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The need for higher oil recoveries and longer production plateaus have led to the large scale implementation of Enhance Oil Recovery mechanisms across carbonate reservoirs in the world, especially in brown fields. The success of these mechanisms relies heavily on the accurate description of geological phenomenon and their characterization in static models. This paper summarizes the challenges of successful development of a mature, highly heterogeneous carbonate reservoir in a brown field in the Middle East with presence of Bitumen in the reservoir intervals, using CO2WAG mechanism. This paper discusses different aspects of Bitumen characterization, beginning with a brief summary of the geological concept behind the preferential Bitumen accumulation within highly cemented intervals using high resolution core & thin section descriptions in the area. The lateral distribution of these intervals was then mapped by integrating core, signatures from logs (reduced porosity), high seismic amplitude signatures in 3D volume and production/injection data from nearby development wells. To capture this phenomenon in the static models, Bitumen was modeled as a discrete property guided by the geological concept. The porosity model includes the impact of Bitumen as the logs capture the degradation. The permeability model was modified by reducing the permeability in cells with Bitumen with a multiplier, since core RCA is subject to cleaning which may result in non-representative measurements. The major findings & conclusions of the project are attributed to the detailed appraisal campaign in this area of the field with focus on identifying and refining presence & distribution of Bitumen using nuclear magnetic resonance logs. MDT data with Vertical interference tests at points above and below the Bitumen confirm no communication. This has impacted the placement of wells within Bitumen area, since CO2WAG mechanism relies on sweep from upward rising CO2 plume which is obstructed by presence of heavy continuous Bitumen accumulations. Improved saturation distribution in models is achieved by using dielectric saturation logs, which results in reduced uncertainty for STOOIP quantification within Bitumen rich regions of the field. An injector-producer pair of Early Production Scheme wells is planned in which will confirm performance with current placement scenarios based on above understanding of Bitumen. The case study identifies and significantly demonstrates the impact of geological phenomenon on the recovery & sweep efficiency of CO2WAG mechanism. Development scenarios must consider the inherent reservoir complexities that are recognized by detailed geological studies, in order to provide representative forecasts that in turn influence the economic viability of the project.
The need for higher oil recoveries and longer production plateaus have led to the large scale implementation of Enhance Oil Recovery mechanisms across carbonate reservoirs in the world, especially in brown fields. The success of these mechanisms relies heavily on the accurate description of geological phenomenon and their characterization in static models. This paper summarizes the challenges of successful development of a mature, highly heterogeneous carbonate reservoir in a brown field in the Middle East with presence of Bitumen in the reservoir intervals, using CO2WAG mechanism. This paper discusses different aspects of Bitumen characterization, beginning with a brief summary of the geological concept behind the preferential Bitumen accumulation within highly cemented intervals using high resolution core & thin section descriptions in the area. The lateral distribution of these intervals was then mapped by integrating core, signatures from logs (reduced porosity), high seismic amplitude signatures in 3D volume and production/injection data from nearby development wells. To capture this phenomenon in the static models, Bitumen was modeled as a discrete property guided by the geological concept. The porosity model includes the impact of Bitumen as the logs capture the degradation. The permeability model was modified by reducing the permeability in cells with Bitumen with a multiplier, since core RCA is subject to cleaning which may result in non-representative measurements. The major findings & conclusions of the project are attributed to the detailed appraisal campaign in this area of the field with focus on identifying and refining presence & distribution of Bitumen using nuclear magnetic resonance logs. MDT data with Vertical interference tests at points above and below the Bitumen confirm no communication. This has impacted the placement of wells within Bitumen area, since CO2WAG mechanism relies on sweep from upward rising CO2 plume which is obstructed by presence of heavy continuous Bitumen accumulations. Improved saturation distribution in models is achieved by using dielectric saturation logs, which results in reduced uncertainty for STOOIP quantification within Bitumen rich regions of the field. An injector-producer pair of Early Production Scheme wells is planned in which will confirm performance with current placement scenarios based on above understanding of Bitumen. The case study identifies and significantly demonstrates the impact of geological phenomenon on the recovery & sweep efficiency of CO2WAG mechanism. Development scenarios must consider the inherent reservoir complexities that are recognized by detailed geological studies, in order to provide representative forecasts that in turn influence the economic viability of the project.
Phase equilibrium calculations require experimental lab data to constrain component properties in an equation of state (EOS) model. These thermodynamics-based models generally perform well when it comes to predicting conventional PVT experiments but often fall short when it comes to predicting gas injection experiments, particularly for CO2 injection. We therefore seek to develop methods that can help provide a good initial estimate of the swelling curve, in cases where laboratory data are not available. Our company PVT database compromises more than 2,200 PVT studies, which enables us to pursue three different avenues for predicting the CO2 swelling curve. The first method relies on a machine-learning algorithm, which takes fluid composition and temperature as input. In general, we find that this solution does not preserve monotonicity of the pressure-dependent properties and it extrapolates poorly outside the parameter space used for training. As an example, it fails to predict the first-contact miscible pressure defined as the maximum pressure on the swelling curve. The second option involved correlating swelling pressure, swelling factor and swelling density as a function of the amount of injected gas. We find that all three curves are well-represented by a parabolic expression and we were able to correlate the coefficients as a function methane content in the reservoir fluid only. The resulting model predicts saturation pressure, swelling factor, and density of the swollen mixtures with an absolute average deviation of 4.8%, 2.3% and 1.7%, respectively, which is an excellent starting point for tuning an EOS model for EOR screening studies until experimental data becomes available. The third strategy involved tuning a separate EOS model to each of the 34 CO2 swelling studies and then attempt to correlate the EOS component properties. We compare the values of the tuned pseudo-component properties against some standard correlations such as Pedersen, Kesler-Lee, Riazi-Daubert and others. We find that the Pedersen correlations for critical pressure, critical temperature and acentric factor provide a more accurate initial guess than the other correlations tested. However, we observed that the tuned solution depended to some extent on the initial guess. We find that for our fluid systems, the default values for the critical volume of the pseudo-components need to be reduced by 15% to better predict the viscosity using the LBC model. Despite the slightly improved property estimation, we did not manage to find a clear trend for the binary interaction coefficient between CO2 and the plus fraction. Therefore, we would recommend predicting the CO2 swelling curve with the set of parabolic correlations.
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