Novel CO2-Emulsified Viscoelastic Surfactant Fracturing Fluid System
- Yiyan Chen (Schlumberger) | Timothy Lawrence Pope (Schlumberger) | Jesse C. Lee (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE European Formation Damage Conference, 25-27 May, Sheveningen, The Netherlands
- Publication Date
- Document Type
- Conference Paper
- 2005. Society of Petroleum Engineers
- 2.4.3 Sand/Solids Control, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.6 Natural Gas, 4.1.5 Processing Equipment, 4.3.1 Hydrates, 4.1.2 Separation and Treating, 5.2.1 Phase Behavior and PVT Measurements, 5.8.1 Tight Gas, 5.1.1 Exploration, Development, Structural Geology, 1.8 Formation Damage, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation
- 8 in the last 30 days
- 760 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 8.50|
|SPE Non-Member Price:||USD 25.00|
The solid-free viscoelastic surfactant (VES) fluid has good proppant transport and excellent cleanup capabilities. Coupling the benefits of a VES fluid with a carbon dioxide (CO)-emulsified system will further enhance cleanup in a depleted reservoir, extend the application to water-sensitive formations, and maintain reservoir gas saturation to prevent any potential water blocks. This paper reports on a new multisurfactant VES fluid system developed specifically to provide a robust surfactant-base fracturing fluid with supercritical CO. The field test results indicate the new system is CO compatible and still possesses all the attributes normally associated with VES systems.
Propped fracture stimulations are generally required to economically produce tight gas sands. Exploiting these reservoirs and maximizing financial returns require placing a fracture that exhibits a long effective half-length, exposes the reservoir to a minimum amount of water, and minimizes height growth into unproductive or water-bearing zones.
To achieve these goals the petroleum industry has utilized both nitrogen (N) and CO foams. As the required bottomhole pressure (BHP) increases, due to increases in fracture gradient and/or depth, nitrogen foam treatments experience high surface treating pressures relative to non-foamed/energized treatments. This increase in treating pressure is caused by the low hydrostatic pressure exerted by the nitrogen foam. Liquid CO provides hydrostatic pressure similar to that of water as well as more flowback energy than nitrogen, per unit volume. CO treatments have also been shown to reduce clay swelling and/or migration due to the low pH environment and aid in cleanup because of a reduced interfacial tension of the aqueous phase.[2,3]
The first treatments containing CO appeared in the 1950s. Containing no more than 50% CO, these treatments were not true foams. They were called energized fluids because at these lower concentrations a foam structure is not developed. In the 1960s CO treatments were pumped containing as much as 70% CO[2.5] This marked the emergence of true aqueous/CO foams. Whether technically correct or not, the industry has historically referred to these aqueous/CO mixtures as foams. However, since CO is pumped as a liquid at surface conditions, it would therefore be characterized as an emulsion. Under most common fracturing conditions it exists as a supercritical fluid, with densities ranging from 40 to 65 lbm/ft (Fig. 1). This complex fluid behaves somewhat like a gas, yet exhibits liquid-like densities. The situation is further complicated by the increasing solubility of CO with pressure in the aqueous phase and the solvent nature of supercritical CO. These properties affect chemistry in the aqueous phase as well as at the interface between the two phases. Creating a stable interface, and hence a stable fluid, under these conditions is critical to creating a robust, effective fracturing fluid.
|File Size||1 MB||Number of Pages||6|