New Insights Into Fracturing Pressure Interpretation: Case Study Of Minifracture Tests In A Naturally Fractured Gas Reservoir
Authors: McLellan P.J. , Janz H.J. 
Published: March 2010

This paper presents a detailed analysis of three minifracs and an acid fracture treatment in a well completed in the Devonian Wabamun Formation near the boundary separating Shell Canada's Limestone and Burnt Timber gas fields in western Alberta. The purpose of this well test program was to gather data for the design of a large acid fracture treatment, if it could be shown to be economically feasible. The minifracs were pumped consecutively and were composed of plain water and combinations of gelled water, diesel. Silica flour and 100 mesh sand. Calculated bottomhole pressures are plotted against various time functions to determine the instantaneous shut-in pressure (ISIP), fracture closure pressure (FCP) and the leakoff behavior of various fluid systems. The importance of using FCP selection techniques based on the nature of the flow regime is demonstrated. The recently proposed fracture model of Shlyapobersky et al. is used to determine the total leakoff coefficients by a global least squares matching technique. Leakoff behavior is shown to be dependent on several factors including the choice of fluid additives, the fracture closure pressure or minimum in-situ stress, the presence of natural fractures and possibly the intermediate and major principal in-situ stresses. Anomalously high propagation pressures were observed during one of the minifracs. These high pressures are believed to have caused either natural fractures or secondary induced fractures to open, resulting in nearly an order of magnitude greater leakoff coefficient than was calculated for lower bottomhole pressures in an earlier test in the same well.

Introduction

The successful stimulation of wells completed in deep, low permeability, dolomite formations in the Canadian Foothills requires a consideration of fracture geometry and fracturing fluid leakoff behavior. In order to achieve long penetrating fractures with either acid-based or proppant-laden fluids an efficient but non-damaging fluid system is normally desired. The most common procedure for assessing the leakoff behavior, fracture geometry and fracture closure pressure present within a candidate fracture zone is to conduct a minifracture test using the actual pad fluid system proposed for the main treatment. Shell Canada's experience in stimulating such reservoirs has been recently described in papers by Milligan et al.(1,2).

Minifrac test procedures and interpretation has been the subject of considerable investigation and controversy over the last 10 years(2–12). Despite the extensive work on the topic and at least two international workshops on in-situ stress measurement many uncertainties often remain in the interpretation of hydraulic fracture injection tests. Several factors have been shown to influence the post shut-in, pressure decline behavior of vertical fractures including: fluid injection rate, fluid rheology, permeability, fluid leakoff additives, temperature, fluid compressibility, fluid pressure, minimum horizontal in-situ stress, and the opening of natural fractures. Interpretation techniques have improved considerably and there are now models available which address and correct for many of these effects which may obscure or distort the true fracture closure pressure and the total leakoff coefficient(11–13).

This paper presents a case history describing a series of minifracs followed by an acid fracture treatment on a shut-in gas well located near the boundary of Shell Canada's Limestone and Burnt Timber gas fields of western Alberta (Fig. 1).