In the recovery of hydrocarbon values from subterranean formations, it has been common practice, particularly in formations of low permeability, to fracture the hydrocarbon-bearing formation to provide flow channels to facilitate production of the hydrocarbons to the wellbore. In such fracturing operations, a fracturing fluid is hydraulically injected down a well penetrating the subterranean formation and is forced against the formation by pressure. Through this procedure, the formation is forced to crack or fracture, and a proppant is placed in the fracture. The fracture provides a radially oriented, relatively high permeability channel in the formation offering improved flow of the recoverable fluid, i.e., oil, gas, or water, back into the wellbore. While a wide variety of fracturing fluids have been used, fracturing fluids customarily comprise a thickned or gelled aqueous carrier fluid which has suspended therein "proppant" particles which are substantially insoluble in the carrier fluid and the fluids of the formation. Proppant particles carried by the fracturing fluid remain in the fracture created, thus propping open the fracture when the fracturing pressure is released and the well is put into production. Suitable proppant materials include, but are not limited to, sand, walnut shells, sintered bauxite, or similar materials. As will be understood by those skilled in the art, the "propped" fracture provides a larger, more highly permeable flow channel to the wellbore through which an increased quantity of hydrocarbons can flow, thereby increasing the production rate of a well.
A problem common to many hydraulic fracturing operations is the loss of fracturing fluid into the porous matrix of the formation, particularly in formations of high permeability, e.g., formations having a permeability of greater than 2 md. Fracturing fluid loss is objectionable, not only because of cost considerations, but especially because it limits the fracture geometry which can be created in high permeability formations. In general, fracturing fluid loss depends on the properties of the rock in the formation, the properties of the fracturing fluid, the shear rate in the fracture, and the pressure difference between the fluid injected and the pore pressure of the rock matrix. In this regard, the properties of the fracturing fluid are those exhibited by the fluid in the formation as influenced, inter alia, by the temperature and shear history to which the fluid has been subjected in its travel down the wellbore and through the fracture.
Thorough analysis of the problem of fracturing fluid loss in high permeability formations reveals that it is necessary to reduce "spurt". As used herein, the term "spurt" refers generally to the volume of fluid lost during fracturing because of early leak off of fracturing fluid before pores of the formation can be plugged, and/or before an external filtercake is formed on the newly exposed rock surface. In the past, a variety of additives to the fluid have been employed, most being selected or designed to generate an external low-permeability filtercake quickly, under little or no shear stress (usually referred to as static conditions) in order to cover the pores and stop spurt. This approach is unsatisfactory since high shear stresses eliminate or severely limit the formation of external filtercake.
In general, the higher the permeability of a rock, the greater the fluid losses due to spurt are likely to be. However, it has been determined that during hydraulic fracturing, spurt occurs principally at or near the advancing tip of the fracture, where new rock surface is being generated. The shear stresses that the fracturing fluid exerts on the surface of the rock are greater proximate the tip of the fracture because of the narrower fracture gap in that location. As indicated previously, the high shear stresses prevent the formation of external filtercakes of polymer and/or fluid loss additives by eroding the surface of the cake in contact with the fracturing fluid. Accordingly, to be effective, a fluid loss additive must be able to stop spurt under high shear rates.
In fracturing high permeability formations, it is desired to develop fractures which are wide and high but which do not extend the great radial distance away from the wellbore as is common in the fracturing of relatively low permeability formations. In the design of high permeability formation fracturing, it is desirable to achieve a condition called tip screen-out after the fracture has opened the desired, relatively short, radial distance from the wellbore. Tip screen outs are achieved by allowing leakoff of the fracturing fluid into the formation to the point where there is insufficient fluid to suspend the associated proppant which the fluid is carrying. In order to accurately design such treatments for high permeability formations (greater than 50 milidarcies), it has been necessary to know the precise permeability of the formation so that tip screen out will occur at the desired point in the pumping schedule. If the formation permeability is not known or is only estimated by calculating the permeability of adjacent wells or similar formations, any variation in the actual permeability of the formation being treated will cause the fracturing treatment to deviate from that designed since the desired tip screen out may occur too early, too late or not at all, therefore not returning full value for the treatment performed. It would, thus, be desirable to be able to more accurately predict the formation permeability in high permeability formations or to temporarily alter the formation permeability to an accurately predictable value prior to or during the fracturing treatment so that the fracturing treatment can be executed in accordance with the desired design. The present invention addresses this desirable result.
Williamson et al., (U.S. Pat. No. 4,997,581) describe the prior art utilization of a variety of inorganic solids, natural starches, and combinations of finely divided inorganic solids with natural starches. All of these compositions are deemed by these patentees to be insufficient to control fracturing fluid loss in moderate to high permeability formations. While these patentees attempt to provide an effective additive by the use of blends of natural starches and modified starches, their blends have limited application. For example, for formations having high permeability and high temperatures, e.g., 300.degree. F., natural and modified starches may not effectively plug the pores in the fracture walls. Finally, additives suggested by other workers in the art, while providing some fluid loss control, often are prohibitive in cost.
Accordingly, there has existed a need for a low cost additive or fracturing fluid which provides fracturing fluid loss control, and a method of fracturing a subterranean formation characterized by reduced fluid loss, under a variety of conditions which include high permeability, high shear rates and high temperature. The invention answers this need.