This study aims to reduce uncertainty in remaining oil saturation (ROS) estimation in Kuwait's heterogeneous Minagish Oolite carbonate reservoir. A progressive experimental workflow across three batches integrates Liquid Trapper coring, Dean-Stark, Core flooding, Centrifuge and NMR (T1/T2) techniques. Objectives include improving material balance, distinguishing hydrocarbon from water signals, and validating ROS and Sor using multiple methods. Deuterium tracer and doped brine enhance saturation accuracy. Results guide EOR efficiency and recovery factor estimation. A progressive stepwise laboratory workflow was designed to quantify ROS using cores acquired via Liquid Trapper coring. Learnings from every batch experiments were used for improvements in later phases. The workflow incorporated routine core analysis, Dean- Stark extraction, core flooding, centrifuge testing, and NMR including native-state and doped-brine measurements. Deuterium tracers assessed mud invasion, while doped brine enhanced hydrocarbon-water signal separation. Batch-1 showed fluid loss during core retrieval. In response, batches 2 and 3 integrated improved NMR protocols and centrifuge methods. These refinements enhanced material balance, reduced uncertainty in ROS estimation, and enabled reliable saturation measurements in swept and unswept zones. A Batchwise experimental workflow adopted to evaluate ROS in cores obtained by Liquid Trapper coring helped in optimising core sample selection process, enhancing cost economics and time efficiency in laboratory experiments. Batch-1 results indicated unreliable ROS estimates due to hydrocarbon losses possibly during core retrieval and handling. RCA and Dean-Stark analyses yielded material imbalance (So+Sw < 0.7), though trends aligned with log data. To address this, Batch-2 incorporated NMR (native, two-phase, single-phase) and core flooding, improving data quality and achieving better material balance (So+Sw > 0.95). However, some plugs still failed to yield oil during flooding, especially in partially swept zones. Batch-3 further enhanced the workflow by integrating centrifuge and doped-brine NMR methods. This allowed clearer hydrocarbon-water phase separation, confirmed by distinct NMR T2 signals. Doped-brine NMR improved hydrocarbon quantification and validated helium and saturation porosity results. Overall, the multi-method approach, including NMR and deuterium tracers, significantly reduced uncertainty in ROS estimation, revealed losses likely occurred during coring/lifting, and improved the confidence in oil saturation measurements—especially in complex, partially swept zones. The study confirms that a combined use of core flooding, Dean-Stark, NMR, and centrifuge methods is essential for accurate Sor/ROS evaluation in such reservoirs. This study advances the state of knowledge by demonstrating a robust, multi-technique workflow for accurately measuring Remaining Oil Saturation (ROS) in complex carbonate reservoirs. By combining core flooding, NMR (including doped-brine), centrifuge and Dean- Stark methods, it addresses fluid loss challenges during coring and improves saturation estimates. This enhances the reliability of EOR project evaluations, guides better reservoir management, and sets a benchmark for ROS analysis in heterogeneous, partially swept reservoirs.

The subject sandstone reservoir is highly heterogeneous due to amalgamated tidal-influenced distributary channels. In addition, it has an unfavorable harsh environment for chemical enhanced-oil-recovery (EOR), such as high salinity (280,000 ppm), temperature (200 °F), and divalent ions (19,000 ppm) as Ca + + and Mg + + . After a robust lab alkaline-surfactant-polymer (ASP) formulation design and successful field trial of the single-well-chemical-tracer-test (SWCTT), an inverted 5-spot injection pattern ASP EOR pilot was designed and field execution started. This pilot is having a challenge controlling the elevated drizzle inorganic carbonate scale at the producers. This paper elaborates on novel practical strategies to control elevated scaling risks and the re-optimization of ASP formulation adjusted to temperature variations due to the extended softened-water pre-flush phase. An extended soften-water pre-flush phase (over-flush) was considered as 7-pore-volume injection (PVI) to avoid the anticipated drizzle scaling risk. However, this over-flush strategy results in longer pilot duration, significantly higher soften water injection costs, reservoir cooling in the pilot region, and persistently high carbonate scaling in the producers. In view of this, various novel pre-flush operating strategies are investigated using high-resolution numerical simulations. The optimized pre-flush strategy was chosen based on minimal divalent ion production to control scale. Thermal simulation shows that this optimized pre-flush strategy resulted in significant cooling of the reservoir in the pilot area prior to ASP injection. Due to this cooling, the lab testing raises serious concerns about the effectiveness of the originally designed ASP formulation at reservoir temperature. As a result, the ASP formulation underwent meticulous re-tuning to ensure its robustness against temperature fluctuations and the harsh unfavorable reservoir environment. The re-optimized robust ASP formulation shows effectiveness in large temperature variations and the harsh environment of the pilot. The results of the optimized novel pre-flush strategy demonstrate that elevated drizzle scale can be controlled under harsh environments using viscous polymer slug injection (∼0.6 to 0.75 PVI) with soften water injection ( 2 PVI). This novel strategy not only controls the scaling risk but also provides better oil desaturation, a better oil chemical ratio, less cooling effect, and a shorter pilot duration (thereby better economics) as compared to the originally designed pre-flush strategy (7PVI).

