Wells – Processes – Chemical inter-reaction of two or more introduced materials
Reexamination Certificate
2001-02-14
2002-12-10
Suchfield, George (Department: 3672)
Wells
Processes
Chemical inter-reaction of two or more introduced materials
C166S308400, C507S244000, C507S265000, C507S267000, C507S277000, C507S904000, C507S922000
Reexamination Certificate
active
06491099
ABSTRACT:
BACKGROUND ART
1. Field of the Invention
This invention relates to the art of treatment fluids used in the recovery of hydrocarbon fluids from subterranean formations, and more particularly, to a fracturing fluid and method of fracturing a hydrocarbon-bearing formation.
2. Description of Related Art
Where hydrocarbons are being recovered from subterranean formations, it is common, particularly in formations of low permeability, to hydraulically fracture the hydrocarbon-bearing formation to provide flow channels to facilitate production of the hydrocarbons to the wellbore. Fracturing fluids typically comprise a thickened base fluid which primarily permits the suspension of particulate proppant materials in the fluid. Typical proppant materials include sand, sintered bauxite and the like. These materials will remain in place within the fracture when fracturing pressure is released thereby holding the fracture open. Such thickened fluids also aid in the transfer of hydraulic fracturing pressure to the rock surfaces and help to control leak-off of the fracturing fluid into the formation.
For many years, the most commonly used fracturing fluids comprised polymer thickened base fluids. The thickening polymers utilized were typically galactomannan gums, cellulosic polymers or synthetic polymers. It was generally necessary to cross-link the hydrated polymers in order to increase the viscosity and, thus, the proppant carrying capacity as well as to increase high temperature stability of the fracturing fluids. Typical cross-linking agents were borates or soluble organo metallic salts. Cross-linking or tying together of the polymer chains increases the viscosity and improves the rheology of the fracturing fluid.
In order to reduce the pumping friction pressure in such fluids, various methods of delaying cross-linking of the polymers have been developed. Delayed cross-linking allows the pumping of a relatively less viscous fracturing fluid having relatively low friction pressures within the well tubing. Cross-linking is then effected at or near the subterranean formation so that the previously mentioned advantages of the thickened cross-linked fluids are available downhole.
One disadvantage of the polymer thickened fluids was the necessity to hydrate the polymer at the well surface in a batch mix operation for several hours in a mixing tank or other container. It was often necessary to cross-link the polymer over a period of time to viscosify the fluid so that it is capable of carrying the proppant into the fracture. Natural polymers including polysaccharides, such as guar, have been used in this way in the past.
The hydration and cross-linking steps were time consuming and required expensive and bulky equipment at the wellsite. Such equipment, and the associated personnel to operate it, significantly increase the cost of the fracturing operation. Further once the polysaccharide is hydrated and crosslinked, it is generally not feasible to add additional polysaccharide to the solution, or to regulate the concentration of polysaccharide in the fracturing fluid during the pumping of the job.
The polymer based fluids of the type described also typically required a large number of additives in addition to the polymer, for example: bactericides, antifoam agents, surfactants to aid dispersion, pH control agents, chemical breakers, enzymatic breakers, iron control agents, fluid stabilizers, antioxidants, salts and the like. These materials must be formulated correctly, transported to the jobsite, and then pumped and metered accurately during the execution of the fracturing treatment.
Another difficulty with polymer-thickened fluids is the deposit and retention of polymer residues at the rock face and within the proppant pack. These characteristics can reduce the effectiveness of the fracturing operation. While there have been significant advancements in the use of oxidative or other breaker systems to reduce the effects of a polymer filter cake and other polymer residue within the fracture, such methods are always less than completely effective.
For example, during the course of a treatment, water from the fracturing fluid may leak into the formation leaving the polymer thickener behind. Concentrations of polysaccharide thickeners, such as guar, show dramatic increases as a factor of twenty as compared to the concentration of guar in the actual fracturing fluid. Many fracturing fluid materials, therefore, when used in large concentrations, have relatively poor “clean-up” properties, meaning that such fluids undesirably reduce the permeability of the formation and proppant pack after fracturing the formation. Well productivity after fracturing increases dramatically as the amount of polysaccharide returned to the surface increases.
One means of overcoming the effects of polymer residues remaining within a fracture would be to use a fracturing fluid that has components that allow themselves to associate, forming structures that are responsible for dramatically increasing the viscosity of the fluid. After the pumping into the fracture is completed, conditions within the fracture and fluid change, resulting in the loss of structure and consequently, viscosity. Example components capable of forming associating structures are certain surfactants. Thus, various emulsions of water and oil have been proposed. These surfactants, under specific conditions, can associate with one another to produce viscosified fluids having properties similar to polymer based fluids. Changes in pH or hydrocarbon content can then dramatically reduce viscosity without the need of traditional breakers and clean-up can occur unhindered due to the lack of proppant pack residue.
While structured surfactant based fluids offer certain advantages over traditional polymer based fluids, there remains room for improvement. These surfactant based fluids have tended to utilize expensive surfactants which were cost prohibitive in some instances. Cost limitations have resulted in the design of these structured fluids that can be characterized as marginal fracturing fluids. There have also been limitations on the temperature stability of such fluids, limiting treatment sizes to rather small fracturing treatments.
U.S. Pat. No. 5,964,295, issued Oct. 12, 1999, to Brown, et al., teaches a method and composition for treating subterranean formations utilizing a “viscoelastic fluid” which purports to overcome certain of the above-noted deficiencies of the prior art polymer containing fluids. However, the Brown fluid continues to be subject to temperature and stability limitations and forms emulsions which are oil wetting to the formation.
BRIEF SUMMARY OF THE INVENTION
An object of the present invention is to develop a surfactant based fluid with the ability to suspend proppants that is economical, having superior properties compared to existing product available on the market, as well as being more temperature tolerant.
The viscous fluids of the invention can be used for transporting particulate through a conduit to a subterranean location. In one form, the fluids comprise an aqueous base, a surfactant comprising an alkyl sarcosinate having from 12 to 24 carbon atoms and a buffer for adjusting the pH of the combined aqueous base and surfactant at or for the formation pH. The alkyl sarcosinate is preferably present in the range from about 0.5 to 10% by weight, based upon the weight of the total fluid. The pH of the viscous fluid is preferably adjusted with the buffer to be in the range from about 6.5 to 10.0 for most formations.
The viscous fluids of the invention can also include an additional source of anions in addition to those furnished by the surfactant. The additional source of anions can comprise a carboxylic acid salt present in the range from about 0.1 to 2% by weight, based upon the weight of the total fluid. The carboxylic acid salt, if present, is preferably selected from the group consisting of monovalent acetates, divalent fumerates, trivalent citrates and tetravalent EDTA. Alternatively, the additional source of anions comprises
Ahmad Atikah J. K.
Di Lullo Arias Gino F.
Rae Philip
BJ Services Company
Bracewell & Patterson LLP
Suchfield George
LandOfFree
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