An original technique to characterize naturally fractured reservoirs frompressure transient analyses

Author's Department

Petroleum & Energy Engineering Department

Document Type

Research Article

Publication Title

Society of Petroleum Engineers - International Petroleum Technology Conference 2012, IPTC 2012

Publication Date

5-25-2012

Abstract

This new technique is introduced to characterize all kinds of naturally fractured (secondary porosity) reservoirs, including carbonates, basements, and clastics on the Megascopic scale of well testing delineation. The technique is based on an original view of pressure transient data (buildup). In fact, this technique bridges between the Macro, Meso, and Megascopic scales of reservoir characterizations. Conventional well testing analysis techniques, e.g. Horner method, do not often work for naturally fractured reservoirssince they are based on a homogeneous reservoir model. In addition, all available techniques to characterize naturally fractured reservoirs from pressure transient analyses are very much theoretical models based on unrealistic geometrical assumptions. They lack practical applications and produce limited information. The new technique has the merit of working on real reservoir data. It utilizes pressure buildup data through the fact that formation fluids travel across different systems in heterogeneous naturally fractured reservoirs; matrix, fractures and the damaged area. A unique graphical characterization of shut-in well pressure versus time will illustrate the effect of fluid movements from the matrix system (or the tiny fractured system) through the main fracture system and across the damage area, if any, into the well. Fluid movements through each system are represented graphically. The technique is further optimized through application of pressure derivative methods to yield a very characteristic graphical representation (triangle)of each hydraulic "flow" unit in the reservoir. The presence of the triangle sides can be used to confirm the existence of a secondary porosity system (fractures) and/or damaged area. The slopes and intersection values of the straight lines are utilized into exclusive formulas to yield the most important petrophysical and engineering parameters about the heterogeneous naturally fractured reservoir (and, in many cases, other kinds of reservoirs) including: effective fractures, matrix and skin systems volumes, partitioning coefficient, fracture intensity index, formation resistivity factor, formation tortuosity, effective drainage radius, damage radius, effective cementation exponent, fracture porosity, matrix porosity, storativity ratio, in addition to fracture permeability, matrix permeability, damaged (skin) permeability, average permeability, pressure drop across the damage area, skin factor, damage permeability, average/dimensionless diffusivity factor, flow efficiency, damage ratio/factor, economic implication of formation damage, average hydraulic "flow" unit quality index. This document and presentation will cover the theory behind the technique and present actual field application examples. Copyright 2011, International Petroleum Technology Conference.

First Page

129

Last Page

147

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