• Energy Research

Geothermal energy has a high potential to contribute to a more sustainable energy system if the associated economic risks can be overcome in the design process. The development planning of deep geothermal reservoirs (over 1000 m depth) relies on computer models to forecast and then optimize system design. Optimization is easy where all the objective's (e.g. NPV) optimization parameters and, most importantly, the geology are considered as known, but this is almost always not the case. Where the complex engineering design (e.g. well placement) meets significant geological uncertainty every development option should be tested using an expensive simulation against the range of geological possibilities. The impracticality of simulating so many models results in a limited exploration of geological uncertainties and development options. Consequently, the risk of improper system design cannot be properly assessed. This paper presents an approach to understand the trade-offs in maximizing heat extraction while minimizing energy usage in re-injection for a new geothermal reservoir development while considering the uncertainty from 18 different geological models. Our approach is computationally feasible because we apply multi-objective particle swarm optimization (MOPSO), to an ensemble of response surface models, built using Gaussian process regression (GPR), for each and every geological scenario. MOPSO explores the trade-off surface for the competing objectives using the mean reservoir responses (covering the geological uncertainty). Our results highlight the impact of geological uncertainty on the optimal well placement and show the need to consider geological uncertainties adequately in optimization. The work demonstrates the shortcomings of using only one geological model of a geothermal reservoir and/or a single objective in optimization. We additionally demonstrate the practicalities of using response surface models in this way for geothermal systems. We anticipate that our work raises awareness for the scope of optimization of geothermal reservoir design under geological uncertainty.

Conventional simulation of fractured carbonate reservoirs is computationally expensive because of the multiscale heterogeneities and fracture–matrix transfer mechanisms that must be taken into account using numerical transfer functions and/or detailed models with a large number of simulation grid cells. The computational requirement increases significantly when multiple simulation runs are required for sensitivity analysis, uncertainty quantification and optimization. This can be prohibitive, especially for giant carbonate reservoirs. Yet, sensitivity analysis, uncertainty quantification and optimization are particularly important to analyse, determine and rank the impact of geological and engineering parameters on the economics and sustainability of different Enhanced Oil Recovery (EOR) techniques. We use experimental design to set up multiple simulations of a high-resolution model of a Jurassic carbonate ramp, which is an analogue for the highly prolific reservoirs of the Arab D Formation in Qatar. We consider CO 2 water-alternating-gas (WAG) injection, which is a successful EOR method for carbonate reservoirs. The simulations are employed as a basis for generating data-driven surrogate models using polynomial regression and polynomial chaos expansion. Furthermore, the surrogates are validated by comparing surrogate predictions with results from numerical simulation and estimating goodness-of-fit measures. In the current work, parameter uncertainties affecting WAG modelling in fractured carbonates are evaluated, including fracture network properties, wettability and fault transmissibility. The results enable us to adequately explore the parameter space, and to quantify and rank the interrelated effect of uncertain model parameters on CO 2 WAG efficiency. The results highlight the first-order impact of the fracture network properties and wettability on hydrocarbon recovery and CO 2 utilization during WAG injection. In addition, the surrogate models enable us to calculate quick estimates of probabilistic uncertainty and to rapidly optimize WAG injection, while achieving significant computational speed-up compared with the conventional simulation framework.

Abstract Relative permeabilities show significant dependence on the saturation path during CO 2 enhanced oil recovery (EOR) and storage. This dependence (or hysteresis) is particularly important for water-alternating-gas (WAG) injection, a successful CO 2 EOR and storage method for clastic and carbonate reservoirs. WAG injection is characterized by an alternating sequence of drainage and imbibition cycles. Hysteresis is hence common and results in residual trapping of the CO 2 phase, which impacts the volume of CO 2 stored and the incremental oil recovery. The competition between hysteresis and geological heterogeneity during CO 2 EOR and storage, particularly in carbonate reservoirs, is not yet fully understood. In this study, we use a high-resolution simulation model of a Jurassic Carbonate ramp, which is an analogue for the highly prolific reservoirs of the Arab D formation in Qatar, to investigate the impact of hysteresis during CO 2 EOR and storage in heterogeneous carbonate formations. We then compare the impact of residual trapping (due to hysteresis) on recovery to the impact of heterogeneity in wettability and reservoir structure. End-member wettability scenarios and multiple wettability distribution approaches are tested, while, effective fracture permeabilities are computed using discrete fracture networks (DFN), ranging from sparsely distributed background fractures to fracture networks where intensity varies with proximity to faults. The results enable us to analyze the efficiency of oil recovery and CO 2 sequestration in carbonate reservoirs by comparing the impact of physical displacement processes (e.g., imbibition, drainage, residual trapping) and heterogeneous rock properties (e.g., wettability, faults, fractures, layering) that are typical in carbonate reservoirs. We show that although the fracture network properties have the greatest impact on the fluid flow, the effect of wettability and hysteresis is nontrivial. Our results emphasize the need for wettability to be accurately measured and appropriately distributed in a reservoir simulation model. Similarly, our results indicate that hysteresis effects in cyclic displacement processes must be accounted for in detail to ensure that simulation models give accurate predictions.

