• Energy Research

Abstract Reservoir heterogeneity at various length scales is a well-established fact. This includes reservoir wettability − a key factor influencing CO2 geo-storage efficiency and containment security − which changes with depth, and is generally non-uniform due to different depositional environments and fluid flow paths over geological times. However, the effect of heterogeneous wettability distribution on CO2 storage efficiency is not understood. Moreover, there is a knowledge gap in terms of how temperature affects capillary and dissolution trapping, CO2 mobility and vertical CO2 migration distance, particularly when coupled with wettability heterogeneity effects. Thus, in this work we studied the effect of wettability heterogeneity and reservoir temperature on the vertical CO2 plume migration, and capillary and dissolution trapping capacities. Our results clearly show that both wettability heterogeneity and reservoir temperature have a significant effect on vertical CO2 migration, and the associated capillary and dissolution trapping mechanisms: both heterogeneously distributed wettability and higher temperature significantly accelerated the vertical CO2 migration, CO2 mobility and solubility trapping, while it reduced residual trapping. We thus conclude that wettability heterogeneity and reservoir temperature are important factors in the context of CO2 geo-storage, and that heterogeneous wettability and higher reservoir temperatures reduce storage capacity.

Abstract Wettability of CO2-brine-mineral systems plays a vital role during geological CO2-storage. Residual trapping is lower in deep saline aquifers where the CO2 is migrating through quartz rich reservoirs but CO2 accumulation within a three-way structural closure would have a high storage volume due to higher CO2 saturation in hydrophobic quartz rich reservoir rock. However, such wettability is only poorly understood at realistic subsurface conditions, which are anoxic or reducing. As a consequence of the reducing environment, the geological formations (i.e. deep saline aquifers) contain appreciable concentrations of various organic acids. We thus demonstrate here what impact traces of organic acids exposed to storage rock have on their wettability. Technically, we tested hexanoic acid, lauric acid, stearic acid and lignoceric acid and measured wettability as a function of organic acid concentration at realistic storage conditions (i.e. 25 MPa and 323 K (50 °C)). In addition, measurements were also conducted at ambient conditions in order to quantify the incremental pressure effect on wettability. Clearly, the quartz surface turned significantly less water-wet with increasing organic acid concentrations, even at trace concentrations. Importantly, we identified a threshold concentration at ˜10−6 M organic acid, above which quartz wetting behaviour shifts from strongly water-wet to an intermediate-wet state. This wettability shift may have important consequences for CO2 residual trapping capacities, which may be significantly lower than for traditionally assumed water-wet conditions where CO2 is migrating through quartz rich reservoirs.

Low-salinity water injection emerges to be a cost-effective and environmentally friendly enhanced oil recovery technique. Furthermore, additives, such as the surfactant and nanoparticles in combina...

AbstractEnhanced coalbed methane recovery and CO2 geostorage in coal seams are severely limited by permeability decrease caused by CO2 injection and associated coal matrix swelling. Typically, it is assumed that matrix swelling leads to coal cleat closure, and as a consequence, permeability is reduced. However, this assumption has not yet been directly observed. Using a novel in situ reservoir condition X‐ray microcomputed tomography flooding apparatus, for the first time we observed such microcleat closure induced by supercritical CO2 flooding in situ. Furthermore, fracturing of the mineral phase (embedded in the coal) was observed; this fracturing was induced by the internal swelling stress. We conclude that coal permeability is drastically reduced by cleat closure, which again is caused by coal matrix swelling, which again is caused by flooding with supercritical CO2.

Abstract Rock mechanical properties are of key importance in coal mining exploration, coal bed methane production and CO2 storage in deep unmineable coal seams; accurate data is required so that geohazards (e.g. layer collapse or methane/CO2 leakage) can be avoided. In this context it is well established that coal matrix swelling due to water adsorption significantly changes the coal microstructure. However, how water adsorption and the associated with microstructural changes affect the mechanical properties is only poorly understood, despite the fact that micro-scale mechanical properties determine the overall geo-mechanical response as failure initiates at the weakest point. Thus, we measured nanoscale rock mechanical properties via nanoindentation tests and compared the results with traditional acoustic methods on heterogeneous medium rank coal samples in both dry and brine saturated conditions. The microscale heterogeneity of the rock mechanical properties was mapped and compared with the morphology of the sample (measured by SEM and microCT). While the nanoindentation tests measured decreasing indentation moduli after water adsorption (−60% to −66%), the traditional acoustic tests measured an increase (+17%). We concluded that acoustic tests failed to capture the accurate rock mechanical properties changes for the heterogeneous coal during water adsorption. It is thus necessary to measure the coal rock mechanical properties at the microscale to obtain more accurate data and reduce the risk of geohazards.

