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Despite their higher complexity (Juri et al., 2015) and usually more challenging commercial development, naturally fractured reservoirs account for a significant portion of oil and gas reserves worldwide (Sun et al., 2021). Typically, natural fractures tend to enhance the productivity of the wells, yet they also tend to accelerate reservoir depletion, often leading to sub-optimal field production and leaving significant volumes of hydrocarbons behind (Aguilera, 1995). In this work, we propose a specific polymer injection design that can provide the conditions for fracture-matrix counter-current flow to develop in a naturally fractured carbonate reservoir. In turn, this flow could trigger a virtuous cycle where the displacement front is progressively slowed down, increasing the efficiency of the displacement process and the oil recovery. This study focused on the integration of multiple sets of data to characterize karstic and tectonic fractures in a discrete fracture network (DFN) model and its posterior use in a dual medium simulation model to determine polymer flooding optimal spacing and injection strategy in a complex, naturally fractured carbonate system. An innovative and integrated approach combining 3D seismic data, bore-hole imagery (BHI), cores, and production data was applied to characterize and represent karstic features. The applied workflow consisted of (1) identification and manual picking of karstic features on BHI, (2) deterministic picking of karstic features as geobodies on the 3D seismic (enhanced similarity volume), (3) integrated implementation of the karstic features into the geological model using advanced geostatistical methods (Multi-Points Simulation, or MPS), and (4) implementation of resulting enhanced reservoir properties on a fit for purpose high-resolution dynamic model (dual porosity/dual permeability). Multiple simulations were run to evaluate different sensitivities including injection rates, injection strategy, completion approach, and producer-injector pattern spacing. Particularly for the latter, a robust karst/fracture system characterization was critical to propose optimal pattern sizes which aim to simultaneously avoid early polymer breakthrough -in shorter than optimal designs and minimize potential shear thickening degradation effects tied to higher polymer throughput required by excessive producer-injector distancing. In terms of the completion interval, the DFN-derived properties were also strongly conditioning the selection of the injection interval with noticeable effects and contrasting results. Because of the superposed features constituting the total fracture system and their different origins, a field-level comprehension of anisotropy and local intensity of the fractures is critical for selecting both the wells for the injectivity test and the potential area for the pilot in the next stage of the project.

This study consists of an innovative multi-disciplinary approach (combining borehole imagery, core data, 3D seismic and field production) which aims at better characterizing and representing karstic features in a dual porosity/permeability simulation model and improving the associated reservoir model predictions in the context of a carbonated reservoir characterization. The applied methodology can be described as follow: Identification and picking of karstification features on bore-hole imagery (GeologTM software) Deterministic picking of karstic features as geobodies on the 3D seismic (enhanced similarity volume (PaleoscanTM software) Integrated implementation of the karstification features into the geological model using advanced geostastical methods (Multi-Points Simulation, PetrelTM software) Implementation of the resulting enhanced reservoir properties during dynamic simulations and history matching (dual porosity/permeability medium, tNavigatorTM software). After their deposition, carbonate reservoir series are affected by intense karstification during a prolonged period of subaerial exposure. They are consequently marked by widespread erosion; dissolution and collapsing features (e.g., solution cavities, solution-enhanced fractures and brecciated intervals) which were first recognized and picked on the borehole imagery. Typical elongated and dendritical karstic features were then identified through advanced 3D seismic attributes and then deterministically picked as geobodies. This picking was performed using advanced similarity seismic volume, at high resolution, to capture vertical heterogeneities in the karstified interval(s) of the reservoir. Then, Seismic extracted geobodies were implemented as key drivers for reservoir properties into the geological model. Since every brecciated zone on the borehole image could not be captured during the seismic picking (either due to resolution, and/or to low seismic quality zone), an advanced Multi-Points simulation was designed and implemented using the "geobody" property as a "training image" (primary constrain). This method reproduces the characteristics of geobodies, such as trends, orientation, shape, and dimensions. This method filled the resolution gap between seismic image and logs and transferred the multi-scale observations into the geocellular model. The karst-related dynamic properties obtained through this advanced modelling workflow were then refined during history matching and considered as the main driver for variations in well productivity indexes. This tailor-made approach critically impacts redevelopment opportunities that will ultimately safeguard and increase hydrocarbon reserves.

