• Energy Research

Abstract This study investigates fines migration and mineral reactions as a mechanism for CO2 residual trapping. We perform imbibition experiments using a sintered glass core and seven Berea sandstone cores. The cores receive four injection stages: water, CO2-saturated water, water-saturated CO2, and finally water or CO2-saturated water. During the second injection stage, the quantity of CO2-saturated water is altered to induce various degrees of fines migration and mineral reactions. These effects are found to yield residual CO2 saturations of 16%, 22% and 23% for zero, 25 and 50 pore volumes of CO2-saturated water injection, respectively. These percentages are 6–7% greater than if neither fines migration nor mineral reactions were present. This is attributed to pore plugging caused by fines migration and mineral reactions, impeding the imbibing water from displacing CO2 in the plugged pores. In addition, CO2-saturated water imbibition is found to increase residual CO2 saturation by 26–30% over that resulting from water imbibition. This is attributed to the CO2 dissolution effect during water imbibition. We therefore conclude that fines migration and mineral reactions is a CO2 residual trapping mechanism during CO2 sequestration.

Abstract CO2-water drainage relative permeability is usually measured in laboratory using a three-stage unsteady-state flooding on cores. This three-stage flooding involves injecting water, then CO2-saturated water, and finally water-saturated supercritical CO2. The injection of CO2-saturated water has been previously found to generate fines due to mineral dissolution. The generated fines can flow with injected fluids and cause pore blockage. This paper examines the effect of fines migration and mineral reactions on CO2-water drainage relative permeability measurements, using a sintered glass core and eight Berea sandstone cores. Three-stage and two-stage flooding are performed on the cores. Three-stage flooding sequence is same as literature. Two-stage flooding involves injection only of water and then water-saturated CO2, to avoid the chemical reactions brought about by CO2-saturated water injection and thereby reduce mineral reactions. Pressure difference across the cores and volumes of water produced are recorded. These data are used to generate CO2-water drainage relative permeability functions. Inductively Coupled Plasma Optical Emission Spectrometry (ICP-OES) analysis of the produced water and Scanning Electron Microscopy (SEM) images of the cores confirm mineral reactions occurred during CO2-saturated water injection in Berea cores. For Berea cores, CO2 relative permeability is reduced (by 21%–48%) during three-stage flooding when CO2-saturated water is injected. The reduction in CO2 relative permeability is found to be a function of water salinity and pore volumes of CO2-saturated water injected. Experiments performed on the glass core suggest that the error in CO2 relative permeability caused by the absence of CO2-saturated water is negligible. Therefore, we propose that CO2-saturated water be omitted during CO2-water drainage relative permeability measurements.

Abstract This paper presents CO2-brine wettability of sandstones and minerals composing the sandstones. The measured contact angles are used further to analyse the effect of wettability on fines migration during CO2 injection. Limited data are available to assess the effect of minerals' wettability on fines migration. We use the captive bubble method to measure contact angle of CO2-brine on Berea and Obernkirchener sandstones, and their mineral components. X-ray powder diffraction (XRD) and x-ray fluorescence (XRF) analysis show that these sandstones consist primarily of five minerals: quartz, kaolinite, chlorite, microcline, and muscovite. All contact angles were measured under a pressure of 5.5 MPa–13.8 MPa at temperatures of 38 °C and 55 °C. Scanning electron microscopy (SEM) and Energy Dispersive X-ray Spectroscopy (EDS) analyses are performed on mineral surfaces before and after measurements to examine surface changes after contact with CO2 and brine. The contact angle of the two types of sandstone indicates that their wettability was not clearly related to pressure and temperature. Quartz is found to be strong water-wet. Kaolinite, chlorite, and muscovite are found to be weak water-wet at 38 °C, whereas Microcline and muscovite show neutral-wettability at 55 °C. For chlorite, the contact angle is found to increase for the first 30 min, which is not observed for other minerals. SEM images reveal surface changes in kaolinite, chlorite, and muscovite after their exposure to CO2-saturated brine. SEM images also reveal heterogeneity in microcline sample, which accounts for the disagreement of our measurements with literature. For strong water-wet fines (contact angle