Abstract The oil recovery from the water-alternating-gas (WAG) injection process is significantly impacted by gravity, viscous fingering, and the permeability heterogeneity of the reservoir. Therefore, the combined effect of these parameters cannot be neglected in the WAG injection process. This article presents the development of a mathematical model of oil recovery and its solution for the WAG injection process that takes into account the combined effects of miscibility change, viscous fingering, gravity, and permeability heterogeneity in an inclined stratified reservoir. First, the governing equations and fractional flow functions were explained in relation to the effects of gravity, permeability heterogeneity, viscous fingering, and miscibility change in an inclined stratified porous medium. Then, a mathematical model was developed using fractional flow functions and conservation equations for both injected water and solvent. The model was generated in the form of a quasi-linear first-order partial differential equation, which was solved analytically in two dimensions (2-D) utilizing vector calculus. Next, this model was solved analytically by applying wave theory to practical constant pressure boundary conditions, which generate distinct waves at different times to provide pressure and saturation at the displacement front location. The total volumetric flux and breakthrough time are calculated from the analytical solution at various times. The presented analytical solutions can be used to predict different parameters for stratified porous media in a fast and efficient way. Finally, the results of analytical solution validated with high-resolution numerical simulation for a wide range of permeability heterogeneity, which shows excellent agreement for breakthrough time, saturation, and pressure versus displacement location of different waves at different times. This analytical solution will save time and money by offering guidance to engineers for analyzing the saturation and pressure distribution at different times and predicting oil recovery. It will also improve the understanding of the physics underlying the multiphase flow WAG injection process in heterogeneous reservoirs.

