The Hall plot is a proven, useful tool for evaluating performance of injection wells. It was originally developed for single-phase, steady-state, radial flow of liquids. It continues to be used to analyse water-injection wells and has also been modified and applied to the injection of polymer micellar solutions for enhanced oil recovery (EOR). However, published studies into its applicability for gas injection scenarios are very limited. This paper discusses the applicability of, and modifications to, the Hall plot for evaluating injection of gas into a reservoir under specific conditions—particularly immiscible gas injection into a gas cap. Three commonly used expressions of the Darcy equation applied to gas wells exist—the low pressure approximation, the high pressure approximation and the method of real-gas pseudopressures. For this study, a methodology similar to that which was originally used to derive the Hall plot for liquids is applied to these expressions in order to derive modified ‘Hall’ expressions for gas wells, making appropriate assumptions. The validity of the resulting derived expressions was then verified using results from a commercial reservoir simulator. Published correlations were used to evaluate pressure-dependent properties for the plot, where required. Based on the analysis, it was found that at low pressures, using the original expression of the Hall plot introduces a nonlinearity that could be misinterpreted as a change in injectivity. The modified expression for the Hall plot, based on the low-pressure approximation and published correlations, removes this artificial nonlinearity and straightens the plot, greatly improving its diagnostic value. It was also seen that at high-pressures, the attempts to re-derive a Hall plot expression for gas flow lead to an expression of the same form as the original Hall plot. Therefore the original Hall plot can be used without modification as it produces a straight line with no curvature. The method of pseudopressures gives the most comprehensive solution over the entire pressure range as expected, although it is more difficult to evaluate due to the need for numerical integration. The results from this work indicate that modified versions of the Hall plot can be used qualitatively by engineers to identify injectivity problems during injection of gas into a reservoir under specific conditions—immiscible gas injection into a gas cap—as long as the appropriate approximations and correlations are used.
Water-alternating-gas (WAG) flooding has been successfully used as development alternative providing frontal mobility control for better conformance, potential reduction of residual oil saturations to water, particularly when miscibility is achieved, and relative permeability changes as result of the cyclic injection. Forecasting performance of the WAG process often involves the use of numerical simulation models that allow the inclusion of capillary, viscous, gravity forces, compositional and hysteresis onto the frontal movement, recovery and injection requirements. It is not uncommon to encounter models that are not necessarily built to address the specific challenges of the WAG displacement and thus require validation and modifications to improve consistency and predictive power. WAG processes are traditionally characterized through a series of laboratory and field observations, a process that starts with corefloods where injection volumes, sequence and water-gas proportions (among others) are optimized and its results are used to calibrate the necessary parameters to represent the WAG process in the dynamic models by simulating the laboratory experiments. These core-level calibrated parameters are often directly used without modification even though the parameters are unique to the scale at which they were calibrated. Investigation into practical translation and use of these core-level parameters on pilot and full field numerical models is the main objective of this paper. This paper builds on the results of previous work which described a multi-stage upscaling process by introducing a series of 1D, 2D and 3D models of varying resolution ranging from core scale to expected full field resolution. The models are built to represent average well spacing as well as reproduce expected frontal advancement. The high-resolution models are used as reference since they are closest to the core scale and the results of the different numerical resolutions are used to determine upscaling requirements (concentrated on immiscible water-alternating-gas - iWAG) as well as investigate the impact and limitations on the magnitude of the upscaling. A realistic full field model is used to validate the impact of the upscaled iWAG parameters on different model resolutions. Results of the investigation were in line with previous work (Talabi et al. 2019) identifying significant deviations in the oil, water and gas production for horizontal grid resolutions beyond 50ft where numerical dispersion and dilution accounted for an early water arrival and subsequent decrease trapping of the non-wetting phase. Oil recovery was consistently underestimated by 2-8% as the grid resolution increased. The upscaling strategy proposed involves the modification of trapping parameters to account for the numerical dilution effect: increase of non-wetting phase relative permeability reduction factor and three-phase wetting phase relative permeability was sufficient to reproduce the overall fine scale mobility (to overcome dispersion/dilution effects). Acceptable calibrations that allow coarse models to reproduce the fine scale results were obtained on the 1D/2D/3D models. As expected, the magnitude of the WAG parameter changes was process and heterogeneity dependent (Moreno et al. 2011) requiring fine tuning as model complexity increased. While the complexity, heterogeneity and fluid dependence of the WAG process is recognized, a multi-stage upscaling approach as described in this paper, is offers an opportunity to better understand the process drivers and design a practical upscaling strategy suitable to accommodate the full field operation and avoid underprediction of WAG performance.