Abstract Carbonate rock is a potential host for carbon dioxide storage. It is likely to react with carbonated water, following CO2 dissolution and dissociation in formation fluids. This might lead to carbonate dissolution or precipitation, depending on pH and formation fluid composition. In case of dissolution, the formation gets mechanically weaker, which could pose a risk for the mechanical stability of the formation, requiring a deeper understanding. In this paper, we used a direct CT scanning – DEM (Discrete Element Method) combined method to investigate how limestone rock mechanical properties change during CO2 injection. The results show that the minor dissolution happened after scCO2 injection, but such damage was much weaker when compared with the sample after live brine flooding. Related morphology change directly affects the rock mechanical response where the maximum compressive stress dropped from 17.2 MPa (for dead brine saturated), to 14.8 MPa (for scCO2 injection), and to 7.9 MPa (under live brine injection). We thus conclude that CO2 injection into pure carbonate reservoirs can impact the mechanical strength of matrix rock, and that the applied DEM models work well since they predicted a reliable stress-strain curve.

Carbon geosequestration in deep saline aquifers is an efficient way to mitigate climate change due to greenhouse gas emissions. The carbonate reservoir is the one of the selected storage site, however, such carbonate rock is sensitive to the acidic environment – where the CO2 saturated formation water could be as medium acid in the reservoir condition. Thus, fully understand such CO2-water-rock interaction and the related rock mechanical properties change are very important for the storage security. However, how the elastic moduli change in the different storage areas are still blank. In this paper, we thus injected scCO2 and CO2 saturated (live) brine into Savonnières limestone core plugs at reservoir conditions to simulate the different areas in the real geosequestration sites. The flooding tests were set as a representative reservoir conditions at approximately 1000m depth with 325 K, 15 MPa confining pressure and 10 MPa pore pressure. The X-ray CT scanning and ultrasonic tests were conducted to monitor the change before and after the flooding. The morphology results showed that the CO2 saturated brine injection had larger dissolution effect than scCO2 and consistent with the calculated Young’s moduli change. Moreover, the Poisson’s ratio slightly had slightly dropped after scCO2 flooding but build up by live brine. We thus suggested that Poisson’s ratio could be used to monitor the CO2 underground conditions (supercritical condition or saturated with brine) in such limestone carbon storage which need more future investigations. Read More: https://library.seg.org/doi/abs/10.15530/urtec-2018-2902695

Abstract Carbon dioxide geosequestration in deep saline aquifers or oil and gas reservoirs is a key technology to mitigate anthropogenic greenhouse gas emissions. Porous carbonate rock is a potential host rock for CO 2 storage; however, carbonate rock chemically reacts when exposed to the acidic brine (which is created by the addition of CO 2 , CO 2 -saturated brine). These reactive transport processes are only poorly understood, particularly at the micrometre scale, and importantly how this affects the geomechanical rock properties. We thus imaged a heterogeneous oolitic limestone (Savonnieres limestone) core before and after flooding with brine and CO 2 -saturated brine at representative reservoir conditions (323 K temperature, 10 MPa pore pressure, 5 MPa effective stress) in-situ at high resolutions (3.43 μm and 1.25 μm voxel size) in 3D with an x-ray micro-computed tomograph; and measured the changes in nano-scale mechanical properties induced by acid exposure. Indeed the carbonate rock matrix partially dissolved, and absolute and effective porosity and permeability significantly increased. This dissolution was confined to the original flow channels and inlet points. Importantly, the rock matrix weakened significantly (- 47% in indentation modulus) due to the acid exposure.

Wettability of surfaces remains of paramount importance for understanding various natural and artificial colloidal and interfacial phenomena at various length and time scales. One of the problems discussed in this work is the wettability alteration of a three-phase system comprising high salinity brine as the aqueous phase, Doddington sandstone as porous rock, and decane as the nonaqueous phase liquid. The study utilizes the technique of in situ contact angle measurements of the several 2D projections of the identified 3D oil phase droplets from the 3D images of the saturated sandstone miniature core plugs obtained by X-ray microcomputed tomography (micro-CT). Earlier works that utilize in situ contact angles measurements were carried out for a single plane. The saturated rock samples were scanned at initial saturation conditions and after aging for 21 days. This study at ambient conditions reveals that it is possible to change the initially intermediate water-wet conditions of the sandstone rock surface to a weakly water wetting state on aging by alkanes using induced polarization at the interface. The study adds to the understanding of initial wettability conditions as well as the oil migration process of the paraffinic oil-bearing sandstone reservoirs. Further, it complements the knowledge of the wettability alteration of the rock surface due to chemisorption, usually done by nonrepresentative technique of silanization of rock surface in experimental investigations.