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 CO₂ water-alternating-gas (WAG) injection, which is a successful EORmethod for carbonate reservoirs. The simulations are employed as a basis for generating datadriven 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 affectingWAG 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 CO₂ WAG efficiency. The results highlight the firstorder impact of the fracture network properties and wettability on hydrocarbon recovery and CO₂ 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.

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Water-Alternating-Gas injection could be an efficient way to improve recovery factors in fractured carbonate reservoirs. However, the complex geology of fractured carbonate reservoirs and the complexity of the WAG process itself create uncertainties when predicting the efficiency of WAG. It is hence challenging to identify engineering controls that allow us to optimize recovery during WAG while accounting for geological uncertainties. To overcome this challenge, we use Latin Hypercube and Box-Behnken experimental designs to set up multiple screened simulations of WAG injection in a fractured carbonate reservoir model that contains multiple geological uncertainties. From these simulations we construct surrogate response surfaces using polynomial chaos expansion. The response surface allow us to predict recovery factor, gas cumulative production, water cumulative production and NPV for different geological scenarios and engineering controls. Finally, we run the Non-dominated Sorting Genetic Algorithm-II on the response surface to obtain an optimal engineering design that not only accounts for geological uncertainties but also competing objectives. Our results show that only such a comprehensive simulation approach, which nevertheless can still be carried out on modern desktop PCs, is capably of analysing the complex interactions between geological and physical uncertainties and engineering controls to identify the most suitable WAG implementation.@en

Relative permeabilities show significant dependence on the saturation path during CO₂ enhanced oil recovery (EOR) and storage. This dependence (or hysteresis) is particularly important for water-alternating-gas (WAG) injection, a successful CO₂ 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 CO₂ phase, which impacts the volume of CO₂ stored and the incremental oil recovery. The competition between hysteresis and geological heterogeneity during CO₂ 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 CO₂ 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 CO₂ 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.

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Conventional simulation of fractured carbonate reservoirs is computationally expensive because multi-scale heterogeneities and fracture-matrix transfer must be taken into account. The computational requirement increases exponentially when multiple simulation runs are required for sensitivity analysis and quantification of the uncertainty range. This can be prohibitive, especially for giant carbonate reservoirs. Yet, sensitivity analysis and uncertainty quantification are particularly important to analyse, determine and rank the impact of geological and engineering parameters on the economics and sustainability of different EOR techniques. We use experimental design to set up multiple screened 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 CO2 water-alternating-gas (WAG) injection, which has been shown to be a successful EOR method for carbonate reservoirs. The simulations are used as a basis for generating polynomial response surfaces for prediction of hydrocarbon recovery and net gas utilisation. We compare response surfaces from polynomial regression to response surfaces generated with polynomial chaos expansion (PCE). PCE allows for non-linear mapping of parameter uncertainty to the predicted results. In the current work, the geological parameter uncertainties affecting WAG modelling in fractured carbonates are evaluated. These include end-member fault transmissibility configurations, wettability scenarios, hysteresis models and fracture intensity. Effective fracture permeabilities are computed using discrete fracture networks (DFN) for sparsely distributed regional fractures. The results enable us to adequately explore the parameter space, quantify and rank the interrelated effect uncertain model parameters on CO2 WAG efficiency in fractured carbonate reservoirs. The results highlight the first order impact of fracture intensity, wettability and hysteresis on hydrocarbon recovery and net gas utilisation. Furthermore, reduced order (i.e. proxy) models enable us to calculate quick estimates of the probabilistic uncertainty range and achieve significant computational speed-up compared with the conventional Monte Carlo framework.@en

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.@en

Relative permeabilities show significant dependence on the saturation path during enhanced oil recovery. This dependence (or hysteresis) is particularly important for water-alterating-gas (WAG) injection, a successful EOR method for clastic and carbonate reservoirs. WAG is characterized by an alternating sequence of drainage and imbibition cycles. Hysteresis is hence common and results in trapping of the non-wetting phase, which impacts incremental recovery. The competition of trapping and geological heterogeneity during WAG, particularly in carbonate reservoirs, is not yet fully understood. In this study, we therefore 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 non-wetting phase trapping during miscible and immiscible WAG in heterogeneous carbonate formations. We then compare the impact of trapping on recovery to the impact of heterogeneity in wettability and reservoir structure. We test end-member wettability scenarios and multiple rock types. We also compute effective fracture permeabilities using discrete fracture networks (DEN), ranging from sparsely distributed background fractures to fracture networks where intensity varies with proximity to faults. The results enable us to analyse and compare WAG efficiency in carbonate reservoirs by ranking the impact of physical displacement processes (imbibition, drainage, trapping, miscibility) versus heterogeneity (wettability, faults, fractures, layering) that are typical for carbonate reservoirs. We show that while miscible WAG injection gives better displacement results than immiscible WAG injection or water flooding for this reservoir, recovery efficiency is limited by structurally induced bypassing and flow channelling. This bypassing is magnified if fractures are considered, leading to an earlier breakthrough of injected fluids and ultimate recoveries that are at least 8% lower compared to matrix-only models. We also demonstrate the impact of different hysteresis models and show that when irreversibility of the drainage and imbibition scanning curves during WAG is accounted for, trapping is enhanced and at least a 5% increase in recovery is observed. This modelling approach, therefore, enables us to increase the reliability of WAG simulations by accounting for trapping and its interaction with wettability, miscibility, and geological heterogeneity in fractured carbonate reservoirs.

