolonged oil recovery response than HSWF. The findings provide direct evidence that LSWF also causes a wettability alteration toward increasing water-wetness – due to limited release of mixed-wet clay particles and multi-component ion exchange, whereas contact angles measured during HSWF remain unchanged. It is observed that the reduction in oil-water contact angles lowers the threshold water pressure needed to displace oil from some medium-sized pore elements and enhances oil recovery during LSWF. Finally, we present the results of a micro-scale three-phase experimental study, using a spreading fluid system, of carbonated water injection and subsequent CO2 exsolution, as a consequence of pressure depletion, that lead to recovery of a significant fraction of trapped oil. Micro-CT visualization of pore occupancy show that the gradual increase in the pressure drop leads to exsolution of CO2, internal gas drive, mobilization of oil ganglia, and a notable reduction in waterflood residual oil saturation. When contacted by CO2, oil globules form thick spreading layers sandwiched between brine (in the corners) and gas (in the center of pores) and are displaced toward the outlet along with moving gas clusters. We observe significant re-connection of trapped oil globules due to oil layer formation during early stages of CWI. The oil layers stay stable until the very late stages of gas exsolution.