This work is done in the context of a giant carbonate reservoir with 40 years of production/injection history. In this reservoir, the key heterogeneities that impact the production mechanisms (high permeability streaks, permeability contrast, intra dense and dual sub-zones of varying maturity) are well characterized, through major field reviews. However, in the recent years, unexpected high water saturation were encountered while drilling infill horizontal drains. An integrated multi-scale investigation was conducted to understand the potential mechanism of water movement within the lower sub-zone through an assimilation and interpretation of data and multi-disciplinary understanding. This work resulted in further optimization of remaining infill wells and the field development strategy. The observed high water saturation signatures were investigated through integration and analysis of multi-disciplinary data, using data acquired in infill wells during the last three (3) years. First, the studied wells were categorized primarily based on their water cut, water saturation encountered and then mapped along with their data. Second, the different scenarios of possible water movement were developed chronologically. Third, a multi-scale integrated analysis (well level to reservoir level) and subsequent mapping was captured on a montage. The developed scenarios were validated with recent surveillance, monitoring data and corroborated with geological/geophysical understanding. This comprehensive approach and results were corroborated with blind tests in terms of the dynamic behavior of the water. Faults and their characteristics were identified as a key element affecting this local dynamic behavior. Saturation logs showed high water saturation but were inconclusive on whether this water is mobile or not. This required integration with dynamic flow data from production logging and well tests. The dynamic data was integrated with the seismic and geological findings to ascertain whether the water presence is due to poor rock type, water migration through faults or water movement in the matrix. The findings were mapped and led to re-consider the well placements and expectations from infill wells while crossing faults. This enhancement of the reservoir understanding resulted in mitigation of risks in future producers which subsequently impacted the reservoir development strategy. This multi-scale analysis over the reservoir provided an insight into the source of the unexpected high water saturation in the undrained lower sub-zones of the reservoir. Thus, revising the understanding of the field development strategy, well placement and related contingencies.

An updated geological and dynamic model for a giant Middle East carbonate reservoir was constructed and history matched with the objective of creating an alternative model which is capable of replicating the reservoir production mechanisms and improving predictability, allowing optimizing the field development plan and water injection strategy. Giant Middle East carbonate fields often have long production history and exhibit high reservoir heterogeneity. It is always challenging to get a robust history matched model aligned with geological concepts and dynamic behavior understanding. The objective of this paper is to present an improved and integrated reservoir characterization, modeling and history matching procedure for a giant Lower Cretaceous carbonate reservoir in the Middle East. The applied workflow integrates all available geological data (stratigraphy, depositional facies, and diagenesis), petrophysical data (RCA and minipermeameter data, Petrophysical Group definition, cut-off definition) and the extensive database of dynamic data (long production history, well test, RST, open-hole log saturation over more than 40 years of development drilling, and MICP). The process was initiated with the reservoir review by means of a fully integrated study that allowed having better understanding of the reservoir behavior and production mechanisms. The key heterogeneities (high permeability and intra-dense layers) which control the flow behavior were identified during this process. Geological trend maps were generated to control the distribution of high permeability and intra-dense in the model. Well test data, open-hole logs from development wells and time-lapse saturation logs from observation wells were used to calibrate the trend and permeability log data. A phenomenological model was constructed to test the main factors impacting the production mechanism as identified during the reservoir review. Multiple iterations were performed between the static and dynamic models in a way that allowed a quick and efficient work that is consistent with all disciplines assumptions. Such continuous loop between the dynamic and geological models, with focus on the geological heterogeneities driving the dynamic reservoir behavior, has led to a more robust model capable of replicate the production mechanisms, which represents a major improvement compared to previous model in term of predictability.

Polymer flooding has long been proposed to improve sweep efficiency in heterogeneous reservoirs where polymer enhances cross flow between layers and forces water into the low permeability layers, leading to more homogeneous saturation profile. Although this approach could unlock large volumes of by-passed oil in layered carbonate reservoirs, compatibility of polymer solutions with high salinity - high temperature carbonate reservoirs has been hindering polymer injection projects in such harsh conditions. The aim of this paper is to present the laboratory work, polymer injection field test results and pilot design aimed to unlock target tertiary oil recovery in a highly heterogeneous mixed to oil-wet giant carbonate reservoir. This paper focuses on a highly layered limestone reservoir with various levels of cyclicity in properties. This reservoir may be divided in two main bodies, i.e., an Upper zone and a Lower zone with permeability contrast of up to two orders of magnitude. The main part of the reservoir is currently under peripheral and mid-flank water injection. Field observations show that injected water tends to channel quickly through the Upper zone along the high permeability layers and bypass the oil in the Lower zone. Past studies have indicated that this water override phenomenon is caused by a combination of high permeability contrast and capillary forces which counteract gravity forces. In this setting, adequate polymer injection strategy to enhance cross-flow between these zones is investigated, building on laboratory and polymer injection test field results. A key prerequisite for defining such EOR development scenario is to have representative static and dynamic models that captures the geological heterogeneity of this kind of reservoirs. This is achieved by an improved and integrated reservoir characterization, modelling and water injection history matching procedure. The history matched model was used to investigate different polymer injection schemes and resulted in an optimum pilot design. The injection scheme is defined based on dynamic simulations to maximize value, building on results from single-well polymer injection test, laboratory work and on previous published work, which have demonstrated the potential of polymer flooding for this reservoir. Our study evidences the positive impact of polymer propagation at field scale, improving the water-front stability, which is a function of pressure gradient near producer wells. Sensitivities to the position and number of polymer injectors have been performed to identify the best injection configuration, depending on the existing water injection scheme and the operating constraints. The pilot design proposed builds on laboratory work and field monitoring data gathered during single-well polymer injection field test. Together, these elements represent building blocks to enable tertiary polymer recovery in giant heterogeneous carbonate reservoirs with high temperature - high salinity conditions.