Abstract CO2 is injected into oil reservoirs to improve oil recovery and sequester greenhouse gas. However, the high mobility of CO2 leads to poor sweep efficiency; consequently, a large volume of oil in the reservoir is left behind, limiting the oil recovery and CO2 storage. This paper introduces water-saturated CO2 injection to improve oil recovery and CO2 storage by reducing the mobility of the CO2. Unlike carbonated water injection, in which the fluid is mostly water, the fluid in water-saturated CO2 injection is less than 1% water. Water-saturated CO2 injection and CO2 injection are compared experimentally using Bentheimer sandstone cores that contain oil. Oil recovery, pressure difference across the core, and compositions and rates of the produced fluids are recorded. The ultimate pressure difference across the core samples during water-saturated CO2 injection is found to be 4.76–9.55 times that the ultimate pressure difference during CO2 injection—indicating reduced CO2 mobility during water-saturated CO2 injection. To investigate the impact of this mobility reduction on oil recovery and CO2 storage, three-dimensional field-scale simulations are run. Simulations show that in the low permeable layer, the sweep efficiency during water-saturated CO2 injection exceeds that during CO2 injection. Consequently, the simulations find water-saturated CO2 injection to yield 7% higher oil recovery and 1.14 mega-tons additional CO2 stored than does CO2 injection.

Carbon dioxide (CO2) injection has been studied and applied as an important Enhanced Oil Recovery (EOR) method. However, a low volumetric sweep efficiency has always been a technical issue for continuous CO2 flooding because of high mobility and low density of CO2 in comparison with those of other reservoir fluids. The low volumetric sweep leaves large volumes of bypassed oil in the reservoir which in turn leaves limited pore space available for CO2 storage. Therefore, several mobility control methods have been trialed in laboratory and field pilot tests to improve the sweep efficiency. One mobility control method is CO2 simultaneous water-and-gas (CO2-SWAG) injection. The injected water displaces the oil which is bypassed by the CO2 to enhance oil recovery. Recent laboratory studies have found that fraction of CO2 injected (FGI) in a CO2-SWAG process can affect CO2 relative permeability function [1], [2]. An optimized FGI reduces the CO2 relative permeability, hence increasing the amount of CO2 retained in the pore space. Although the previous studies have highlighted strong dependency of CO2 relative permeability on FGI, the number of experiments performed were limited to find the optimum value of FGI. In this study we performed laboratory experiments to find optimum FGI to maximize oil recovery and CO2 storage during CO2-SWAG displacement in a Bentheimer sandstone. A 28cm long Bentheimer core sample was used for the study. Before the SWAG injection, the core is at irreducible water saturation. The oil phase is composed of 65% Hexane (C6) and 35% Decane (C10). Experiments are run at 1700psia and 700C which represents near-miscible conditions. Pure Supercritical CO2 and distilled water are injected simultaneously into the core at a fixed FGI. A total of 8 experiments were performed at FGI of 0.0, 0.25, 0.50, 0.75, 0.80, 0.997 and 1.0. FGI of 0.0 and 1.0 represents water injection and continuous CO2 injection, respectively while a FGI of 0.997 represents CO2water saturated CO2 at the experimental conditions. The produced fluids are collected in glass vials and are subsequently analyzed using the Gas Chromatography to quantify the produced water and hydrocarbons. A gas flowmeter is used to measure the mass rate of gas. The volume of the produced liquid and differential pressure across the core are continuously recorded during the experiment. A compositional commercial reservoir simulator is used to determine the FGI dependent relative permeability functions. Pressure drop across the core, oil recovery and the mass of CO2 stored are used as the matching parameters. The results indicate that 0.80 is the optimum FGI for the given experimental conditions. A remarkable reduction in CO2 relative permeability was observed for FGI 0.75 compared with continuous CO2 injection (FGI=1).