Developing High Resolution Static and Dynamic Models for Waterflood History Matching and EOR Evaluation of a Middle Eastern Carbonate Reservoir

Abstract

Enhanced oil recovery (EOR) has become increasingly important to maintain and extend the production plateaus of existing oil reservoirs. Simulation models for EOR studies require the right level of spatial resolution to capture reservoir heterogeneity. Data acquired from the dedicated observation wells are essential in defining the required resolution to capture reservoir heterogeneity. For giant reservoirs with long production history, their full field models usually have grid block sizes that are of similar scale as the distance between injectors and observation wells, with the consequence of losing the value of the time lapse saturation logs from dedicated observation wells. Therefore, using high resolution sector models, especially from the part of the reservoir where static and dynamic data sets are rich, is a must.The objective of this paper is to present an improved and integrated reservoir characterization, modelling and water and gas injection history matching procedure of a giant Cretaceous carbonate reservoir in the Middle East. The applied workflow integrates geological, petrophysical, and dynamic data in order to understand the production history and the remaining oil saturation distribution in the reservoir. Large amounts of field data, including time lapse saturation logs from observation wells, have been collected over the last decades to provide insight into the sweep efficiency and flow paths of the injected water.Iterative simulations were performed to investigate different scenarios and various sensitivities with each iteration involving an update of the static model to honor both the dynamic and core/log data. While applying this iterative process it was also acknowledged that conventional core data (e.g. 1 plug per foot) may not capture the high permeability streaks in these heterogeneous reservoirs that control much of the reservoir flow behaviour, hence much denser plugging and core examination is required. In addition, permeability upscaling procedures need to take into account the fact that core plugs may not represent the effective permeability of the larger connected vuggy pore systems.The improved understanding of reservoir heterogeneity, the more robust reservoir characterization, and the improved history matching demonstrates that a better representation of reservoir dynamics is achieved. This provides a solid platform for designing and planning future EOR schemes.

Analysis and Simulation of Polymer Injectivity Test in a High Temperature High Salinity Carbonate Reservoir

“…The reservoir is a Lower Cretaceous carbonate formation characterized by relatively high heterogeneity and stratigraphic cyclicity [ 21 ]. Reservoir’s average thickness ranges from 45 to 90 m. The major challenge that drove toward considering polymer flooding option in this reservoir is that it is divided into two main layers that have significant permeability contrast [ 22 ].…”

“… Parameter Value Reservoir temperature 120 °C Bubble point pressure 14,755 kPa Oil density 815.18 Kg/m 3 Oil viscosity 0.32 mPa.s Water density 1174.79 Kg/m 3

Figure A1 Oil-water relative permeability and capillary pressure curves for permeability above 100 mD (Modified and adapted from [ 21 ]).

Figure A2 Oil-water relative permeability and capillary pressure curves for permeability below 100 mD (Modified and adapted from [ 21 ]).

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“… Oil-water relative permeability and capillary pressure curves for permeability below 100 mD (Modified and adapted from [ 21 ]). …”

Updated Perceptions on Polymer-Based Enhanced Oil Recovery toward High-Temperature High-Salinity Tolerance for Successful Field Applications in Carbonate Reservoirs

“… Two polymer-based cEOR field pilots is commenced by in two reservoirs which are presently undergoing water-flooding. The targeted reservoirs cover multiple fields in Abu Dhabi [ 176 , 212 ]. The target reservoirs have high temperatures ranging from 100 C to 130 C, high-salinity formation brine of around 200,000 ppm, and high concentrations of divalent ions (Ca and Mg ) of around 18,000 ppm, with a carbonate reservoir formation.…”

A Novel Energy Lifting Approach Using J-Function and Flow Zone Indicator for Oil Fields

“…Building a robust reservoir dynamic model relies on reservoir characterization and energy management as well as reliable predictions. In order to proceed to SCAL analysis such as P c curves, it is vital to define rock types, reservoir quality, zonation, and heterogeneity through conventional core analysis and relate it to the geological facies and SCAL interpretation [19][20][21][22].…”