In this new fracturing method, high-viscosity fracturing fluids are used to obtain greater fracture length and width. The technique is characterized by higher propagation pressures and lower fluid loss at the fracture face. A film of water surrounding the fracturing fluid reduces friction losses in the tubing, and this lowers surface treatment pressures and pumping power requirements. Introduction A new method has been developed in which high-viscosity fracturing fluids are used for stimulating production from formations having a wide range of production from formations having a wide range of permeabilities. The fluids that have been used to date permeabilities. The fluids that have been used to date have ranged generally from about 500 cp to about 100,000 cp at ambient temperatures. The new method is used commercially under the names "Superfrac", "Super Frac", and "Super Sand Frac". The preferred fluids for use in the new method are loose water-in-oil dispersions or emulsions prepared by blending brine and a surface-active agent into a crude oil or petroleum fraction that has these high viscosities. When properly prepared, these emulsions will not readily change composition in the presence of free water. The emulsions are isolated from the inner wall of the tubing string or casing by a film of free water during injection and are generally pumped with about the same pressure drop as 1-cp oil or water. Studies indicate that the free water is lost to the formation after the fluids enter the fracture and that the high viscosity fracturing fluid remains behind for propagation of the fracture and placement of the propping agent. propping agent. This technique can be used to fracture any formation, but it has particular advantageswhen a large fracture conductivity ratio cannot be realized with small proppants,when thick or high-permeability formations are to be fractured,when a well must be fractured through small-diameter tubing or casing, andwhen proppant must be carried great distances from the wellbore. This paper gives the relationships of fluid viscosity to fracture geometry and proppant placement, establishes the advantages of using high-viscosity fluids for stimulating high- and low-permeability formations, and tells how the high-viscosity fluid system is maintained and pumps and Field tests have shown that excellent, sustained productivity increases have been obtained with this new hydraulic fracturing process. Fracture Geometry The use of very viscous oils as fracturing fluids has several benefits, including good fluid-loss control, increased fracture width, and improved sand transport. Fluid Loss Control Since Howard and Fast showed that the rate of fluid leakoff from a fracture depends upon the resistance of the invaded zone, the resistance of the filter cake, and the resistance of the compressible formation fluids, much of the work on fracturing has been directed toward the use of water-based fluids that can be injected at high rates and toward the development of better fluid loss control additives. Results to date indicate that gelled fluids and other water-based systems generally have low viscosities under the temperature and shear conditions existing in most fractures, and also that fluid loss control additives are normally much less effective under dynamic filtration conditions than they were once thought to be. Increased fluid loss can explain many of the difficulties encountered in conventional fracturing operations. JPT P. 89
A new hydraulic fracturing system has been developed and tested in both oil and gas wells. The fluids used are viscous polymer emulsions made from commonly available lease fluids such as crude oil and brine. By varying the oil and polymer content, the properties of the system can be easily controlled. Relative to other viscous fluid systems, for comparable results the costs are much less. Summary and Conclusions In the past 5 years, viscous fracturing fluids have been shown to have advantages over conventional, low-viscosity gelled-water fluids. Many viscous fluid systems were developed and tested with various degrees of success. The main limitations of those fluids are their high cost and, in some instances, the difficulty of removing the fluid from the formation.A new hydraulic fracturing system has been developed and tested under a variety of field conditions in both oil and gas wells. Fluids used in this system are viscous emulsions prepared with a lease crude, refined oil, condensate or liquefied petroleum gas as the internal phase, and water, brine, or acid containing a water-soluble polymer and a surfactant as the external phase. This adaptable fluid system is inexpensive, its properties can be controlled, and it breaks readily after the treatment, permitting the injected fluids to be easily produced from the formation.Properties of these emulsion fluids are controlled by varying the polymer concentration in the water and the volume of oil in the emulsion. Sufficient polymer is used to provide the aqueous phase with an polymer is used to provide the aqueous phase with an apparent viscosity from 10 to 100 cp at 75 degrees F and at a shear rate of 511 sec(-1). The concentration of the dispersed oil phase is maintained between 50 and 80 volume percent.For field applications, the preferred emulsion contains from 60 to 75 volume percent oil and from 1 to 2 lb of guar per barrel of water or brine. This composition is generally chosen since it can be emulsified easily and allows for a margin of mixing error. The fluid viscosity will be too low if the oil content is 50 percent or less, and the emulsion may become unstable or too viscous if the oil content is greater than 80 percent.A surface-active emulsifier capable of forming an oil-in-water emulsion is added to the aqueous phase at a concentration of about 0.5 percent by weight to help form the emulsion and temporarily stabilize its properties. The two basic types of surfactants used properties. The two basic types of surfactants used for this application are sodium tallate (for fresh water) and a quaternary amine (for brine; i.e., water containing more than 10,000 ppm chlorides). A fluid loss additive (FLA) - normally a mixture of silica flour and a commercial additive composed of particles coated with a water-soluble polymer - may be added at a concentration of 20 to 40 lb per 1,000 gal of emulsion.Polymer emulsion fracturing resulted in an average production increase of 3.4 for 97 Exxon Co. U.S.A. production increase of 3.4 for 97 Exxon Co. U.S.A. oil and gas wells treated in 1971 and 1972. Clean-up after these treatments was rapid and most gas wells were placed back on production without swabbing. P. 731
Waterflooding is the oldest and by far the most important method used by the petroleum industry to increase recovery from both onshore and offshore reservoirs. Waterflood design is a complex problem that must ultimately be handled on an individual reservoir basis. This paper presents factors that should be considered in designing both onshore and offshore waterfloods. The need for careful examination of the following factors is discussed: Reservoir geology and method of depositionPrimary production mechanisms and stage of depletionReservoir and fluid propertiesReservoir pressureWell spacing and possible waterflood patterns After these factors are discussed, the effects that pattern selection, timing and injection/producing rates have on project economics are discussed. A special emphasis is placed on offshore waterflooding since it is now of significant concern.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.