Influence of Rock Wettability on Reservoir-Scale CO2 Geo-Sequestration

The focus of this research is to investigate the influence of rock wettability on CO2 movement through porous media. By performing different multiphase flow reservoir simulations on a hectometre scale, this research investigates the effects of wettability, wettability spatial distribution, and factors affecting wettability on the efficiency of CO2 trapping mechanisms. The results of this research show that reservoir wettability significantly influences CO2 storage efficiency and that water-wet reservoirs are preferable CO2 sinks

Hydrogen underground storage efficiency in a heterogeneous sandstone reservoir

Underground hydrogen storage has been recognized as a key technology for storing enormous amounts of hydrogen, thus aiding in the industrial-scale application of a hydrogen economy. However, underground hydrogen storage is only poorly understood, which leads to high project risk. This research thus examined the effect of caprock availability and hydrogen injection rate on hydrogen recovery factor and hydrogen leakage rate to address some fundamental questions related to underground hydrogen storage. A three dimensional heterogeneous reservoir model was developed, and the impact of caprock and hydrogen injected rate on hydrogen underground storage efficiency were analysed with the model. The results indicate that both caprock and injection rate have an important impact on hydrogen leakage, and the quantities of trapped and recovered hydrogen. It is concluded that higher injection rate increases H2 leakage when caprocks are absent. In addition, lower injection rates and caprock availability increases the amount of recovered hydrogen. This work therefore provided fundamental information regarding underground hydrogen storage project assessment, and supports the decarbonisation of the energy supply chain.Cited as: Mahdi, D. S., Al-Khdheeawi, E. A., Yuan, Y., Zhang, Y., Iglauer, S. Hydrogen underground storage efficiency in a heterogeneous sandstone reservoir. Advances in Geo-Energy Research, 2021, 5(4): 437-443, doi: 10.46690/ager.2021.04.0

The effect of WACO2 ratio on CO2 geo-sequestration efficiency in homogeneous reservoirs

Various factors such as reservoir temperature, wettability, caprock properties, vertical to horizontal permeability ratio, salinity, reservoir heterogeneity, injection well configuration affect the CO2 geo-sequestration efficiency. Furthermore, it was previously investigated that CO2 storage efficiency can be improved by using water alternating CO2 (WACO2) technology. However, the effect of the WACO2 ratio (the ratio of the total amount of injected CO2 to the total amount of injected water) on CO2 storage efficiency has not been addressed adequately. Thus, in this paper, a 3D homogeneous reservoir simulation model has been developed to study the impact of the WACO2 ratio on CO2 mobility and CO2 trapping capacity using five different WACO2 ratios (i.e. 3, 2, 1, 1/2, and 1/3). For all WACO2 ratios tested, 9000 kton (kt) of CO2 were injected during 3 CO2 injection cycles (2 years each) and at an injection rate of 1500 kt per year. Each CO2 injection cycle was followed by a 2 years water injection cycle with injection rates of 500 kt/year, 750 kt/year, 1500 kt/year, 3000 kt/year, and 4500 kt/year for the 3, 2, 1, 1/2, and 1/3 WACO2 ratios, respectively. Then, this 12 years WACO2 injection period was followed by a 100 years post-injection period. Our results clearly indicate, after 100 years post-injection period, that the WACO2 ratio has an important effect on the CO2 migration distance, CO2 mobility and CO2 trapping capacity. The results demonstrate that lower WACO2 ratio leads to reduce the vertical CO2 plume migration and CO2 mobility. Furthermore, low WACO2 ratio enhances the capacities of capillary and solubility trapping mechanisms. Thus, we conclude that WACO2 has a significant impact on the geo-sequestration efficiency and less WACO2 ratios are preferabl