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The Sabriyah field located in northern Kuwait primarily produces from the Mauddud and Burgan formations. The upper section of the Burgan formation is referred to as the Sabriyah Upper Burgan (SAUB) reservoir. SAUB reservoir consists of Cretaceous Albian age sandstones and spreads over an area of ~105 km2. This paper sheds light on the successful application of a long-term polymer injectivity (LTPI) test in the SAUB reservoir as a strategic milestone towards phased commercial polymer-flooding development. The main objective of the SAUB LTPI test was to evaluate injectivity at multiple injection rates and polymer concentrations under sub-fracturing conditions. Current EOR efforts target reservoir areas with unfavorable mobility ratio to improve oil recovery and unlock additional oil reserves. The location of the SAUB LTPI test was carefully selected to avoid faults and low channel thickness. Effluent water with TDS ranging from 150,000 to 200,000 ppm was used for polymer solution preparation. Iron content was relatively high (up to 200 ppm) but this was duly mitigated by maintaining low dissolved oxygen levels (i.e. <10 ppb). Fit-for-purpose modular skids were used for water treatment and polymer mixing/injection. A pre-selected sulphonated polymer was used based on extensive lab evaluation to overcome the high TDS, hardness, and temperature of the SAUB reservoir. A step rate test was conducted, and subsurface parting pressure was estimated to be around 5020 psi. Field data indicates that the selected polymer can be injected at commercial rates, under matrix conditions, using treated effluent water without plugging the reservoir. Important polymer rheological properties were generated using field data. Field and lab polymer data were found to be consistent. The LTPI test location average permeability that is lower than that of core plugs used during core-flooding experiments. Consequently, residual resistance factor was increased from a lab derived value of 1.3 to 1.5 based field data. Establishing favorable polymer injectivity under matrix conditions with relatively lower permeability is encouraging because better polymer injectivity is expected in areas having higher permeability. Pre and post polymer injection reservoir modeling were carried out on a sector reservoir model built in CMG STARS utilizing available lab data. Post calibration of the dynamic model was performed using pilot operational and laboratory data, predictive forecasts were then generated to evaluate the techno-commercial feasibility of polymer injection into the SAUB reservoir. Reservoir simulation results based on actual field data demonstrated that polymer-flooding accelerates oil production rates compared to water-flooding. Injecting 0.7 to 0.8 PVI (pore volume injected) at a polymer concentration of 1600 ppm was found to be optimal for commercial polymer-flooding development. The adopted approach and associated results demonstrate the viability of performing customized field trials to fast-track phased commercial polymer-flooding. LTPI test results validated earlier SAUB polymer-flooding forecasts for SAUB polymer-flooding development (SPE paper reference). An incremental oil recovery of 9.6 % can be achieved from polymer-flooding. Polymer-flooding ultimate total cost (UTC) over a period of 10 years was estimated to be 15.80 US$/bbl including the cost of additional wells.

Umm Gudair Minagish Oolite is a highly heterogeneous reservoir with intermittent micritic units forming low permeability barriers to fluid flow. Based on screening/lab study, the polymer or surfactant-polymer flooding was proposed using normal 5 spot injection pattern. KOC decided to test only polymer flooding because of cost considerations. This study is to design fit for purpose long-term polymer injectivity (LTPI) pilot using produced water (salinity 230000ppm) with the objectives of testing injectivity, adsorption, breakthrough, resistance factor and response time within 6-12 months. Numerical simulation and economic modelling was used for this evaluation to explore various novel strategies. Various parameters were optimized to design Fit for Purpose LTPI pilot configurations using high salinity produced water. The laboratory experiments were conducted in conjunction with reservoir simulation to confirm the technical viability of polymer flooding using high-salinity water. In this study, we discuss existing challenges and how the same was transformed into opportunities by optimizing various parameters such as number of wells, well spacing, well location, perforation layer for injectors and producer and the economics to meet pilot objectives. The simulation results show that normal 2-spot injection pattern (2 injectors and 1 producer) with 80m well spacing and perforation in B-zone is a suitable solution for LTPI pilot within given time. Based on the above plan, one injector was drilled near the existing producer. The recent gyro survey demonstrated shifting of the sub-surface locations of both the producer and injector, thereby altering the well spacing. Further simulation incorporating the new locations indicated that the pilot would not meet the objectives within the piloting duration of 6 months because of shifting. Surface constrains hindered the shifting of drilling location for the second injection well to maintain 2-spot injection pattern. To overcome this challenge, additional simulation works performed to plan and drill the second injector well near another existing producer at 80m well spacing in a different area to test different rock types. Both LTPI pilot designs show higher incremental cumulative oil over water flood, faster polymer breakthrough (∼1 month), faster polymer response and oil peak within 6 months. In addition, using high salinity produced water for polymer flooding is expected to reduce piloting cost and increase operational efficiency by reducing operational problems associated with treatment and handling of less saline water.

