The WAG (water-alternating-gas) recovery process is a well-established process for enhanced oil recovery with several successful field applications. This process is evaluated for potential application in a giant, offshore Abu Dhabi field. This paper describes an evaluation approach of the WAG process application to the subject field. Many separate reservoir simulation models were created to evaluate various aspects of the WAG recovery process. The models addressed WAG operating parameters such as implementation timing, and the effect of WAG parameters (WAG ratio, cycle length). The models were also used to estimate the rate and recovery impact of WAG implementation using different injectants (off-site available hydrocarbon gas, associated gas, enriched gas). The evaluation process for the giant field started with a small 3D sector model derived from a full-field model of the most significant reservoir unit. This model was extensively used to test the operational parameters. The findings were then tested with larger-scale models for full-field evaluations. Finally, grid sensitivity studies were done using 2D cross-sectional models to calibrate the recovery results from the coarser gridded full-field models. Results show that WAG incremental recovery over the waterflood recovery for the situations studied is about 7 to 8% OOIP (original-oil-in-place). A WAG ratio of 4:1 appears to be optimal. Incremental WAG recovery is insensitive to cycle lengths and timing of WAG implementation. Miscible injectants provide higher recoveries than immiscible gas injection. Model derived recovery benefits were sensitive to the grid size with as much as twice the likely benefit shown with a coarser grid.
Flank areas pose a particular field development challenge in giant fields with low dip where the transition zone is spread over a large area. Successful development of flank areas depends on accurate reservoir characterization, in particular, water saturation distribution in addition to the optimal placement of wells, both areally and vertically. In relatively thin reservoirs, horizontal wells are generally preferred to increase reservoir contact using lower well counts. Proper spacing and vertical placement of horizontal wells are, however, critical. Well spacing is closely linked to oil recovery, pressure support, and sweep efficiency. Similarly, placement of horizontal wells in the right layer is vital for maximum vertical sweep. In order to test initial concept in the field, two existing producers were converted into injectors and pressures were monitored at the offset producers. Surveillance showed that the injectors were able to support producers 1 km away. This paper describes the process of arriving at the optimal well placement for maximizing oil recovery in the flank areas. This study is applicable to giant oil fields with large flank areas which pose significant development challenges.
Streamlines have been acknowledged as a powerful tool for modeling and optimizing waterfloods in oil reservoirs. Streamlines provide visualization of reservoir fluid flow and a unique way to conceptualize and quantify injector-producer well connectivity. Well allocation factors (WAFs) between injectors and producers as well as injection efficiency can be calculated and used to optimize water injection and reduce injection water cycling while focusing on maximizing oil recovery. The objective of this study was to develop a methodology, tool, and workflow for optimizing pattern waterflood management and to demonstrate application in a giant offshore carbonate reservoir. This methodology utilizes historymatched simulation models to generate streamlines from the pressure field and fluxes computed by a finite-difference reservoir simulator, EM power . A finite-difference simulator is more rigorous than streamline simulators in terms of its ability to model complex fluid flow, and therefore, provides a more realistic solution. The streamlines thus obtained take into account the detailed geology, well locations, phase behavior, and flow behavior of the history-matched models. This methodology utilizes the concept of pair "injection efficiency" (IE) and pair "voidage replacement ratio" (VRR) which was necessary for the subject giant oil field and is equally applicable to other fields.The optimization process is started by generating streamlines and associated WAFs at the current time using the simulation model. The injection efficiency is calculated and injector-producer well pairs are identified with high and low IE. New producer rates are then calculated by increasing producer rates in high IE well pairs and decreasing rates in low IE well pairs based on a weight factor. The injector rates are then calculated by applying a target VRR to each individual well pair. This results in redistribution of injection and production rates in a more balanced/optimal manner. The process is repeated at regular intervals (e.g., yearly or quarterly) while simulation is run in the prediction mode. Results show higher total oil production rates or lower water production and water injection rates. The WOR versus cumulative oil production clearly demonstrates that the overall injection efficiency increases as the optimization process is progressed.
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