IMPROVED FRACTURING FLUID AND METHOD OF USE FIELD OF THE INVENTION [0002] Improved aqueous fracturing fluids which are particularly useful as well as stimulation fluids for fracturing hermetic (i.e., low permeability) underground formations have now been discovered. Gas wells treated with these fracturing fluids have rapid cleanup and improved well production. Fluids contain small but sufficient amounts of certain amine oxides to aid in the removal of fracturing fluid from the formation. By facilitating the removal of fluid from the invaded areas, the amount of damage to fracture surfaces in the formation is minimized. BACKGROUND OF THE INVENTION Various amine oxides have been used as surfactants to create foams and remove "borehole intrusion fluids", according to USP 3,303,896, and have been used as foamable stabilizers according to USP 3,317,430. Certain amine oxides have also been used in combination with quaternary ammonium compounds as foaming and slurry suspension agents. See, for example, USP 4,108,782 and USP 4,113,631. The use of amine oxide surfactants for the extraction of improved petroleum by chemical overflow was described in a topical report by David K. Olsen in NIPER-417 (August 1989) for a work done for the US Department of Energy under the agreement of DE-FC22-83FE60149 cooperation by the National Institute for Petroleum and Energy Research. However, to the knowledge of the applicants, the amine oxides have not been used to improve the properties of the fracturing fluids and to promote rapid cleaning, or to improve the production of the well from a well stimulated by hydraulic fracturing . Hydraulic fracturing of underground formations has long been established as an effective means of stimulating the production of hydrocarbon fluids from a well. In hydraulic fracturing, a well-stimulation fluid (usually referred to as fracturing fluid or "frac fluid") is injected into and through a borehole and against the surface of an underground formation penetrated by the borehole at a pressure at least enough to create a fracture in the formation. Commonly, a "filler fluid" is injected first to create the fracture and then a fracturing fluid, often containing granular propping agents, is injected at a sufficient pressure and proportion to extend the fracture from the sounding more deeply into the formation . If a supporting agent is employed, the goal is usually to create an area full of supporting agent (aka, the supporting agent package) from the tip of the back of the fracture to the sounding. In any case, the hydraulically induced fracture is more permeable than the formation and acts as a route or conduit for the hydrocarbon fluids to flow towards the borehole and then to the surface where they are collected. Fracturing methods are well known and can be varied to meet the needs of the user, but they should follow this general procedure (which has been greatly simplified). The fluids used as fracturing fluids have also varied, but many if not most are water-based fluids that have been "viscosified" and thickened by the addition of a natural or synthetic polymer (cross-linked or non-crosslinked). The carrier fluid is commonly water or a brine (e.g., diluted aqueous solutions of sodium chloride and / or potassium chloride). The viscosification polymer is typically a solvatable (or hydratable) polysaccharide, such as a galactomannan gum, a glicomannan gum, or a cellulose derivative. Examples of such polymers include guar, hydroxypropyl guar, carboxymethyl guar, carboxymethylhydroxyethyl guar, hydroxyethyl cellulose, carboxymethyl hydroxyethyl cellulose, hydroxypropyl cellulose, xanthan, polyacrylamides and other synthetic polymers. Of these guar, hydroxypropyl guar and carboxymethylhydroxyethyl guar are typically preferred due to their commercial availability and cost performance. In many instances, if not most, the viscosification polymer is crosslinked with a suitable crosslinking agent. The crosslinked polymer has an even higher viscosity and is even more effective as a carrier of the supporting agent in the fractured formation. Borate ion has been widely used as a crosslinking agent, typically in high pH fluids, for guar, guar derivatives and other galactomannans. See, for example, USP 3,059,909 and numerous other patents describing this classical aqueous gel as a fracture fluid. Other crosslinking agents include, for example, titanium crosslinkers (USP 3,888,312), chromium, iron, aluminum and zirconium (USP 3,301,723). Of these, titanium and zirconium crosslinking agents are typically preferred. Examples of commonly used zirconium crosslinking