The water-alternating-gas (WAG) operating scheme and reservoir permeability heterogeneity are the main crucial parameters, which highlyaffect WAG displacement process. The novelty of this article lies in the development of an analytical model for WAG incremental oil recovery as function of WAG ratio, viscous gravity ratio and mobility ratio for the stratified heterogeneous reservoir. We have investigated the effect WAG ratio on WAG incremental oil recovery with variation horizontal permeability heterogeneity, vertical permeability anisotropy and dip angle of the reservoir. The critical operating parameters investigations were carried to optimize WAG displacement process in both homogeneous and heterogeneous reservoirs. Finally, we have estimated all the benefits of the most suitable techno-economical WAG operating scheme as tapered WAG (TWAG) over uniform WAG (UWAG). The developed analytical model showsreasonably similar results as numerical simulation. The results of the analytical and numerical analysisshow that the incremental oil recovery accelerated bya decrease WAG ratio. However, this effect is more noticeable at high viscous gravity (VGR). The increase in reservoir dip angle subsequently increases vertical and displacement sweep efficiencies compared to the horizontal reservoir for different WAG ratio. While increasing WAG ratio decreases vertical sweep and increases displacement sweep of inclined reservoir compared to the horizontal reservoir. The increase of oil recoverywas observed by higher Kv/Kh with a lower WAG ratio. However, this effect is less evident at lower Kv/Kh. The WAG ratio with a higher proportion of water is beneficial for the heterogeneous reservoir. The infill implemented before WAG start shows faster oil recovery compared to WAG start first then infill implemented in the heterogeneous reservoir. The TWAG incremental recovery over water flood was 18% in homogeneous and 8% in heterogeneous reservoirs, while EUR was approximately similar to UWAG. The TWAG shows more efficient techno-economic benefits over UWAG due to better economics, faster oil recovery rate, more efficient use of injected gas and reduces response time in both homogeneous and heterogeneous reservoirs.

Availability of gases at the field level makes attractive to water-alternating-gas (WAG) process for low viscosity and light oils carbonate reservoir. However, impact of reservoir heterogeneity on WAG performance is crucial before field application. In general, ramp carbonates have heterogeneity due to variation of permeability and porosity. However, WAG performance significantly affected by permeability variations. This article investigates merits and demerits of WAG displacement due to permeability heterogeneities such as permeability anisotropy, high permeability streaks (HKS), matrix permeability, dolomite and thin dense stylolite layers. High-resolution compositional simulations with tuned equation of state (EoS) were carried out using 2D and 3D sector models. The study focuses on WAG performance in terms of oil recovery, vertical sweep, solvent utilization, gas oil ratio (GOR), water cut (WCT), WAG response time, gravity override, hysteresis, un-contacted oil saturation and economics. The results of simulation show that the heterogeneous reservoir provides initially faster WAG response, lower expected ultimate recovery (EUR), faster gas breakthrough, higher GOR and WCT production compared to homogeneous reservoir. The gas gravity override at smaller wells spacing is less in homogeneous reservoir as compared to heterogeneous reservoir, but it is reverse in case of larger well spacing. In heterogeneous reservoir, the HKS shows significant gas override resulting in poor vertical sweep due to capillary holding, and the high permeability dolomite layer shows early water breakthrough. This reservoir has higher solvent utilization in initial stage, and then, it becomes nearly equal to homogeneous reservoir. Simulation in both reservoirs overestimates incremental recovery of 2–3% OOIP at one pore volume injection because of not involving un-contacted oil saturation as predicted in core flood. The findings of this study will help to understand WAG performance and design in highly heterogeneous reservoirs for field applications. Graphical abstract

Summary An extensive study was conducted to optimize the field development plan (FDP) with infill wells in water and miscible water-alternating-gas (WAG) displacement processes for high and moderately heterogeneous areas of stratified carbonate reservoir. This reservoir is complex heterogeneities with numerous fractures, high perm steaks, multiple sub-layers with variable permeability and intrabed communication with other reservoirs. Within this reservoir, the wells have dual completion through short/ long strings. It is observed that injected water /gas is flowing through high permeability layers and leaving a lot of oil in un-swept area. Therefore, in order to sustain target oil production and improve recovery, this reservoir is currently undergoing re-development with different innovations including maximum reservoir contact (MRC) wells with line drive injection pattern drilled from different artificial islands, gas lift, infill wells, different tubing size strings, different types of well completions (limited entry liner –LEL, pre perforated liner- PPL, inflow control devices- ICD and inflow control valve- ICV) and appropriate EOR technology. This article presents analytical models and a step by step work flow to optimized FDP for optimum tubing size, well spacing, vertical well placement, well length to reduce the gap between toe to heel of two wells, techno-economic viable number of infill wells and their location (vertical and areal) for maximizing the recovery and maintain the longer plateau at target production rate. An FDP is formulated with optimum tubing size, well spacing, well length, vertical well location and techno-economic viable infills in water / miscible WAG flooding for a highly heterogeneous complex stratified reservoir.