Abstract Foam displacement has been employed in several field pilots which report improvement in mobility control, sweep efficiency, delayed gas breakthrough and EOR. However, foam behavior in highly heterogeneous porous media in general and fractured reservoir in particular is not well understood. Effective application of foam for enhanced oil recovery requires a good understanding of physical displacement processes (e.g. adsorption, foam generation, foam decay) at the laboratory and field scale. This is particularly important for the more complex fractured carbonate reservoirs which host over half of the world's remaining conventional oil reserves. We investigate the effect of foam displacement in fractured carbonate reservoirs using numerical simulations tuned to experimental data to compare recovery for different injection strategies at different scales. In the experiments, high quality foam was generated by the injection of surfactant solution and N2 gas either in-situ or prior to injection. A mechanistic Lamella Density model was used to simulate core-scale laboratory experiments and history match the unknown foam parameters. We applied our understanding of foam displacement processes at the core scale to a reservoir model at the inter-well scale where additional heterogeneities were encountered. For this model we used a cross section of highly heterogeneous simulation model of a middle Jurassic carbonate ramp that is an analogue to the Arab D formation in Qatar. We used this model to test the effect of foam injection for different injection mechanisms, analyze the displacement processes, and compare the overall sweep and recovery. Foam injection showed very promising results by diverting the flow from the high permeability fractures to the matrix, allowing for a better sweep efficiency that lead to a noticeable increase in differential pressure. Pre-formed foam yielded a higher recovery (around 78% of OOIP) compared to the in-situ generated foam in the core samples. This might be due to the smooth nature of the fractures leading to fewer snap off sites for foam generation. Varying the foam injection strategies (i.e. pre-formed foam, co-injection, and SAG) resulted in at least a 12% change in recovery compared to conventional water flooding and water-alternating gas injection. Foam quality, foam stability and injection mechanism were all factors that controlled sweep efficiency. Our results illustrate how the laboratory-scale displacement mechanisms could operate on a larger (i.e. inter-well) scale where additional heterogeneities are encountered and the ratio of viscous to capillary and gravity forces changes. Our simulations also demonstrate that uncertainties in parameterizing foam models using experimental data from core floods translate into considerable uncertainties for predicting recovery at the field-scale. Still, foam can be an effective agent to increase oil recovery in fractured carbonate reservoirs by improving sweep efficiency and reducing gravity override.

Abstract When CO2 is injected into an aquifer, the injected CO2 is generally colder than the reservoir rock; this results in thermal gradients along the flow path. The temperature variation has an impact on CO2 solubility and the kinetics of any mineral reactions. Core flood experiments and associated reactive transport simulations were conducted to analyse thermal effects during CO2 injection in a dolomitic limestone aquifer and to quantify how CO2 solubility and mineral reactivity are affected. The experiments were conducted by injecting acidified brine into an Edwards Limestone core sample. A back pressure of 400 psi and injection rates of 30 mL/hr and 300 mL/hr were used. A range of temperatures from 21 °C to 70 °C were examined. Changes in the outlet fluid composition and changes in porosity and permeability were analysed. A compositional simulation model was used to further analyse the experiments. The simulations were history-matched to the experimental data by changing the reactive surface area and the kinetic rate parameter. The calibrated model was then used to test the sensitivity to CO2 injection rate and temperature. The impact of temperature on CO2-induced mineral reactions was observed from changes in mineral volume, porosity and permeability. The reaction rate constants estimated from the outlet solution concentrations are much lower than existing data for individual minerals. The estimated specific surface areas for carbonate minerals are in reasonable agreement with published values. The numerical investigations showed that at the lower temperatures, despite the reaction rates being slower, the solubility of the minerals was higher, and so as a result of these competing effects, moderately elevated calcium and magnesium concentrations were observed in the effluent. At higher temperatures, the solubilities of the minerals were lower, but now the reactions rates were higher, so similar effluent concentrations could be achieved. However, at higher flow rates, characterized by a lower Damköhler number, the residence times were shorter, and so lower effluent concentrations were observed. Additionally, the solubilities of calcite and dolomite varied to different extents with temperature, and so the calcium to magnesium molar ratio in the effluent brine increased with increasing temperature. The change in mineral composition during CO2 injection varies between the near well zone and the deeper reservoir. Near the well where the temperatures will be lower, solubilities are elevated, but the kinetic reaction rates and residence times will be lower, somewhat limiting dissolution. Deeper in the aquifer the solubilities will be reduced and residence times will be longer, enabling an equilibrium to be established. Modelling is thus required to connect these flow regimes.