For many CO2-emitting industrial sectors, such as the cement and chemical industry, Carbon, Capture and Storage (CCS) will be necessary to reach any set climate target. CCS on its own is a very cost-intensive technology. Instead of considering CO2 as a waste to be disposed of, we propose to consider CO2 as a resource. The utilisation of CO2 in so-called CO2 Plume Geothermal (CPG) systems generates revenue by extracting geothermal energy, while permanently storing CO2 in the geological subsurface.To the best of our knowledge, this pioneer investigation is the first CCUS simulation feasibility study in Switzerland. Among others, we investigated the concept of injecting and circulating CO2 for geothermal power generation purposes from potential CO2 storage formations (saline reservoirs) in the Western part of the Swiss Molasse Basin ("Muschelkalk" and "Buntsandstein" formation).Old 2D-seismic data indicates a potential anticline structure in proximity of the Eclépens heat anomaly. Essentially, this conceptual study helps assessing it's potential CO2 storage capacity range and will be beneficial for future economical assessments. The interpretation of the intersected 2D seismic profiles reveals an apparent anticline structure that was integrated on a geological model with a footprint of 4.35 × 4.05 km2.For studying the dynamic reservoir behaviour during the CO2 circulation, we considered: (1) the petrophysical rock properties uncertainty range, (2) the injection and physics of a two-phase (CO2 and brine) fluid system, including the relative permeability characterisation, fluid model composition, the residual and solubility CO2 trapping, and (3) the thermophysical properties of resident-formation brine and the injected CO2 gas.Our study represents a first-order estimation of the expected CO2 storage capacity range at a possible anticline structure in two potential Triassic reservoir formations in the Western part of the Swiss Molasse Basin. Additionally, we assessed the effect of different well locations on CO2 injection operations.Our currently still-ongoing study will investigate production rates and resulting well flow regimes in a conceptual CO2 production well for geothermal energy production in the future. Nonetheless, our preliminary results indicate that, under ideal conditions, both reservoirs combined can store more than 8 Mt of CO2 over multiple decades of CCUS operation. From our results, we can clearly identify limiting factors on the overall storage capacity, such as for example the reservoir fluid pressure distribution and well operation constraints.

Characterization of naturally fractured reservoirs is challenging because of variable properties and high heterogeneity. One of these examples is the complex fractured carbonate reservoir of Upper Cretaceous Maastrichtian age present in a field located in onshore of Abu Dhabi. A detailed study was conducted to accurately characterize and model fracture networks occurring in the reservoir, in order to control early water breakthrough problems caused by fracture connections to aquifer and resulting in reduced oil production and bypassed oil issues. The workflow involved a full interpretation of the seismic dataset and fault networks, concluding that faults are short and discontinuous, with frequency increasing with depth. A second step included a fracture network characterization using: Core, Borehole image, 3D seismic and dynamic data. Core description showed that reservoir is dominated by short diagenetic and stylolite-related fractures, with only rare tectonic fractures. Borehole image analysis confirmed core observations and concluded that fracturing is dominated by corridors related to faults, with thicknesses of 50 to 300 ft. No small-scale diffuse fracturing was detected. Seismic attributes were combined into fracture index maps to detect large-scale fractured zones at keys levels. Good relationship was found between the faults and lineaments from seismic and large fracture clusters seen on borehole image data. Dynamic analysis using production, pressure, PLT and well test data showed that production is mainly controlled by matrix. Moderate Kh and productivity enhancement was detected at proximity with corridors (around 100 m), and water production behavior was locally explained by corridors. No evidence for small-scale fracturing flow was found. Finally, a fracture model integrating all fracture characterization results was built and allowed computing equivalent fracture properties (fracture K in x, y, z, fracture porosity and matrix block sizes), in order to optimize new well location and trajectories for increased field production and delayed water breakthrough.