Effect of CO2 flooding on the wettability evolution of sand-stone

Wettability is one of the main parameters controlling CO2 injectivity and the movement of CO2 plume during geological CO2 sequestration. Despite significant research efforts, there is still a high uncertainty associated with the wettability of CO2/brine/rock systems and how they evolve with CO2 exposure. This study, therefore, aims to measure the contact angle of sandstone samples with varying clay content before and after laboratory core flooding at different reservoir pressures, of 10 MPa and 15 MPa, and a temperature of 323 K. The samples’ microstructural changes are also assessed to investigate any potential alteration in the samples’ structure due to carbonated water exposure. The results show that the advancing and receding contact angles increased with the increasing pressure for both the Berea and Bandera Gray samples. Moreover, the results indicate that Bandera Gray sandstone has a higher contact angle. The sandstones also turn slightly more hydrophobic after core flooding, indicating that the sandstones become more CO2-wet after CO2 injection. These results suggest that CO2 flooding leads to an increase in the CO2-wettability of sandstone, and thus an increase in vertical CO2 plume migration and solubility trapping, and a reduction in the residual trapping capacity, especially when extrapolated to more prolonged field-scale injection and exposure times

CO2 saturated brine injected into fractured shale: An X-ray micro-tomography in-situ analysis at reservoir conditions

Fracture morphology and permeability are key factors in enhanced gas recovery (EOR) and Carbon Geo-storage (CCS) in shale gas reservoirs as they determine production and injection rates. However, the exact effect of CO2-saturated (live) brine on shale fracture morphology, and how the permeability changes during live brine injection and exposure is only poorly understood. We thus imaged fractured shale samples before and after live brine injection in-situ at high resolution in 3D via X-ray micro-computed tomography. Clearly, the fractures’ aperture and connectivity increased after live brine injection

Effect of the number of water alternating CO2 injection cycles on CO2 trapping capacity

The CO storage capacity is greatly aected by CO injection scenario – i.e. water alternating CO (WACO ) injection, intermittent injection, and continuous CO injection – and WACO injection strongly improves the CO trapping capacity. However, the impact of the number of WACO injection cycles on CO trapping capacity is not clearly understood. Thus, we developed a 3D reservoir model to simulate WACO injection in deep reservoirs testing dierent numbers of WACO injection cycles (i.e. one, two, and three), and the associated CO trapping capacity and CO plume migration were predicted. For all dierent WACO injection cycle scenarios, 5000 kton of CO and 5000 kton of water were injected at a depth of 2275 m and 2125 m respectively, during a 10-year injection period. Then, a 100-year CO storage period was simulated. Our simulation results clearly showed, after 100 years of storage, that the number of WACO cycles aected the vertical CO leakage and the capacity of trapped CO . The results showed that increasing the number of WACO cycles decreased the vertical CO leakage. Furthermore, a higher number of WACO cycles increased residual trapping, and reduced solubility trapping. Thus, the number of WACO cycles signicantly aected CO storage eciency, and higher numbers of WACO cycles improved CO storage capacity

Apparent Viscosity Prediction of Water-Based Muds Using Empirical Correlation and an Artificial Neural Network

Apparent viscosity is of one of the main rheological properties of drilling fluid. Monitoring apparent viscosity during drilling operations is very important to prevent various drilling problems and improve well cleaning efficiency. Apparent viscosity can be measured in the laboratory using rheometer or viscometer devices. However, this laboratory measurement is a time-consuming operation. Thus, in this paper, we have developed a new empirical correlation and a new artificial neural network model to predict the apparent viscosity of drilling fluid as a function of two simple and fast measurements of drilling mud (i.e., March funnel viscosity and mud density). 142 experimental measurements for different drilling mud samples have been used to develop the new correlation. The calculated apparent viscosity from the developed correlation and neural network model has been compared with the measured apparent viscosity from the laboratory. The results show that the developed correlation and neural network model predict the apparent viscosity with very good accuracy. The new correlation and neural network models predict the apparent viscosity with a correlation coefficient (R) of 98.8% and 98.1% and an average absolute error (AAE) of 8.6% and 10.9%, respectively, compared to the R of 89.2% and AAE of 20.3% if the literature correlations are used. Thus, we conclude that the newly developed correlation and artificial neural network (ANN) models are preferable to predict the apparent viscosity of drilling fluid