TX 75083-3836, U.S.A., fax 01-972-952-9435.Abstract 4D (or time-lapse) seismic is sensitive to changes in reservoir pressure and saturation. It allows monitoring of a reservoir during production, helps define areas of unswept hydrocarbons, and aids planning of infill drilling or pressure support solutions.By improving the reservoir model, 4D reservoir monitoring can improve the accuracy of reserves evaluation and help with the optimisation of reservoir management. This paper describes the preliminary work carried out as part of an ongoing project on 4D reservoir monitoring. The ultimate aim of the project is to history match a field flow model using both production and 4D seismic data.The proposed approach, based on the integration of a reliable petroelastic model (PEM) with a dynamic flow simulator, uses an iterative, gradient-based optimisation method to adjust the initial reservoir parameters. This paper focuses on the assessment of the impact of petroelastic modelling within the framework of 4D quantitative history matching. It shows the results of the procedure that was followed to validate the PEM for the Girassol field in offshore Angola. It addresses the problems of scale usually encountered within a 4D workflow. It also illustrates the results of the sensitivity analysis carried out on the acoustic properties predicted by the PEM when applied to the dynamic flow simulator.In view of the application of the full 4D history matching loop to the field example, possible ways of determining the acoustic parameters and the areas of the reservoir that are most sensitive to 4D effects were assessed and are presented herein.This paper highlights the importance of deriving a reliable PEM when dealing with 4D reservoir monitoring and suggests (*) Now at IFP School, Reservoir Geoscience & Engineering a way forward for integration with computer-aided history matching processes using both production and seismic data. History-Matching Using Time-Lapse Seismic: the HUTS approach to 4D history matchingThe classical approach to history matching a reservoir model strives to achieve a satisfactory agreement between observed and predicted production data. This is attained while keeping the model as consistent as possible with all the static and dynamic information available from logs, cores and well tests. In most cases, there is not a unique combination of input parameters that leads to a good history match. Hence, it is left to the technical judgment of the reservoir engineer to discriminate between possible solutions.Until recently, production data only (e.g. gas-oil ratio, water cut, flow rates) have been used during this process. With the increasing availability of 4D seismic data, the use of this added information becomes a new challenge.HUTS 1,2 , a 2-year project sponsored by the European Commission and terminated in December 2002, proposed a quantitative use of 4D data in history matching.The HUTS approach uses an iterative, gradient-based optimisation method to adjust the initial reservoir parameters. The problem fa...

Reservoir X is a giant oil reservoir of 30×10 Km2 developed since 1973 using peripheral water injection. A major review study was done in 2016 highlighted major reservoir challenges that need to be managed and mitigated. The main challenges are (a) reservoir pressure decline in the central area (b) advancement of water cut/water conning (c) increased number of inactive strings (d) improper distribution of production offtake (e) inefficiency of current injection scheme. Consequently, reservoir deliverable potential has continuously dropped with increasing inactive strings threatening the attainment of the field mandated production target. This requires a major shift in our reservoir management strategies and best practices to cope with these challenges. In this paper, a case study for reservoir management in a mature carbonate reservoir with its detailed methodology is presented. An intensive and integrated technical work was conducted to (a) regain the target technical rate of 20% (300Mbpd) (b) arrest the pressure decline (c) implementation of a more efficient long-term plan to increase reservoir pressure and to maximize ultimate recovery. A detailed approach was developed which consisted of short, mid and longterm actions. This approach involves (a) re-prioritization of infill drilling through weighted ranking (b) pressure recovery implementation strategy through sectorization, re-balancing of production offtake and improving water injection efficiency (c) sector based evaluation using simulation/streamlines/data analysis for the voidage replacement (e) water injection optimization with the help of new peripheral water injectors, increased water injection availability (New clusters and network debottlenecking) and new Water Injection scheme (Mid Flank water injectors) (f) tracking the implementation of the Pressure Recovery Plan with a dedicated and tailored monitoring dashboard. Through this integrated approach a portfolio of wells is selected and ranked that help in achieving the objectives of the reservoir development efficiently and the 20% Technical Rate achievement. The sector wise analysis and tracking approach enabled in arresting the pressure decline in the crestal area and ensured that the focus remained on the recovering pressure in the worst affected areas of the reservoir while meeting the production requirements. Another important outcome of this work was to drive a slew of initiatives related to the improvement of water injection efficiency that is a necessary requirement to recover the pressure in the crestal area. This reservoir management methodology and framework put in place provides a platform to continuously integrate the inputs (production/injection; VRR; pressure) and develop understanding from the different disciplines of the reservoir development to monitor and manage the reservoir in and efficient and timely manner.