The paper presents an analytical solution of Buckley-Leverett (BL) equation in gas displacement process including viscous fingering and gravity effects at constant pressure boundary conditions for the inclined stratified heterogeneous reservoir. First, the governing equations related to the change of fluid properties, which govern viscous fingering are discussed. Then the gas flood BL-equation accounting for gravity and miscibility effects for inclined stratified heterogamous reservoir are developed and solved analytically using fractional-flow theory and MOC (method of characteristics). The analytical solution provides the guidance to predict the oil recovery through pressure and saturation distribution at any given time for horizontal, inclined, homogeneous and heterogeneous reservoirs. The results of the analytical solution (total volumetric flux, breakthrough time, front location, saturation and pressure) are compared with finite-difference numerical simulation using CMG simulator. The comparison shows that the analytical solution gives approximately similar results as finite difference numerical simulation. The results of analytical solution show that the total volumetric flux increases with increase of permeability, permeability heterogeneity, injection gas viscosity, mixing parameter and injection pressure, while it decreases with increase in gravity, reservoir inclination and normalized gas formation capacity. The breakthrough time and advance distance are found to be strong function of permeability heterogeneity, injected gas viscosity, mixing parameter and reservoir inclination angle, gravity number, normalized gas formation capacity and injection pressure. Furthermore, with increase of mixing parameter/injection pressure and decrease of permeability heterogeneity results in remarkable improvement of relative permeability and reduction of residual oil saturation led to higher oil displacement efficiency.

This paper describes a step by step work flow to optimise field development plan of three vertically adjacent complex carbonate reservoirs by using multiple strings in a given well to access them. It also provides an innovative view on how to develop multiple vertically separated, adjacent complex reservoirs from artificial (man-made) island with maximum reservoir contact (MRC) wells to get economically viable production. The focus was to revise the development plan of the major reservoir and use the future development wells of this reservoir to access other vertically adjacent minor reservoirs that are within the drilling reach from different artificial islands. The study addresses optimised well spacing, completion layers of well placement, well drill sequence, well type; and number of economic infill well placement and sectorisation strategies for optimal production. This study also includes assessment of the value of infill wells, dual-lateral, dedicated lateral and single-lateral wells to target more than one reservoir. An optimised integrated field development plan of major and minor reservoirs is formulated with new long horizontal MRC wells which include both single and dual-lateral wells accessing one, two or three reservoirs depending upon location and accessibility.

The major key uncertainty of complex carbonate reservoirs are the vertical transmissibility across the tight dense (stylolite) layers and areal distribution of high permeability streaks (HKS), which have major impact on reservoir management, well locations, and well completion design in water and miscible water-alternative-gas (miscible WAG) injection process. The present study presents interpretation methodology of vertical transmissibility through assessment of horizontal to vertical permeability ratio (Kv/Kh) from various dynamic data. The Kv/Kh range assessment was done after integration with whole core data and pressure transient data. The impact of Kv/Kh on water and miscible WAG injection processes has also been investigated. The result shows that good vertical communication between the bulk of the porous sub-units and all across stylolite layers except one stylolite layer which acts as field wide barrier. In addition, simulation result of water and miscible WAG injection with higher order of estimated Kv/Kh ratio (0.2 to 1 as found in good permeability porous layers of most of the carbonate reservoirs) indicates no major impact on water cut (WCT), gas oil ratio (GOR), water breakthrough (WBT), gas breakthrough (GBT), and expected ultimate recovery (EUR) in homogeneous area, while oil recovery acceleration with lower WCT/GOR and slightly early WBT/GBT time in heterogeneous area due to gravity or viscous effect suppressed by heterogeneity effect. However, the lower order of Kv/Kh ratio (~ < 0.05) provide delay in WBT/GBT and lower WCT / GOR production due to viscous dominant flow which results in lower gravity-viscous number.

