In this paper, we show a new upscaling process to accurately predict the production performance of gas-condensate reservoirs, accounting for condensate banking phenomena, using a coarsely-gridded black-oil simulation model. In reservoir simulation, it has been necessary to conduct time-consuming fine-grid compositional simulation to reasonably predict the reservoir pressure profile and condensate banking near the wellbore. A newly-developed in-house program utilizes the Adaptive Local-Global Multiphase Upscaling (ALGMP) methodology developed by Nakashima et al. (2012)1. The main feature of the program is that both the entire model domain (global boundary) and local domain (well vicinity) are taken into account in the upscaling process to retain the accuracy of prediction within a relatively short computation time. The entire model domain was reflected in the form of a coarse-grid full-field model, from which a near-wellbore area of interest was extracted for fine-grid compositional modelling (using velocity-dependent relative permeability (VDRP) to represent relative permeability improvement around wellbore caused by high velocity and/or low interfacial tension (IFT)), applying common flux boundary conditions at each time-step. In the coarse-grid full-field model, mobility change is mainly due to the near-wellbore condensate drop-out observed in the fine-grid compositional model. This was reflected by an iterative upscaling of the gas-condensate relative permeability and fluid properties, using an optimization loop over the local domain, to match the well phase flow rates in the coarse-grid black-oil model with that in the fine-grid compositional model, within an acceptable margin. The developed program was applied to a real gas-condensate field model and demonstrated that the ALGMP procedure can provide well performance predictions close to the reference fine-grid simulation results with reduced computational time. The accuracy of the ALGMP procedure is higher than that of a standard single-phase upscaling approach.

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.

In recent years there has been a growing interest in accurately modelling the condensate banking phenomena in gas-condensate reservoirs to better predict production performances. The velocitydependent relative permeability (VDRP) concept is one of the methodologies to replicate well production performance reflecting both condensate banking phenomena and velocity effect in gas-condensate reservoirs. In this paper, we present the result of a fine-scale compositional reservoir simulation study by introducing VDRP model validated against the actual field production data from a gas-condensate reservoir called S-Tuff Formation in Minami-Nagaoka Gas Field in Japan.A comprehensive data acquisition program was implemented during the long-term production test of the S-Tuff formation to enable the detailed evaluation of production performance and near-wellbore fluid behavior in the reservoir. The program included the measurements of flowing and shut-in bottomhole pressures, surface flow data and fluid sampling. The ultimate objective was to accurately predict the field production performance by an established reservoir simulation model through history matching.The fine-scale compositional reservoir simulation study showed that VDRP model was required to obtain reasonable match with production data, including BHPs and GOR, whilst it was not achieved by the model with conventional gas-oil relative permeability curves because the simulated FBHP fell far below the observed data when the FBHP was below dewpoint. Hence, the study suggested that improvement of gas-oil relative permeability by velocity effect occurred during production. It was also shown that the well productivity impairment due to condensate banking in VDRP model was not as severe as in the case where the conventional fixed gas-oil relative permeability was used.In this study, the VDRP concept was adopted to evaluate the impact of condensate banking and velocity effect, and its methodology was validated using the actual field production data and its history matching. This study will contribute further improvement of performance prediction for similar gas-condensate reservoirs.