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A high-resolution three-dimensional (3D) outcrop model of a Jurassic carbonate ramp was used in order to perform a series of detailed and systematic flow simulations. The aim of this study was to test the impact of small- and large-scale geological features on reservoir performance and oil recovery. The digital outcrop model contains a wide range of sedimentological, diagenetic and structural features, including discontinuity surfaces, shoal bodies, mud mounds, oyster bioherms and fractures. Flow simulations are performed for numerical well testing and secondary oil recovery. Numerical well testing enables synthetic but systematic pressure responses to be generated for different geological features observed in the outcrops. This allows us to assess and rank the relative impact of specific geological features on reservoir performance. The outcome documents that, owing to the realistic representation of matrix heterogeneity, most diagenetic and structural features cannot be linked to a unique pressure signature. Instead, reservoir performance is controlled by subseismic faults and oyster bioherms acting as thief zones. Numerical simulations of secondary recovery processes reveal strong channelling of fluid flow into high-permeability layers as the primary control for oil recovery. However, appropriate reservoir-engineering solutions, such as optimizing well placement and injection fluid, can reduce channelling and increase oil recovery.@en

We integrate discrete fracture network (DFN) with discrete fracture and matrix (DFM) models to increase the efficiency and accuracy of static and dynamic calibration in naturally fractured reservoirs. The DFN method provides a framework for generation and modelling of fractured reservoir models and their conditioning to the observed data. The DFM is more accurate for the dynamic modelling in situations where there is significant flow in the matrix. We discuss a workflow where the two methods are combined jointly in a real fractured reservoir.@en

Outcrop analogue studies for complex subsurface reservoirs have become increasingly common because they allow us to integrate reservoir characterisation with reservoir simulation. This enables us to correlate distinct geological features that can be observed in the outcrop but are normally upscaled in dynamic models, to complex flow phenomena present in real reservoirs. Hence we can construct static models that are better calibrated because they contain the key geological structures controlling the flow behaviour and translate them into dynamic models that are upscaled properly. In this study we use a high resolution simulation model of a middle Jurassic carbonate ramp outcrop from the High Atlas Mountains of Morocco, which can be regarded as an analogue for the Arab D formation, to investigate fluid flow processes during enhanced oil recovery (EOR). The outcrop analogue model contains a wide range of sedimentological and structural geological features, including patch reefs, mollusc banks, mud mounds and fractures. Our work aims to improve our understanding of the flow dynamics occurring during secondary and tertiary gas injection in complex carbonate reservoirs. We simulated gas injection as both, miscible and immiscible, where miscibility is determined by the minimum miscibility pressure (MMP) estimated from correlations. We compare continuous gas injection and water alternating gas (WAG) injection and decipher how they are influenced by matrix and fracture heterogeneities. The results show up to 7% incremental recovery by gas injection compared to secondary recovery due to the contact of un-swept zones and improved hydrocarbon displacement. We show how gas channelling along high permeability layers is mitigated by WAG injection and that detailed representation of small- and large-scale geological features such as fractures and high permeability streaks, leads to improved prediction of hydrocarbon recovery. Using this understanding, we optimise recovery by ensuring effective gas utilization, injection strategy and miscibility conditions.@en

Carbonate reservoirs contain a significant portion of the world's proven hydrocarbon reserves but are challenging to produce due to their complex lithologies, structural heterogeneities, and neutral to oil-wet nature. Increasing recovery requires a better understanding of how different recovery processes respond to the heterogeneities inherent to these reservoirs. This will contribute to the design of appropriate engineering solutions which extend the life of mature fields and develop green fields more effectively. We use a high-resolution 3D outcrop model of a Jurassic carbonate ramp in order to perform a series of detailed and systematic flow simulations. The aim is to test the impact of small- and large-scale geological features on reservoir performance and oil recovery. The outcrop analogue model is of excellent quality comprising a wide range of diagenetic and structural features, including discontinuity surfaces, mud mounds, mollusc banks and fractures. Flow simulations are performed for numerical well-testing and secondary oil recovery. Numerical well-testing allows us to generate synthetic but systematic pressure responses for different geological features observed in the outcrops. This allows us to assess and rank the relative impact of specific geological features on reservoir performance. The outcome documents that, due to the high level of matrix heterogeneity, most diagenetic and structural features cannot be linked to a unique pressure signature. Instead, reservoir performance is controlled by sub-seismic faults and mollusc banks acting as thief zones. Numerical simulations of secondary recovery processes reveal strong channelling of fluid flow into high-permeability layers. This is the primary control for oil recovery. However, appropriate reservoir engineering solutions such as optimising well placement and injection fluid can reduce channelling and increase oil recovery.@en