A Logical Approach to Fracture Fluid Selection
Authors: Anderson H. , Bratrud T. , Delorey J. 
Published: March 2010

This paper presents a method of matching formation, rock and reservoir fluid characteristics to the properties of fracturing fluids for optimized stimulation treatments. Particular emphasis is placed on the role of the scanning electron microscope in formation characterization. The other rock and well properties can be determined utilizing standard industry practices. In addition to the traditional fracturing fluid parameters of rheology and fluid leak-off, the volatility, wetting tendencies, inter facial tensions and clay compatibility are discussed and are utilized in the selection process.

Introduction

Over the course of fracturing history, the decisions involved in choosing fracturing fluids have varied considerably. In earlier years, attempts were made to maximize created fracture area, with no real consideration for the geology and mineralogy of the reservoir. Rather, emphasis was placed on increasing the fracturing fluid efficiency and width generation capabilities.

It has long been known that certain fluids give substantially better results on a particular formation than other: fluids, but the success or failure of the fluid selection was largely due to experience.

With the advent of scanning electron microscopy, the emphasis shifted to damage occurring as a result of fracturing fluid interaction with authigenic materials in argillaceous reservoirs. The high demand for energy and the interest in low-permeability reservoirs have created a new mysticism involving clay mineralogy. This paper discusses a more detailed fracture selection process which will alleviate some of the misinterpretations.

Permeability analysis of formation cores has been an important factor in determining whether a well was capable of commercial production. The fact that measurements are made with gas at pressures significantly different from the formation pressure, however, causes large errors in permeability values, always on the optimistic side. In addition, if a well hasn't been cored it is difficult to obtain permeability data until production has been established, and obtaining production may require stimulation. Permeability values however, can only give

(Figure in full paper)

a partial picture of pore geometry which should be supplemented by SEM studies, capillary pressure measurements, core flow tests and relative permeability measurements.

The purpose of this paper is to combine geology, fluid flows and rock fluid interaction into a logical design process for fracture fluid selection. This process involves the microscopic properties of the rock, including permeability and fracture face damage, the formation heterogeneity, the formation pressures and saturation levels as well as the fracture fluid properties.

Sandstone Geology and Permeability

Permeability of a porous material characterizes the ease with which a fluid will flow with an applied pressure gradient. The physical parameters of a formation that contribute to permeability variances are the size and shape of the pore spaces, grain packing and fabric, and the degree of cementation. The fabric of a rock is the property concerned with the orientation in space of the component particles. Grains naturally tend to fall such that they lie with their greatest cross section in a horizontal pattern and with their longest axis parallel to water currents thus describing permeability as a directional property.