Enhanced Aqueous Fracturing Fluid Recovery from Tight Gas Formations: Foamed CO2 Pre-pad Fracturing Fluid and More Effective Surfactant Systems
Authors: Tamayo H.C. , Lee K.J. , Taylor R.S. 
Published: March 2010

Abstract
Under pressured, tight, deep formations represent a challenge in terms of recovery of fracturing fluids. CO2, N2 and binary high quality foams are widely used in this type of reservoir due to their capacity to energize the fluid and improve total flowback volume and rate. Surfactants designed to reduce surface and interfacial tension are also a key element in the design of fluid systems to enhance recovery and reduce entrapment of fluid barriers within the formation. Enhanced fluid recovery improves overall completions economics due to less total treatment cost and less time required for flowing back fluids. The most important benefit is achieving a less damaged proppant pack, resulting in higher fracture conductivity.
This document will discuss the application of CO2 foamed fluids and surfactants to enhance fracturing fluid recovery and other techniques adopted by one operator in the Wild River Field to improve completion practices.

Introduction
Unconventional gas-in-place in Canada (not including gas hydrates) has been estimated at approximately 2,589 Tcf; 1,500 Tcf of these reserves correspond to tight gas(1). Achieving optimum development of these reserves is challenging due to the low permeability (&lt; 0.1 mD) and abnormal pressures that characterize tight gas sands. The challenges are both technical and economic. Unconventional reservoirs, in general, require higher capital expenditure compared to conventional reservoirs(2). Commercial rates are, in most cases, achieved by hydraulically fracturing pay zones. The perfect fracturing job in these cases would consist of an inexpensive, long fracture with infinite conductivity, 100% propped, 100% effective length, and contained in the pay zone with 100% fluid recovery. However, realistically we know that a tight gas-bearing zone faces abnormal pressure, low permeability, clay swelling and migration, capillarity effects, near-wellbore restrictions and formation complexity and heterogeneities. These characteristics usually result in damage from drilling and cementing operations, water phase trapping, screenouts, proppant not carried to the far field, dehydrated polymer, etc.
This paper will review different practices that are proving to mitigate some of these problems, focusing on enhanced fracturing fluid recovery with the aid of high-quality CO2 foamed fluid as a pre-pad and the addition of solvents/surfactants. The experience gained after performing 192 fracturing jobs in the Cadomin Formation, Wild River Field in central Alberta will help illustrate the benefits of the practices recommended in this document.

Description: Cadomin Formation, Wild River Field
The practices described in this document are based on the experience acquired fracturing in the Cadomin Formation of the Wild River Field in Alberta, Canada (Figure 1). The Cadomin Formation is a deep basin, tight gas formation with NW-SE trending, usually the lowest reservoir in sequence, and consequently, highly stressed. The Cadomin Formation is a braided channel deposit, sourced by conglomeratic and sandstone alluvial fans to the west. This zone is present in every Wild River well(3). The common reservoir parameters of the Cadomin Formation are presented in Table 1.
FIGURE 1: Wild River Field location(3).
Table 1: Reservoir properties.