Subsurface porous rocks have the potential to store large volumes of hydrogen (H$_2$) required for transitioning towards a H$_2$-based energy future. Understanding the flow and trapping behavior of H$_2$ in subsurface storage systems, which is influenced by pore-scale heterogeneities inherent to subsurface rocks, is crucial to reliably evaluate the storage efficiency of a geological formation. In this work, we performed 3D X-ray imaging and flow experiments to investigate the impact of pore-scale heterogeneity on H$_2$ distribution after its cyclic injection (drainage) and withdrawal (imbibition) from a layered rock sample, characterized by varying pore and throat sizes. Our findings reveal that even subtle variations in rock structure and properties significantly influence H$_2$ displacement and storage efficiency. During drainage, H$_2$ follows a path consisting of large pores and throats, bypassing the majority of the low permeability rock layer consisting of smaller pores and throats. This bypassing substantially reduces the H$_2$ storage capacity. Moreover, due to the varying pore and throat sizes in the layered sample, depending on the experimental flow strategy, we observe a higher H$_2$ saturation after imbibition compared to drainage, which is counterintuitive and opposite to that observed in homogeneous rocks. These findings emphasize that small-scale rock heterogeneity, which is often unaccounted for in reservoir-scale models, can play a vital role in the displacement and trapping of H$_2$ in subsurface porous media.

Abstract We investigate how efficiently oil can be recovered from a carbonate rock during surfactant based enhanced oil recovery (EOR) at the core-scale, particularly when chemical processes change wettability, and analyse how geological heterogeneities, observed at the next larger scale (centimetre to decimetre) impacts the effectiveness of surfactant-based EOR at the inter-well scale. To quantify how heterogeneity across scales impacts surfactant flooding, we combine laboratory experiments with simulation studies at the core- and inter-well scale. We first analysed a series of surfactant imbibition experiments at different surfactant concentrations (from 0 to 3 wt. %) using reservoir cores from the Wakamuk field, a carbonate reservoir in Indonesia. We then built a 3D simulation model of the laboratory experiment and matched the experimental data to identify the key physical mechanisms (e.g., reduction in interfacial tension (IFT) and wettability alteration) that lead to increased oil recovery. Next, we parametrised the surfactant models using assisted history-matching methods to calibrate the relative permeability and capillary pressure curves as a function of surfactant concentration. These models were then deployed in high-resolution simulations at the inter-well scale. These simulations captured the small-scale geological heterogeneities that are typical for a carbonate reservoir system, e.g., the Shuaiba formation in the Middle East, but are not resolved in field-scale models. Our core-scale simulations demonstrate a change from co- to counter-current flow in the laboratory experiments and indicate that the resulting increase in oil recovery is due to a combination of IFT reduction, wettability alteration from oil- to water-wet, and capillary pressure restoration; these processes need to be captured adequately at the inter-well scale model. The increase in surfactant concentration above the critical micelle concentration (CMC) (i.e., from 1 to 3 wt. %) triggered the capillary pressure restoration and dominated recovery at the early-time. The changes in relative permeability and capillary curves during the surfactant floods were best modelled using a concentration-based interpolation. There is uncertainty when calibrating surfactant models using laboratory experiments. A key question hence is if geological heterogeneity at the inter-well scale masks these uncertainties. Results from our high-resolution simulations show that large-scale heterogeneity impacts recovery predictions, but it is the coarsening of the grid, not the upscaling of permeability, that dominates the error in field-scale recovery predictions during surfactant based EOR. Indeed, the error arising from numerical dispersion during grid coarsening can be as large as the error arising when selecting an inaccurately configured surfactant model due to the lack of quality experimental data. Hence appropriate grid refinement, possibly using adaptive grid refinement, needs to be considered when setting up a surfactant based EOR simulation, along with the appropriate configuration of the surfactant model itself.

AbstractThermohaline convection of subsurface fluids strongly influences heat and mass fluxes within the Earth's crust. The most effective hydrothermal systems develop in the vicinity of magmatic activity and can be important for geothermal energy production and ore formation. As most parts of these systems are inaccessible to direct observations, numerical simulations are necessary to understand and characterize fluid flow. Here, we present a new numerical scheme for thermohaline convection based on the control volume finite element method (CVFEM), allowing for unstructured meshes, the representation of sharp thermal and solute fronts in advection‐dominated systems and phase separation of variably miscible, compressible fluids. The model is an implementation of the Complex Systems Modelling Platform CSMP++ and includes an accurate thermodynamic representation of strongly nonlinear fluid properties of salt water for magmatic‐hydrothermal conditions (up to 1000°C, 500 MPa and 100 wt% NaCl). The method ensures that all fluid properties are taken as calculated on the respective node using a fully upstream‐weighted approach, which greatly increases the stability of the numerical scheme. We compare results from our model with two well‐established codes, HYDROTHERM and TOUGH2, by conducting benchmarks of different complexity and find good to excellent agreement in the temporal and spatial evolution of the hydrothermal systems. In a simulation with high‐temperature, high‐salinity conditions currently outside of the range of both HYDROTHERM and TOUGH2, we show the significance of the formation of a solid halite phase, which introduces heterogeneity. Results suggest that salt added by magmatic degassing is not easily vented or accommodated within the crust and can result in dynamic, complex hydrologies.