• 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 Carbon dioxide geo-sequestration (CGS) into sediments in the form of (gas) hydrates is one proposed method for reducing anthropogenic carbon dioxide emissions to the atmosphere and, thus reducing global warming and climate change. However, there is a serious lack of understanding of how such CO2 hydrate forms and exists in sediments. We thus imaged CO2 hydrate distribution in sandstone, and investigated the hydrate morphology and cluster characteristics via x-ray micro-computed tomography in 3D in-situ. A substantial amount of gas hydrate (∼17% saturation) was observed, and the stochastically distributed hydrate clusters followed power-law relations with respect to their size distributions and surface area-volume relationships. The layer-like hydrate configuration is expected to reduce CO2 mobility in the reservoir, and the smaller than expected hydrate surface-area/volume ratio will reduce methane production and CO2 storage capacities. These findings will aid large-scale implementation of industrial CGS projects via the hydrate route.

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.

Abstract CO2 storage refers to the methods employed to inject CO2 in depleted oil and gas reservoirs and deep saline aquifers for long term storage of CO2 with the objective to reduce the anthropogenic CO2 emissions. Wettability and interfacial tension are two important multiphase parameters which are used to characterize the flow behavior of CO2 in reservoirs. Numerous studies have reported wettability data of CO2-brine systems on various rock forming minerals as function of pressure, temperature and salinity. However, the associated trends have not been physically well-understood and require considerable attention which is objective of our present work. In this work, we apply Neumann's equation of state method to our measured contact angle data for CO2-brine-mica systems and contact angle data of CO2-brine-quartz from Sarmadivaleh et al., 2015. Our results indicate that for mica, solid-CO2 interfacial tension decrease with pressure and salinity and increase with temperature. Moreover, solid-liquid interfacial tension decrease with temperature and decrease with salinity. For quartz, although the solid-CO2 interfacial tension decrease with pressure and increase with temperature, yet solid-liquid interfacial tension increase with temperature which explains the increase in contact angle with temperature for quartz. Overall, we find that results are in accordance with wettability data as function of pressure, temperature and salinity. We thus conclude that hotter reservoirs with lower injection pressure and lower brine salinities exhibit relatively better water wetting state and hence better seal capacity leading to higher CO2 storage potential. We also conclude that solid surface energy approach adequately explains the dependency of wettability on pressure, temperature and salinity.

Abstract Nanofluids are proven to be efficient agents for wettability alteration in subsurface applications including enhanced oil recovery (EOR). Nanofluids can also be used for CO 2 -storage applications where the CO 2 -wet rocks can be rendered strongly water-wet, however no attention has been given to this aspect in the past. Thus in this work we presents contact angle (θ) measurements for CO 2 /brine/calcite system as function of pressure (0.1 MPa, 5 MPa, 10 MPa, 15 MPa, and 20 MPa), temperature (23 °C, 50 °C and 70 °C), and salinity (0, 5, 10, 15, and 20% NaCl) before and after nano-treatment to address the wettability alteration efficiency. Moreover, the effect of treatment pressure and temperature, treatment fluid concentration (SiO 2 wt%) and the period of nano-treatment on the wettability of calcite is examined. We find that nano-treatment alters the wettability significantly i.e. intermediate-wet calcite turns strongly water-wet after treatment (e.g. at 20 MPa and 50 °C, θ = 64° for intermediate-wet calcite, and θ = 28° for nano-treated calcite). Consequently, pre-injection of nanofluids will significantly enhanced the storage potential. It was also found that the permanent shift in wettability after nano-treatment is a function of treatment conditions including temperature, pressure, and treatment duration time and that surfaces treated under high pressure and low temperature yield better wettability alteration efficiency. We point out that the change in wettability is attributed to the changes in surface properties of the nano-treated sample. The results of the study thus depict that nanoparticles can significantly enhance storage potential and de-risk storage projects.

Abstract The propane pre-cooling cycle has been widely used in most LNG plants as the first cooling cycle in the natural gas liquefaction process. As LNG plants consume high amounts of energy, enhancements in the process design and plant operation will minimize the overall energy consumption of the plant. The aim of this study is to enhance the process efficiency of a three stage propane pre-cooling cycle of the Cascade LNG process for the large-scale LNG train by determining the optimal operating conditions of the propane evaporator that will minimize the overall energy consumption. Energy and exergy analysis methods are adopted to evaluate the process efficiency of the propane pre-cooling cycle. Six case studies were presented to determine the optimal operating conditions of the propane evaporator that gives maximum energy reduction. The propane pre-cooling cycle is modelled and simulated using Aspen HYSYS with detailed thermodynamic information obtained to calculate the exergy loss. The results of the energy and exergy analysis indicate that Case 6 gives the highest coefficient of performance (COP) and the maximum exergy efficiency compared to the baseline case, which are 15.51% and 18.76% respectively. The results indicate that by reducing the cooling duty at the intermediate stages of propane evaporator about 13.5% energy saving can be achieved compared to the baseline case.

Abstract Limestone reservoirs are considered as potential candidates for CO 2 geo-sequestration. In order to predict structural and residual trapping capacities of CO 2 and containment security in carbonates, the wettability of the CO 2 /brine/rock systems plays a vital role. Calcite is the main component in limestone and thus commonly used to characterize carbonate wettability using direct contact angle measurements. Previously, several studies determined wettability of calcite/CO 2 /brine systems, but the data clearly lacks in terms of (a) wettability characterization for a wide range of operating conditions, and (b) published data reports contradicting results with measured wettability ranging from strongly water-wet to weakly CO 2 -wet. Thus, to reduce the uncertainty in the reported measurements, we conducted an experimental study to measure advancing and receding water contact angles for calcite/CO 2 /brine systems as a function of pressure (0.1–20 MPa), temperature (308–343 K) and salinity (0 wt% NaCl – 20 wt% NaCl). The results indicate that calcite is strongly water-wet at ambient conditions and with the increase in pressure the surface gradually loses its water-wetness. At high pressure storage conditions (20 MPa and 308 K), calcite surface turned weakly CO 2 -wet implying that an upwards directed suction force will be created and consequently leakage may occur. Moreover, with the increase in temperature contact angle decreased implying that carbonates turn more water-wet at higher temperatures. Furthermore, contact angle increased with salinity. By comparing our results with published data, we point out that apart from pressure, temperature and salinity, the surface cleaning methods and surface roughness and nature of the sample itself can be possible sources of ambiguity in literature data. We conclude that high temperature and low salinity carbonate formations with lower injection pressures are more suitable for safe CO 2 storage.

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.