An extensive study was conducted to evaluate enhanced oil recovery (EOR) potential of a giant, offshore, Middle East oil field. The subject field contains a very large reservoir with light oil and has a long production life extending beyond 100 years. Primary recovery began in 1968. The field has been under water flooding with pattern injection since 1982. In order to sustain oil production and increase the ultimate recovery, EOR will likely be implemented at some future time. Miscible gas injection with a water-alternating-gas (WAG) injection scheme is considered to be the most suitable method among the currently available technologies. The WAG injection process is a well-established EOR technique with several successful field applications around the world. This paper describes Water Alternating Gas (WAG) Optimization through Tapered WAG technique (more gas is injected earlier and then reduced over time) and its impact in the subject reservoir. The primary focus of this study is to estimate the benefit of miscible WAG EOR for the subject reservoir. Finely-gridded, compositional, mechanistic, 2D cross-sectional models as well as 3D sector models were constructed and used for the evaluation. One non-hydrocarbon (CO2) and two hydrocarbon ("associated" and "lean') miscible gases were tested as injectants. The study encompasses different geological areas in the same reservoir and addresses key design parameters including well spacing, optimal WAG operating scheme, and timing of WAG application. In this paper, we will focus on formulation of optimal CO2 WAG operating scheme. As part of optimization of the miscible WAG application, a concept of Tapered WAG was tested. A typical WAG application consists of injection of water followed by gas injection. Each cycle of water and gas injection is of fixed duration. In Tapered WAG concept, the durations of gas injection varies with longer gas injection earlier and reducing with progressive WAG cycles. Such miscible WAG application, termed as Tapered WAG, was found to be more effective than the Uniform WAG application where the water and gas injection cycle durations are same. The Tapered WAG technique reduces response time i.e. oil bank arrives earlier. It also uses gas injection more efficiently, i.e. produces more incremental oil per unit of injected gas. Findings were applicable to both a homogeneous (low and relatively Uniform perm) and heterogeneous (high perm with high perm streaks dominant) areas of the reservoir.
Gas injection has been widely used by industry for improving oil recovery. A common variation of gas injection is to have water-alternating-gas (WAG) injection which attempts to overcome gas override in an oil reservoir. In this paper, a simultaneous water and gas injection pilot is discussed. Water and gas are injected simultaneously using two strings in the same well with water injected into an upper zone and immiscible hydrocarbon lean gas injected into a lower zone. This is referred as SWAG in the paper. The subject reservoir is part of a large field located offshore in the Middle East. Water flood started in this under-saturated oil reservoir since 1980’s. Five immiscible gas injection pilots (GIPs) including the SWAG pilot were initiated in late 2001 in this reservoir to assess the benefits of immiscible gas injection in improving oil recovery. This paper describes the performance analysis from field surveillance data of the SWAG pilot which is also aided by a sector simulation model. Performance comparisons of the SWAG pilot versus the earlier completed gas injection pilots is also demonstrated. The history matched model successfully predicts gas arrival timing in the pattern producer. The model results are used to infer the swelling effect of the injected gas as well as to estimate gas sweep efficiency. Both RST log and simulation results show that simultaneous water injection introduced in the upper zone is not able to mitigate gas override. The model analysis, coupled with results from special core analysis, suggests the immiscible gas is not as effective as water injection in maximizing oil recovery from this reservoir. The volumetric sweep efficiency of the injected immiscible gas is estimated to be less than 10% pore volume (PV) and the swelling benefit is less than 1% OOIP at the time of gas breakthrough.
A new generation geologic model for a giant Middle East carbonate reservoir was constructed and history matched with the objectives of creating a model suitable for full field prediction and sector level drill well planning. Several key performance drivers were recognized as important factors in the history match; 1) unique carbonate fluid displacement; 2) data validation and horizontal well trajectory issues; and 3) distribution of high permeability streaks. Ultimately a full field history match consisting of more than 1000 well strings and several decades of history was achieved using detailed distribution of the high permeability streaks, while honoring measured core poro-perm relationships, lab-validated displacement curves, and well test data. This paper discusses the role of the geometry and the vertical distribution of the high-permeability streaks in the history matching of a giant offshore carbonate reservoir. Specifically, the modeling of the high-permeability streaks – which consist of thin rudist and algal rudstone, floatstone, and peloidal grainstone, with abundant, well-connected inter-particle porosity - became possible after extensive revamping of the reservoir rock type model, updating well descriptions, and a detailed zonal mapping of the high permeability streaks and dolomitic zones. The areal and vertical model resolution was doubled over the previous models to accommodate the internal sub-layering of the upper four reservoir zones in order to capture the thin (~1.4 ft) high-permeability streaks. During the history match, local modifications of the high-permeability streaks were the integral part of the feedback loop between the simulation engineers and geoscientists that kept the common-scale simulation model and geologic model synchronized. The final history match was validated by extensive analysis of the models’ vertical conformance as compared to production logs. This approach made it possible to construct a more heterogeneous model than previous models; while honoring both field KH and matrix poro-permeability without local permeability multipliers. The combination of these features provides a higher confidence model of long term well injectivity/productivity.
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.
Numerical simulation models have been used to optimize oil recovery since the 1960's. Typical steps to create a simulation model include 1) building a static model based on all available geological and petrophysical data; 2) history matching the static model to tune it to the available production and measured data; and 3) using the conditioned model to design drill-wells, predict pressure evolution, and forecast flow streams for business decisions. Today it is generally accepted that the best models result from using interdisciplinary teams to ensure geologic consistency is maintained during the history matching modifications – e.g. Sibley (1997), Landis (2005). We discuss herein a unique approach to efficiently manage and expedite the history matching of a giant carbonate reservoir using a team of simulation engineers. The workflow was developed based on domain decomposition principles to divide the problem into manageable sector models with coordinated updates between the sector and full field model to obtain the full-field history match. With this approach, dynamic history matching is divided among many simulation engineers in a way that maintains the base geologic model, vets regional modifications, and transmits local lessons to the full-field model. The workflow relies on fast extraction, creation, and management of sector models (or subdomains) from the full field. Each sector is linked to the full field by incorporating flux boundary conditions obtained from either a larger sector model or the full-field model. The proposed approach allows for the acceleration of the history match by effectively dividing the work among a team of simulation engineers. The "sector" approach of making smaller models from one large model speeds up the model build and run times making it convenient to have the multiple iterations necessary to achieve a satisfactory history match in a complex, high-contrast flow strata geologic environment. The goal of the work was to reduce the time to achieve the history match to one year, as opposed to the previous experience requiring several years for similarly sized models. Some critical advantages and lessons from the workflow will be discussed through its application using actual history matching examples from a giant offshore, Middle Eastern, carbonate reservoir having over four decades of production history.
This paper discusses a revised field development plan (FDP) of a giant complex carbonate reservoir located offshore Abu Dhabi which has been producing for more than 30 years. In recent years the target production of the field was raised. However, the target production plateau length and recovery factor remained high. This ambitious vision created a new environment and new challenges for field development.Previous work has included a number of innovations (1,2,3) :• Optimize well spacing and configuration, focusing on the advantages of infill drilling for improved aerial/vertical sweep efficiency • Optimize drilling timing for infill wells • Optimize vertical well placement • Optimize injection strategy An optimized field development plan is proposed where the desired production rate and plateau length are met while recovery is improved. The optimized solution involves a proposed infill drilling strategy and corresponding injection strategy. The injection strategy includes optimization of the future target reservoir pressure to achieve the best field performance.
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.
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