In recent years, chemical enhanced oil recovery (EOR) application for heavy oil fields has been limited by low oil prices. The use of chemicals, though proven to be effective, can be toxic, expensive, and/or non-biodegradable. Deep Eutectic Solvents (DES) are potentially a much cheaper, greener alternative to conventional surfactants. However, there are very limited studies on the DES application. This study focused on numerical modeling of the effectiveness of a specific DES (Choline Chloride: Glycerol), in improving oil recovery and evaluating the parameters affecting the DES behavior. Data was gathered based on a literature review of the various but limited studies available and used to construct a black oil numerical model representing a heavy core-flooding experiment. The model was calibrated to some of the available published data. The study then used this model to examine different scenarios by comparing the performance of conventional water flooding using formation brine, with the performance of DES injection (after an initial period of brine flooding). The simulations were repeated at multiple temperatures and concentrations. Simulation results tally with the hypothesis and published data which is in favor of oil recovery enhancement with DES injection. In brine flooding cases, the oil recovery factor was in the range of 36-39%, with the high end occurring at a higher temperature. Increasing the DES concentration reduces the interfacial tension (IFT) which further improves oil recovery with the assistance of wettability alteration. Injected DES alters the rock wettability from oil-wet to water-wet thus improving the oil mobility. It was also observed that the oil recovery factor increases significantly with the increase of temperature as this reduces the oil viscosity and in turn, the mobility ratio, given the same formation properties. The highest recovery factor (60-62%) was achieved at the maximum injected concentration although this may not be practical in field application. Based on this, DES performance can be successfully applied as a substitute for current surfactant flooding methods in light of its low-cost, ‘greener’ nature as well as performance as a chemical EOR agent.
The rise in global warming is due to the high emissions of greenhouse gases (GHG) around the world. Carbon dioxide (CO2) gas emissions, a by-product from the petroleum industry, is contributors to climate change. One technology that may help curb CO2 gas emissions is injecting the gas into the subsurface reservoir. In this study, CO2 mineral trapping behaviour and its reactions within a wet basaltic rock containing Olivine mineral are captured and simulated in a full field numerical simulation model. A 2-stage approach was planned to develop the full field numerical model. In the first stage, a single cell model was developed, assessed and matched to the literature experiments with several assumptions considered and applied. Following this, the second stage involved developing a full field model to observe and analyse the distribution and concentration of CO2 during injection, as well as its sequestration as a solid phase (i.e., mineral trapping). The overall volume ratio of injected CO2 versus water was also assessed to ensure enough CO2 were injected into the basalt rock ensuring clear distribution of CO2 in the rock either in dissolved, trapped, or mobile state. In this study, the injected volume covered 4% of the total water volume. Results show that mineralization occurs faster than expected when CO2 gas was introduced to the wet basaltic rock especially near the CO2 injector wellbore. The mineralization speed depends on the reaction rate, modelling (cell) surface area and volume as well as the reaction rate coefficient where it was tuned to match the experimental results. The time required for the CO2 component to travel within the rock was also assessed to give a clear picture of the CO2 distribution where it took 10 years to reach 1000 ft away from the injector wellbore within a 440 ft thick reservoir.
A case study modelling pipeline layout and asset-wide choke optimization in a dry gas field of multiple reservoirs is presented. The methodology utilized an integrated asset model (IAM) and lexicographic optimizer with a neural network accelerator to perform production optimization while considering system constraints on the quality of the produced gas blend as well as the effect of significant differences in reservoir pressure on total asset production. The field comprises several gas reservoirs; some are already developed and in production, and others are in development with more wells to be drilled and brought online later. Production from the different reservoir units is commingled as the units tie into a common surface production network. Based on preliminary simulation studies, the commingled pipeline causes production deferment due to backpressure. It was postulated that a dedicated, high-pressure pipeline would be required to mitigate this. The purpose of this study was to investigate if the cost of the dedicated pipeline could be avoided by selectively choking back high-pressure wells to allow lower-pressure wells to flow and assess the incremental recoverable volume is CO2 content in blended gas was optimized. The first step of the pilot study was to create a representative surface network model that could be coupled to the available subsurface black oil simulation model for two of the fields. A model integration software platform was used for linking the surface to subsurface, and a representative simulation control strategy was input. A custom-built choke optimization logic using an optimizer that honors the CO2 constraints and maximizes gas production up to the asset sales gas plateau target was implemented and triggered every month during the simulation. The optimized simulation generates a gas rate and choke pressure drop schedule per month per well that then can be used to develop a monthly choke set-point schedule. The simulations were run for 12 years. Based on the results, using choke optimization, the production deferment—cumulative production difference between dedicated pipeline and comingled pipeline—can be reduced by up to 80%, making the choke-optimized comingled pipeline case more economic than the equivalent dedicated pipeline case. In addition, cumulative production can be increased by approximately 34% in both dedicated and comingled pipelines while honoring the CO2 production constraint. The results of this study demonstrate the potential benefits of choke optimization in the gas field to both increase production by better field management and offset the need for an expensive dedicated pipeline, allowing the field improve its production potential at minimal cost.
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