An inverted 5-spot Alkaline Surfactant Polymer (ASP) pilot is planned for a giant sandstone reservoir in North Kuwait. Despite the development of a robust lab-optimized ASP formulation at reservoir temperature (90°C) and the execution of a successful Single Well Chemical Tracer Test (SWCTT), the combination of high temperature and divalent ion concentration (∼20,000 ppm) makes the implementation of a successful multi-well ASP pilot very difficult mainly due to the challenge of inorganic carbonate scale. This paper presents some unique challenges in connection with the design of an inverted 5-spot ASP pilot and discusses practical strategies to mitigate them. Due to the high divalent ion concentration in the formation brine, the design basis for the planned chemical EOR pilot requires pre-flushing the reservoir using softened seawater prior to ASP injection. In the base-case scenario for the pilot, injection and production within the pattern were balanced to target a Voidage Replacement Ratio (VRR) of 1. However, it was realized that such a pre-flush strategy would still present significant carbonate scaling risk at the producers. In view of that, an extended softened-water pre-flush strategy (over-flush) was considered to alleviate the anticipated scaling concerns. Simulations were carried out to explore various scenarios to work out the optimal over-flush strategy for the pilot to mitigate the potential for scale formation at the producers. It was realized that over-flushing the hot reservoir brine by large volumes of cooler surface water could result in significant cooling of the reservoir prior to ASP injection. This change in reservoir temperature compromises the performance the original lab-optimized formulation that was designed considering a reservoir temperature of 90°C. In view of that, careful re-tuning of the chemical formulation was necessary to make it robust for pilot conditions post softened water over-flushing.

The present study deals with the extension of Stone's model to develop the analytical model of gravity segregated length (distance travelled by injected water and gas together before the complete segregation) and gravity segregated water zone height in water-alternative-gas (WAG) displacement for inclined stratified heterogeneous reservoirs. However, as per our knowledge, until now, all available analytical models of gravity segregation in the WAG displacement process consider the assumption that the reservoir is homogeneous i.e. one-layer system with constant porosity and permeability. In reality, most of the reservoirs are heterogeneous with random variation in permeability due to the variation in the depositional environments, which have a major impact on a vertical sweep in WAG displacement. The analytical models of gravity segregation for dipping stratified heterogeneous reservoir are developed by solving the fractional flow equations of displacement of fluids through MOC (method of characteristics). Then the results of these analytical models are compared with 3D finite-difference compositional reservoir simulation. The developed analytical models give appropriately similar results as 3D finite-difference compositional model. Also, analytical model results show that the complete gravity segregated length (vertical sweep efficiency) increases with an increase in reservoir dip angle and mobility ratio, and a decrease in gravity number, vertical permeability, and horizontal permeability heterogeneity. On the other hand, the gravity segregated water zone height decreases with an increase in reservoir dip angle and gravity number.

This paper describes a step by step work flow to optimise field development plan of three vertically adjacent complex carbonate reservoirs by using multiple strings in a given well to access them. It also provides an innovative view on how to develop multiple vertically separated, adjacent complex reservoirs from artificial (man-made) island with maximum reservoir contact (MRC) wells to get economically viable production. The focus was to revise the development plan of the major reservoir and use the future development wells of this reservoir to access other vertically adjacent minor reservoirs that are within the drilling reach from different artificial islands. The study addresses optimised well spacing, completion layers of well placement, well drill sequence, well type; and number of economic infill well placement and sectorisation strategies for optimal production. This study also includes assessment of the value of infill wells, dual-lateral, dedicated lateral and single-lateral wells to target more than one reservoir. An optimised integrated field development plan of major and minor reservoirs is formulated with new long horizontal MRC wells which include both single and dual-lateral wells accessing one, two or three reservoirs depending upon location and accessibility. [Received: September 1, 2017; Accepted: July 30, 2018]

