Fracturing Fluids for Deep, Hot Formations

Summary

Cross-linked gels are adequately stable at high fluid temperatures and, thus, have established their usefulness for fracturing high-temperature formations. However, in certain treatment situations, they may develop high friction pressure in tubular goods, which can limit their injection rate. Furthermore, the rheological properties exhibit a timeshear history dependency that is difficult to predict.

Two-stage gel systems have been very successful in providing a means to develop desired viscosity at providing a means to develop desired viscosity at downhole conditions without causing high tubular friction pressures. However, several currently available systems do not have the stability required for large volume treatments at temperatures above 250 degrees F (120 degrees C).

A fracturing fluid has been developed that solves many disadvantages and limitations of both crosslinked and two-stage gel systems. This is made possible by the use of a new delayed hydrating gelling possible by the use of a new delayed hydrating gelling agent. The fluid has the desired two-stage viscosity qualities and can be formulated to provide the desired viscosity throughout a treatment. In addition, the rheological properties of the new fluid system are highly predictable.

This fracturing fluid system has been tested successfully in the field. Fluid design and treatment results are presented.

Introduction

The commercial success of massive hydraulic fracturing (MHF) in tight gas reservoirs has been well documented. For example, successful stimulation programs have been used to produce wells in the programs have been used to produce wells in the Cotton Valley Lime, Cotton Valley Sand, Edwards Lime, J Sand, and Mesa Verde Sand formations.

Recent renewed efforts to develop deep formations with temperatures exceeding 250 degrees F (121 degrees C) - such as the Silcos Sand, Grey Sand, Shannon Sand, and deep Cotton Valley Lime - have required that more stable fracturing gels be developed to place large quantities of proppant successfully. This is especially true for placing the higher density bauxite proppant required for most of these deep formations, where closure pressures could exceed 12,000 psi (82 MPa). Typical job volumes in these formations range from 80,000 to 800,000 gal (303 to 3030 m3) of gelled fluids with pumping time ranging from 3 to 14 hours.

Most fracturing fluid systems available for stimulation under these temperature and pumping- time conditions are based on the use of various pumping- time conditions are based on the use of various derivatized guar polymers as the basic viscosifying agents. The temperature stabilities of these polymers are functions of fluid pH, ionic strength, and the presence of added stabilizers. Many of the available presence of added stabilizers. Many of the available fluid systems also are cross-linked with one of a variety of metal cross-linking agents. In general, the ability to stabilize the base polymer will dictate the time/temperature stability of the system. Furthermore, the upper temperature limit for cross-linked systems may be less than that of the base polymer with the appropriate stabilizers and delayed hydrating polymer.

During recent efforts to improve MHF design, the critical role of viscosity control has been defined. Fluids with too little viscosity may suffer from excessive fluid loss, short propped length, narrow width, and premature proppant deposition. Fluids with too-high viscosity may create excessive fracture widths that can reduce the propped fracture length and cause high fracture friction pressure, which may result in premature job termination. Since each fluid increment experiences different fluid- temperature profiles, careful control of fracture viscosity requires the use of multiple fluid formulations.

Derivatized guar fluids can be used for treatments up to 250 degrees F (121 degrees C) without added stabilizers. The use of methanol and other stabilizers has extended the fluid stability to 350 degrees F (177 degrees C).

JPT

P. 2213