Tag: geologist

Estimating Rock Typing in Uncored Wells Using Machine Learning Techniques for Brazilian Pre-Salt Carbonate Reservoir

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Accurate rock typing in uncored wells is essential for enhancing reservoir models, particularly in complex geological formations like the Brazilian pre-salt carbonate reservoirs. This study explores the application of machine learning (ML) techniques to estimate rock types in uncored wells. The research leveraged core data from 11 cored wells to calculate the Rock Quality Index (RQI) and Flow Zone Indicator (FZI), identifying 14 distinct rock types through the Discrete Rock Typing (DRT) method, along with well log data such as gamma ray, density, neutron, permeability, and porosity. Various machine learning models, including Support Vector Machine (SVM), K-Nearest Neighbors (KNN), Decision Tree, Gradient Boosting, Naive Bayes, XGBoost, and Random Forest were tested, where XGBoost achieved the highest accuracy of 73.3%. Applying XGBoost to all wells resulted in accuracy ranging from 0.6 to 0.91 and the model was subsequently used to estimate rock types in over 20 uncored wells to generate reservoir simulation models. This study highlights the efficacy of machine learning (particularly XGBoost) in addressing reservoir complexities and offering significant improvements in the understanding and development of carbonate reservoirs.

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.

Integrated Multi-Scale Pore Characterization of Carbonate Rocks in the Barra Velha Formation, Santos Basin, Brazil

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Carbonate rocks feature heterogeneous porous systems that span multiple scales, from pore level to the reservoir scale. The complexity and diversity of carbonate reservoirs demand a consistent approach to their characterization. The efficient integration of multiscale imaging data and petrophysical data is increasingly important to address the challenges associated with these complex carbonate reservoirs. A crucial step in overcoming these scale gaps in reservoir modeling and simulation involves enhancing the characterization of reservoir flow units and their associations with geological and petrophysical heterogeneities at varying scales. In this study, we focus on the classification of pore types using digital rock analysis and petrophysical evaluation of pre-salt lacustrine carbonates from the Barra Velha Formation (BVF) in the Santos Basin using computerized tomography (CT), core samples description, and petrography. Eight types of pores were identified at the core scale: interparticle, stratiform-vuggy, growth framework, vuggy, vuggy-fracture, fracture, interclast, and intraclast. The distribution and characteristics of these pore types were analyzed at different scales, including thin-sections and micro-CT, and nuclear magnetic resonance (NMR), which highlights the diversity in the porous system and the impact of different pore types on porosity and permeability. NMR analyses illustrated the pore size heterogeneity to provide distinction between tight and porous samples. Hydraulic rock units (HRUs) were defined based on flow zone indicator (FZI) using the probability plot approach. Seven HRUs were defined: HRU1 and HRU2 represent samples with the highest FZI and rock quality index (RQI) values, whereas HRU3 and HRU4 denote intermediate values. HRU5, HRU6, and HRU7 represent units with the lowest values. HRU1 and HRU2 were predominantly associated with vuggy, growth framework, and interparticle porosities, which are often enhanced by dissolution processes. Conversely, HRUs with reduced reservoir qualities (5, 6, and 7), characterized by the lowest permeability values, are more prevalent in intervals with higher silicification and silica and dolomite cementation, presenting a variety of pore types at a macroscale. The integration of multiscale imaging techniques and petrophysical data underscores the complexity of pore systems, providing crucial insights into their reservoir characteristics.

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.

Comparing WAG-CO 2 injection with continuous water and gas injection in separate wells for the development and management of a CO2-rich light oil fractured carbonate reservoir subject to full gas recycling

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Many projects in the Brazilian pre-salt assume the use of water alternating gas (WAG-CO2) injection as an ecologically safe carbon storage strategy, with improved hydrocarbon recovery. However, studies that compare these advantages with a simpler management plan are not common. The objective of this work is to compare WAG-CO2 injection with continuous injection of water and gas (CIWG) rich in CO2 in separate wells for the development and management of a light-oil fractured carbonate reservoir subject to full gas recycling. We employed the UNISIM-II benchmark model, a naturally fractured carbonate reservoir with Brazilian pre-salt characteristics, which enables an application in controlled environment where the reference response is known (UNISIM-II-R). We used a model-based decision analysis for production strategy selection, hierarchical optimization of the decision variables and algorithms to maximize the objective function. Representative models (RM) are selected from the ensemble of models and used to incorporate the effects of geological, reservoir, and operational uncertainties into the optimization process. The net present value is the objective function during the nominal optimization of candidate strategies of each RM and the expected monetary value and risk analysis are considered to select the final production strategy considering uncertainties. The risk analysis was quantified based on downside risk and upside potential relation to a benchmark return. We optimized two alternative development plans (one considering WAG-CO2 injection and the other continuous injection of water and gas in separate wells) and compared their performance indicators and decision variables, including design variables (number, type and placement of well, and size of production facilities) and life-cycle control rules (management of equipment over time). We then applied a cross-simulation, where the best strategy optimized for one recovery method was applied to the other and the injection strategy was optimized again. We were therefore able to assess the need to pre-define the recovery method before defining design variables to validate the flexibility of each strategy for possible future changes in the recovery mechanism. Finally, we repeated the study for different reservoir scenarios to compare the alternatives considering typical uncertainties of the Brazilian pre-salt and validated the final strategies in the reference model to quantify the real value in decision making. The strategies reached a full gas recycling in both recovery methods and allowed a comparison of their advantages and disadvantages. The operations of WAG-CO2 injection can be more complex and the equipment more expensive. The novelty of this work is the consideration of continuous injection of water and gas in separate wells as a simpler alternative to the development and management of pre-salt oil fields, since this method may also meet operators’ and environmental demands, bearing simpler operating challenges and promoting good recovery and profitability.