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.
Produced water reinjection (PWRI) is a proven field development technology which has been widely applied to numerous fields to optimize disposal of produced fluids while meeting reservoir injection requirements. However, PWRI has not been evaluated in many of the giant carbonate reservoirs which are relatively immature in the Middle East. In this paper, an on-going assessment of potential PWRI for a giant offshore field is presented. The giant offshore oil field in the Middle East has been extensively developed since the 1970's. Seawater injection has been applied in the field since the 1980's and the produced water is disposed of through dedicated wells. The daily water production rate from this field has been increasing over time, and the continuous addition of oil producers and water injectors to capture the field reserves will further accelerate water production. Developing the most cost-effective solution to handle the significant volumes of produced water is crucial to ensure long-term operability of facilities and continued field production. A strategy to derive value from the produced water, which otherwise is considered unwanted, is to utilize PWRI. Proper laboratory assessment to determine specifications for PWRI will ensure the re-injected produced water is compatible with the reservoir fluids and that the target injection rate can be sustained through matrix flow. The lab assessment to determine produced water quality specifications include an evaluation of the inorganic scaling potential of PWRI (fluid compatibility) and an analysis of the impact of oil carry over in the presence of fine particles on near wellbore injectivity. Thermodynamic modeling and bottle tests were performed to determine compatibility of PWRI with reservoir fluids (i.e. scale precipitation) and core flood tests at residual oil saturation with multiple rock types were completed to quantify the impact of oil carry over on PWRI specifications. Thermodynamic modeling and bottle tests show PWRI has a lower inorganic scaling tendency than conventional sea water injection, and that scaling does not appear to be aggravated by PWRI. Core flood experiments indicate injectivity is maintained under anticipated oil carry over conditions (including upset conditions) across the various rock types evaluated suggesting PWRI may be an attractive technology to mitigate produced water disposal requirements while also meeting a portion of future field-level injectivity demand.
An extensive study was conducted to revise the field development plan (FDP) of a giant offshore Middle East oil field. The subject field contains several stacked reservoirs 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 the subject reservoir, most of injector wells are located in a concentric ring along the crest. This reservoir is currently undergoing further redevelopment with a line drive injection pattern utilizing long horizontal wells. Currently, a revised field redevelopment plan is being evaluated to assess increasing the production target of the reservoir while maintaining the production plateau. In order to sustain target oil production and improve recovery, the revised field redevelopment consists of different innovations including maximum reservoir contact (MRC) wells with line drive pattern, gas lift, infill drilling and co-development of multiple reservoirs with single lateral or dual lateral wells with different tubing strings and appropriate EOR technology. This paper describes the current work to optimize the combined development plan of three vertically adjacent reservoirs by using multiple strings in a given well to access them. The focus was to revise the development plan of the larger reservoir and use the future development wells of this reservoir to access other smaller vertically adjacent reservoirs that are within the drilling reach from different artificial islands. The study addresses optimized well spacing, vertical well placement, well drill sequence and infill well placement. This study also includes assessment of the value of infill wells, dual-lateral and single-lateral wells to target more than one reservoir. An optimized field development plan is formulated with new MRC wells which include both single and dual-lateral wells accessing one, two or three reservoirs depending upon location and applicability.
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