Improved Prediction Of Reservoir Behavior Through Integration Of Quantitative Geological And Petrophysical Data
Authors: Davies D.K. , Vessell R.K. , Auman J.B. 
Published: December 2007

This paper presents a cost effective, quantitative methodology that has been successfully demonstrated to provide improved reservoir characterization and prediction of permeability, production and injection behavior during primary and enhanced recovery operations. The method is based on identifying intervals of unique pore geometry (rock type). This approach applies high level image analysis techniques of core material to quantitatively identify various pore geometries. when combined with more traditional petrophysical measurements on conventional core samples, various pore geometries (rock types) can be recognized from conventional wireline logs in non-cored wells or intervals. This allows the calculation of rock type and a superior estimation of permeability and saturation. Based on geological input, the reservoirs can then be divided into hydrodynamically continuous layers (flow units) and grid blocks for simulation.

An overview of the results obtained in a complex carbonate and a sandstone reservoir are presented. When combined with production data, the improved characterization and predictability of performance obtained using this unique technique has provided a means of targeting the highest quality development drilling locations, improving pattern design, rapidly recognizing conformance and formation damage problems, identifying bypassed pay intervals, and improving assessments of present and future value.

Introduction

This paper presents a technique for improved prediction of permeability and flow unit distribution that can be used in reservoirs of widely differing lithologies and porosity characteristics. The technique focuses on the use and integration of pore geometrical data and wireline log data to predict permeability and define hydraulic flow units in complex reservoirs. The two studies presented here include a low porosity, complex carbonate reservoir and a high porosity, heterogeneous sandstone reservoir These reservoir classes represent end-members in the spectrum of hydrocarbon reservoirs. Additionally, these reservoirs are often difficult to characterize (owing to geological complexity) and contain significant volumes of remaining reserves.

The technique described has been successfully used to characterize a wide range of other carbonate and sandstone reservoirs including tight gas sands (Wilcox, Cotton Valley Formations, Texas), moderate porosity sandstones (Middle Magdalena Valley, Colombia: San Jorge Basin, Argentina), and high porosity reservoirs (Offshore Gulf Coats and Middle East). The two reservoir studies presented here are funded by the US Department of Energy as part of the Class II and Class III Oil Programs for shallow shelf carbonate (SSC) reservoirs and slope/basin clastic (SBC) reservoirs. One objective of the program is to demonstrate advanced reservoir characterization tools that will result in a significant increase of reserves.

The techniques used for reservoir description in this paper meet three basic requirements that are important in mature, heterogeneous fields:The reservoir descriptions are log-based. Flow units must be identified using wireline logs because few wells have cores. However, because values of porosity and saturation derived from routine log analysis often do not accurately identify productivity in complex reservoirs, it is necessary to develop a log model that will allow for the prediction of another producibility parameter, in this case permeability.Use only the existing databases — no new wells will be drilled to aid reservoir description.The reservoir models are numeric (simulator-ready) and display the distribution of hydraulic flow units.

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