Abstract The subject field is a giant offshore reservoir with light oil and a planned long production life extending beyond 100 years. In order to sustain oil production, EOR will be implemented at the appropriate time. As a result of EOR screening, miscible water-alternating-gas (WAG) injection was identified as one of the suitable methods. In order to evaluate miscible WAG potential, extensive WAG simulation studies were conducted in each step including 1D, 2D and 3D simulation. First, 1D simulations were conducted for tuning the equation of state (EOS). Second, 2D conceptual model simulations were carried out for the preliminary evaluation of WAG. Then, 3D conceptual models for two typical geological areas of the subject reservoir, the "Homogeneous" and "Heterogeneous" geologic areas were generated and findings from the 2D simulation study were validated. Finally, 3D sector model simulations were conducted using the history-matched simulation model to evaluate the miscible WAG potential for full field implementation and its economics. In all simulation studies, CO2 and hydrocarbon (HC) gas were evaluated as miscible injectants. 1D simulations replicated a slimtube test and EOS parameters were tuned to match the minimum miscible pressure (MMP) of CO2 and HC gas. As a result of 2D simulations, "Tapered" WAG appears the most attractive WAG injection scheme in terms of gas utilization and oil recovery. In the Tapered WAG concept, the durations of gas injection varies where longer gas injection cycles are completed initially progressing towards shorter gas injection cycles with progressive WAG sequences. The Tapered WAG concept was also tested using the 3D conceptual model and similar findings were obtained. To evaluate miscible EOR WAG for the full field, due to the size of our field, the high resolution gridding required to capture fluid transport and the 9 component tuned EOS, the required computing resources exceed typical computing capacity; hence, two sector models which represent the Homogeneous and Heterogeneous areas were generated. Based on simulation results, normalized type curves for the hydrocarbon pore volume injected (HCPVI) with incremental recovery factor were generated for each geological area. A production and injection profile for full field WAG implementation was generated by applying these type curves to each pattern and incremental oil production was estimated. The potential incremental oil production for WAG application for a giant offshore oil field was successfully assessed utilizing extensive simulation scenarios from a preliminary concept using simplified models to a detailed full field analysis using complex models. Through this step-by-step analysis, we were able to efficiently identify the key criteria impacting full field recovery including Tapered WAG, impact of injectant and impact of multi-scale heterogeneity (e.g. 2D-3D).

Abstract As part of the ongoing development of a large offshore oil field, an asset owner places a strong emphasis on continuous improvement of the established framework for integrated post-drill well analysis. The geology of the candidate field is complex and the occurrence and distribution of the extreme permeability features that dictate early water production is highly uncertain. While much effort is devoted to mitigating their adverse impact through proper integration of surveillance data for accurate well planning, post-drill outcomes can still diverge significantly from pre-drill expectations. Several wells have been drilled in the production build-up campaign, including ground-breaking pilots and many more are following in very quick succession as part of the life cycle strategy for the field. Due to high drilling frequency, the challenges of assimilating learnings through conventional post-drill analysis for optimization of future drill wells can be enormous. To apply key lessons from these wells in building quick baseline knowledge for reservoir model update and drill plan optimization, the modeling and development team have developed an improved workflow for integrated post-drill analysis. The workflow leverages the full benefit of collaboration between multi-disciplinary teams to integrate 3D seismic data, multiple well information (including geologic reports, well logs and petrophysical results) and surveillance data from new drill wells to benchmark pre-drill expectations. An important aspect of the approach is the quick incorporation of drilling results into static and dynamic models via a cycled, closed-loop workflow for quick assessment of model fidelity through an evergreen update process. A multifunctional post-drill analysis facilitates critical consideration of well results to capture significant learnings that influence future drill well and data acquisition optimization, reservoir model history match and prediction enhancements, and identification of drilling hazards and geological features that affect reservoir performance. This paper describes the methodology used to plan and implement post-drill well analysis within a fast paced and high drill frequency environment. Key elements of the methodology are described through the use of a case study example, and include: Standardized subsurface workflow, comparison of post-drill well results with pre-drill well expectations, identification and documentation of significant observations and lessons learned improvement of history match & predictive capability of reservoir models and integration with other drill-well delivery processes.