Reservoir management practices are classically based on analytical models and standard Reservoir Engineering tools. In the waterfood or water alternating gas recovery process, the analysis is made traditionally with the hypothesis of constant predefined patterns. The producer – injector pair's interaction is quantified based on predefined geometrical analysis of the percentages of contribution of each injector to a producer. In the absence of certain degree of reservoir homogeneity, and also possible injection/production technical issues this method presents a lot of limitation and may lead to erroneous results. Fields in the Middle East are dominantly carbonates and the flow paths are guided by heterogeneous distribution of reservoir characteristics mainly permeability. This paper outlines a case study for the usage of streamline simulation in predefining the optimized rates of each producer and injector in order to optimize the recovery from individual pattern. The study quantified the interaction between producers and injectors pairs and defined the dynamic pattern distribution through the history. A number of attributes can be derived for each producer injector and pattern. Attributes such as the instantaneous and cumulative voidage replacement ratio, sweep efficiency and injection leakage can be analyzed in order to give more weight in the optimization stage to certain producer and certain injectors. It was concluded that the geometrical lay out of the patterns is not necessary respected and the injectors may support producers outside their geometrical patterns. There was as well a certain amount of the injection that is not contributing to any production and it is not targeting or supporting any specific well. A number of forecast scenarios were conducted and through ranking different realizations based on total patterns sweep efficiency, the best scenario was selected to determine the allowable volumes to be injected and produced. The scenario showed better control of the patterns as there was a reduction of any redundant injection and the leakage was cut down.

This paper presents an application of integrated asset modeling (IAM) to a rich gas condensate field under recycling mode located in Abu Dhabi. The field is composed of many non communicating gas reservoir units; some of these units are already developed and being produced for a number of years, while some others reservoirs are in the exploration / evaluation phase. Potentially, some of the reservoir units are sharing or will share the surface network and the process facilities. The project consists of developing a platform for a solution that can respond to the current requirement of the available modeled reservoirs; at the same time, the solution should be expandable to account for the reservoirs being explored or at early production phase. The first step of the study was to construct the surface network for both gas injectors and gas producers. The subsurface compositional simulation models for the developed reservoirs were available and history matched. The platform linking the surface to subsurface was developed and set to fulfill the field development requirements. The solution was validated for the historical performances, measurement of the surface network were collected and validated in the stand-alone mode and in the coupling mode. Tests for the prediction performances were also performed, and led to more realistic profile showing the recoverable reserves for recycling and blowdown considered scenarios. The integrated model indicated area of improvement in pressure history match of the field simulation model for few wells where it was not easy to observe in standalone simulations. The platform for the integrated Asset modeling is expandable to further development that could be plugged-in, either functional adds-on like process modeling and economic evaluation or organic like adding additional wells to the existing models or adding new models for exploration unit. It will be also applicable to see the compression requirements during any time in the future.

This paper presents a generic workflow to assess direct and indirect production in reservoirs with layered contrasted permeability. The objectives are to quantify the total individual production split from those zones when compared to volumetric and evaluate the productivity efficiency. The workflow comprehensively integrates reservoir surveillance tools such as Production Logging Tools (PLTs) to perform a zonal decline analysis through analytical approach. The numerical simulation modeling is utilized to support this assessment. The paper describes a method of capitalizing the flowmeter results and correlate them with production decline to identify the volumes swept from the tighter zones of interest. The workflows identifies, as a result of this analysis, the split of the two portions of this swept volumes in the tight zones : a portion easy to identify, as it is produced directly through the logged wellbore or migrated vertically to most permeable zones to build-up on the attic portions of the reservoir. Such analysis when conducted in a specific field and coupled with simulation result is a powerful tool to decide on the actual mechanism affecting the sweep including the importance of gravity and percolation process. Consequently, strategic decision could be taken based on the options to develop the contrasted zones. This is including the decisions on wells configuration, whether it is more justified to fetch the tight zones volumes through vertical wells or to rationally exploiting the top layer through horizontal wells. The workflow was applied to real case study and showed a quantitative conclusive result, it demonstrated the equilibrium, required to maintain, in the withdrawals ratio of the contrasted zones. This equilibrium will ensure to have a better sweep of lower productivity zone.

This paper describes the implementation of the solvent model in streamline simulation and its application to WAG injection optimization for a producing field. The solvent model was implemented as an extension to the 3-component black oil model, with solvent as an additional component, to model miscible displacement process. The relative permeabilities and fluid properties of the oil and gas phases are modified based on the fraction of the solvent component, the reservoir pressure and the Todd-Longstaff mixing-parameter (i.e. an empirical treatment of the effects of physical dispersion between miscible components). The solvent model was applied to a Middle Eastern oilfield, which is currently under development using a miscible WAG process. PVT analysis has been done to prepare the properties for the reservoir gas and the injection solvent. Streamline simulation models with and without solvent model were run to compare the results with a reference finite difference compositional reservoir simulator and the effect of miscibility has been validated. Results of streamline simulation models with and without solvent model were compared against a reference finite difference reservoir simulator. The comparison shows the streamline simulation model with solvent model has much better agreement with the reference finite difference compositional reservoir simulator which shows that the miscible displacement process is properly simulated in the streamline simulation model with solvent model. The solvent model presented in this paper advances streamline simulation technology, combining the intuitive and unique properties of streamlines and the capability of simulating miscible recovery mechanism. It allows simulating both immiscible and miscible displacement within the same simulation. The solvent model considers the effects of miscibility by considering relative permeabilities and fluid properties adjustments based on pressure and solvent concentration. The technology will help effective simulation of miscible recovery process, assist optimum solvent allocation and improve unified sweep.

Within an oil reservoir the water saturation height functions can vary strongly, especially for carbonate rocks. These variations can be significant and difficult to estimate. The amount of hydrocarbons in place, the prediction of recoverable oil, the recovery process and the future plans of developing such reservoirs depend on many factors, one of which is the accurate modeling of water saturation.The Khafji carbonate reservoir is a heterogeneous reservoir with two different types of oil: light oil in the top of the reservoir and heavy oil in the bottom of the reservoir. The challenge of water saturation modeling is primarily in the heavy oil zone, where conventional height function techniques produces poor match against measured water saturation logs. Alternative methods were utilized in order to obtain good match in both light oil and heavy oil columns.A workflow has been created in order to overcome these challenges. Laboratory derived capillary pressure curves were used to establish water saturation height relationships as a function of rock type (RT). Additionally, a Flow Zone Indicators (FZI) analysis was used as a basis for rock typing. Then a J-function derived from capillary pressure data for each rock type or hydraulic flow unit (HFU) was used to generate saturation height function for each RT. The generated saturation undergone via several iterations to match the large span of openhole electric water saturation logs above the free-water level (FWL). The saturation profile generated by this workflow shows a good match to the measured Sw electric logs, and the calculated fluid volumes are in agreement with company's approved reserves estimation.