Screening of Field Development Options by Simulation Study To Improve Recovery From Lower Southern Units of Complex Carbonate Reservoir

Abstract

Abstract Major contribution to oil production has been mostly from the highly prolific upper Southern units in a giant complex carbonate reservoir in the middle-east region. The water front advanced much faster in highly permeable upper units than the lower units and has created uneven water sweep in southern part of the field. Reservoir management program has been implemented to reduce production from wells that are located near the water finger area to achieve an even water flood advance. However, the current situation has raised some issues concerning the optimization of recoverable reserves in lower units due to water slumping from upper to lower units, uneven areal and vertical sweep, and uncertainty in the effectiveness of dense intervals within the lower subunits. But opportunity still exists to improve the recovery from these units. A series of simulation models were built to address above issues. A pilot study was initiated to evaluate the best possible scheme for future management of lower reservoir units. A parametric study was performed using sector models to evaluate the different combinations of pattern type, pattern size, injection phases and completion types. The screening process was performed by extracting sector models from the history matched Black Oil and Compositional models. The prediction runs were made using voidage replacement ratio of 1.1 for forty years of simulation run time. The study area represents 66% and 34% distribution of the OOIP in the upper and lower units of the lower two units, respectively. Based on the simulation study results and economic analysis, it was concluded that the best option for development is 1.4 km Inverted 5-spot pattern. The wells are slanted in the upper unit and horizontal in lower unit of the bottom two units of the reservoir. WI scenarios performed better followed by WAG and GI scenarios. However, the recoveries are comparable for the WI and WAG scenarios. Out of 0.5, 1.0 and 2 years WAG cycles, 0.5 years cycle proved to be the best possible option. As a result of this study, the best two schemes were approved to be piloted in the field and to gather actual data. Based on the results of these pilots, further fine tuning of the fine scale simulation models will be conducted. Fine tuned models would then be used to predict the optimized field wide application of the best possible option for the future development and management of the reservoir. History matched black-oil and compositional simulation models are utilized in this study. The black-oil model was used to study WI behavior. However, GI and WAG performances were examined using the compositional model. A local grid refinement (LGR) was incorporated in the southern portion of the reservoir for the bottom three subunits of the total five subunits. The LGR was introduced to provide higher resolution to obtain a better match of water breakthrough in producers and to mimic the water finger observed in the field during the history matching process. Introduction The reservoir consists of a layer cake setup in the most prolific part of the reservoir. The upper units, however, have much higher permeability as compared to the lower units as shown in Figure 1. During the initial period of few years of production reservoir pressure dropped significantly. In order to arrest the decline in pressure, peripheral water injection was introduced in the field. As a result of high production rates from the upper units, the water front has advanced much further than in the lower units, which are of much lower permeability. This has induced uneven sweep of the major southern part of the reservoir as shown in Figure 2 for the upper and lower units.