Integration of the PLT and PBU Data in Permeability Modeling Workflow

Abstract

Abstract Permeability prediction always constitutes a challenging step in the modeling process. Reservoir heterogeneity such as diagenesis, fracturing and effective connected geobodies are the main factors complicating the prediction. Hence, limiting permeability model to core data only could lead to unsatisfactory results while history matching. As consequence, poor reservoir performance prediction will be obtained. In such circumstance, further permeability enhancement using PBU and PLT data are usually needed. The Core or log derived Permeability captures the heterogeneity around the wellbore whereas well test data describes the reservoir in accordance with the radius of investigation. In addition to that, the measured core permeability is absolute while the fluid flow in the reservoir is governed by the effective permeability which is captured by well test data. Having the advantage of continuous monitoring program including PLT and PBU constitute a precious and considerable piece of data. These amounts of PLTs allow capturing the vertical heterogeneity in the reservoir while the PBU tests give better areal distribution of the KH test. A ratio of KH test over KH core can be calculated and usually assumed as a good indicator of presence of fractures. In this case, an appropriate Discrete Fracture Network (DFN) model is required to build the permeability model. However, if the ratio is indicating matrix contribution a more simplistic approach can be applied and gives reasonable results. By identifying the contributing intervals from PLT results coupled with the KH test over KH core ratio, the core permeability is then elevated to the test permeability. The objective of this work is to present the application of this approach in different blocks in one giant gas field which shows improvement in the permeability prediction; results are supported by dynamic analytical model performance. Introduction Estimating effective permeability at reservoir scale is a challenging task especialy in carbonates due to the fact that their depositional process and the diagenetic history can be very complex, resulting in heterogeneity of the pore system. In addition to that, fractutres can occure in the reservoir leading to additional difficulties to characterize the permeability. As consequence of that, high permeability intervals can be developed at different scale, those streaks might not be captured by core and log data.