Tag: geology

A Procedure to Parameterize High Permeability Zones in Naturally Fractured Reservoir

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This paper presents a novel-methodology to compensate for the poor characterization of high-permeability structures (excess-K: vugs, karsts and super-K features), and non-fault-related-fractures, in naturally fractured Brazilian Pre-Salt carbonate reservoirs. These heterogeneities are often undetectable in well logs and seismic data, but significantly impact well performance. The methodology aims to enhance the representation of such features within dynamic simulation models, improving reservoir characterization and supporting more reliable data-assimilation and forecasting processes. The methodology involves: (1) upscaling high-fidelity fine-grid models to coarser-grids while preserving dynamic behavior, (2) identifying wells with productivity/injectivity mismatches due to a poor excess-K characterization, (3) applying a data assimilation (DA) process to minimize the mismatch between modeled and measured wells production and injection rates by updating the absolute permeability of the matrix. The novelty of the process is that the permeability field is updated by creating a mask (3D property) built by kriging permeability increments estimated from the well cells with productivity/injectivity issues. Therefore, the DA aims to find the least increments of permeability needed for each well such that when this mask is summed with the matrix permeability field all wells present good productivity/injectivity matching with history data. The methodology was applied to a dual-porosity/dual-permeability (DP/DK) compositional reservoir model. Two distinct well behaviors were observed: (1) wells located within fracture zone (12 of 33) showed good productivity/injectivity alignment with historical data and (2) the remaining 21 wells, located away from fracture zone, exhibited significantly poorer productivity/injectivity. This mismatch was attributed to the absence of excess-K features in the original matrix permeability model (Km-field). The optimization process was applied to these 21 wells. For each well a specific Ki-value was settled, defining input-points for kriging. The resulting kriged permeability correction volume (mask) was summed with the Km-field to generate an updated-permeability model. This process was repeated until all wells presented good productivity/injectivity matching with historical data. The process not only corrected the simulated dynamic responses, but also revealed key spatial permeability patterns that had not been captured in the static model. The results served as feedback to the geologists and enabled iterative improvement of the geological model, supporting a more integrated and realistic characterization. Overall, the results validate the methodology as a robust tool for incorporating unresolved high-permeability features in reservoir simulation and improving the quality of data assimilation. This study introduces an automated, iterative probabilistic data-assimilation framework that directly integrates geostatistical kriging with permeability adjustments for excess-Kstructures. The approach provides bidirectional feedback to geological modeling and allows the generation of realistic ensembles for data assimilation workflows. By combining geo-statistics within an uncertainty reduction scheme, the method addresses key modeling gaps encountered when modelling a Brazilian Pre-Salt carbonate.

Numerical Simulation Study of Relative Permeability Hysteresis in a Fractured Carbonate Reservoir Subjected to Water-Alternating-Gas Injection (WAG-CO2)

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The hysteresis phenomenon in relative permeability curves is an important aspect when modeling WAG- CO2 processes. Although experimentally validated, this phenomenon is often overlooked in numerical studies. Furthermore, the impact of hysteresis on oil recovery is a complex issue, which may hinder or contribute to the sweep efficiency. This work evaluates different hysteresis scenarios for a comprehensive analysis of this phenomenon in a synthetic fractured carbonate field analogous to a pre-salt field in Brazil (UNISIM-II-D). The hysteresis is applied in two different scenarios: (i) in low-permeability porous medium (LK); (ii) also included to a lesser extent in high-permeability layers (LSK). The work initially presents sensitivity analyses based on attributes of the Larsen-Skauge WAG hysteresis model. The results reveal that the impact of hysteresis on oil recovery differ for different production strategies. The sensitivity profile of each hysteresis attribute also differs notably between the two assessed hysteresis scenarios, with the effect being more pronounced in the LSK scenario, even at low attribute values. Then, a nominal optimization of reservoir development and management variables is presented for each hysteresis scenario and for the scenario with no hysteresis. We verified that the application of an optimized solution in a non-corresponding scenario may compromise economic and production indicators. The results demonstrate the importance of incorporating the hysteresis phenomenon into models used in life cycle optimization processes (LCO), as the field should be operated differently when hysteresis is identified as a real phenomenon. Finally, the impact of hysteresis on an ensemble of 197 models under uncertainty was evaluated considering two approaches: (i) hysteresis scenario as uncertainty; (ii) values of the Larsen-Skauge’s hysteresis model as uncertainty. In both cases, the NPV risk curves were similar to the original one, in which hysteresis was not included as uncertainty. However, changes were observed for some production indicators and the impact may be more significant for different cases. The results also revealed that different hysteresis scenarios can impact the NPV and production indicators differently when applied to an ensemble of reservoir scenarios, resulting in either positive or negative trends. In this benchmark, hysteresis in low-permeability porous medium at immiscible conditions tend to cause a slight decrease of oil recovery, while hysteresis in Super-k promoted a better mobility control of gas and water in these layers, favoring the production and economic outcomes. Hence, this numerical study provides an extensive analysis of the effects of different hysteresis scenarios on applications that have not been previously explored, such as hysteresis in high- permeability layers, in reservoir life-cycle optimizations, and in a probabilistic approach.

Numerical Study on the Impact of Advanced Phenomena in a Fractured Carbonate Reservoir Subjected to WAG-CO2 Injection

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Advanced phenomena related to water-alternating-gas (WAG) injection are usually neglected in numerical simulations. This work evaluates the impact of different physical phenomena on field indicators, considering a typical pre-salt carbonate reservoir (UNISIM-II-D-CO, a dual-por dual-perm compositional case) subjected to WAG-CO2 injection. Additionally, the computational cost incurred by each of these phenomena is evaluated, since it represents a great challenge in optimization and probabilistic studies. The following phenomena are evaluated considering a nominal base case: (i) matrix-fracture transfer calculation, (ii) relative permeability hysteresis, (iii) CO2 and CH4 solubilities in aqueous phase, (iv) diffusion, (v) numerical dispersion control models, and (vi) velocity-dependent dispersion. CO2 and CH4 solubilities in the aqueous phase, as well as molecular diffusion, did not have a significant impact on field indicators, but they increased simulation runtime more than two times. Matrix-fracture transfer modeling was the most impactful factor, followed by hysteresis and velocity-dependent dispersion. Therefore, the impact of these phenomena was also investigated in a probabilistic approach, considering an ensemble of 197 geostatistical scenarios under uncertainty. Risk curves revealed that the advanced matrix-fracture transfer models improve sweep efficiency. This effect is mainly due to gravity force which acts as a driving mechanism for the oil moving from the matrix to fractures. The capillary effect, in turn, was small compared to gravity. The impact of dispersion and hysteresis on risk curves were smaller than the effect of matrix-fracture transfer modelling. However, these phenomena are particularly interesting in UNISIM-II-D-CO due to the presence of Super-K facies. Hysteresis, when applied to low and high permeability layers, reduced gas mobility and, consequently, the gas produced, contributing to the NPV for most models under uncertainty. On the other hand, the velocity-dependent dispersion mainly affected fluid flows in the regions adjacent to Super-K layers, promoting better oil recovery. The inclusion of advanced phenomena related to WAG-CO2 injection can hold importance when modeling fractured carbonate fields, like those found in the Pre-Salt in Brazil. Nevertheless, computational costs might make their inclusion impractical in full-field simulation models employed for optimization and probabilistic studies. In such cases, it is recommended to assess low-fidelity models or alternatives to accelerate simulations, focusing mainly on the most impactful phenomena related to WAG-CO2 injection.