agents include zirconium complexes triethanolamine, zirconium acetylacetonate, zirconium lactate, zirconium carbonate, and chelating agents of organic alphahydroxycarboxylic acid and zirconium. Examples of commonly used titanium crosslinking agents include complexes of titanium triethanolamine, titanium acetylacetonate, titanium lactate, and chelating agents of organic alphahydroxycarboxylic acid and titanium. Additional information about fracturing is found in the description by Janet Gulbis and Richard M. Hodge in Chapter 7 of the text "Reservoir Stimulation" published by John iley & amp; amp; amp;; Sons, Ltd., Third Edition, 2000 (Editors, Michael J. Economides and Kenneth G. Nolte), which is incorporated herein by reference. Some fracturing fluids have also been energized by the addition of a gas (e.g., nitrogen or carbon dioxide) to create a foam. See, for example, the pioneering work by Ronald E. Blauer and Clarence J. Durborow in USP 3,937,283 ("Formation Fracturing with Stable Foam"). The rheology of the traditional water-based polymer solutions and also the complex fluids, such as foams, can typically be modified and augmented by various additives to control their operation. Typically, fluid loss additives are added to reduce the loss of fracturing fluids in the formation. The problems associated with the loss of fracturing fluid in the formation are well known. For example, Holditch 1978 reported: "The fluid injected during the fracturing treatment will leak out in the formation and reduce the relative permeability to the gas in the invaded region.Following the fracture, the gas permeability will be reduced to zero." Additionally, Holditch said: "In some cases, the injected fracturing fluid can reduce the permeability of the formation in the invaded zone." Stephen A. Holditch, SPE 7561 (Presented at the 53rd Annual Technical Conference and Exhibition of the Society Petroleum Engineers of AIME, held in Houston, Texas, October 1-3, 1978). The damage to the formation could be severe, and in practice it is a reduced flow of hydrocarbons, low production and low economy in the well. Although the state of the art has advanced substantially since Holditch reported the problems associated with fracture fluid leakage, the problems remain the same. See, for example, Vernon G. Constien, George. Hawkins, R. Prud'homme and Reinaldo Navarrete, Chapter 8, entitled "Performance of Fracturing Materials" and the other chapters on fracturing and well stimulation in "Reservoir Stimulation" published by John Wiley & Sons, Ltd., Third Edition, property rights Schlumberger 2000 (Editors, Michael J. Economides and Kenneth G. Nolte), whose description is incorporated herein by reference. These authors and others emphasize the importance of "cleaning" or "fracture cleaning" to optimize the production of hydrocarbon fluids from the well. The term "cleaning" or "fracture cleaning" refers to the process of removing the fracturing fluid (without the supporting agent) from the fracture after completing the fracturing process. Techniques to promote fracture cleaning frequently involved reducing the viscosity of the fracturing fluid so that it would flow more easily back into the borehole. The so-called "ruptores" have been used to reduce the viscosity of the fluid in many instances. The breakers can be enzymes (oxidants and oxidant catalysts), and can be encapsulated to delay their release. See, for example, USP 4,741,401 (Walles et al) assigned to Schlumberger Dowell and is incorporated herein by reference. Another technique for assisting in cleaning, although by a contrary procedure, is found in USP 6,283,212 (Hinkel and England), which was also assigned to Schlumberger Dowell and incorporated herein by reference. There is still a need for improved fracturing fluids, and the need is met at least in part by means of the following invention. SUMMARY OF THE INVENTION [0002] Improved aqueous fracturing fluids which are particularly useful as well as stimulation fluids for fracturing hermetic (i.e., low permeability) underground formations have now been discovered. The gas wells treated with these fracturing fluids have a fast cleanup and improved well production. The fluids contain small but sufficient amounts of certain amine oxides to assist in the removal of the fracturing fluid from the formation. By facilitating the removal of fluid from the invaded areas, the degree of damage to fracture surfaces in the formation is minimized. The amine oxides correspond to the formula
(formula 1) wherein R x is an aliphatic group of from 6 to about 20 carbon atoms, and wherein R 2 and R 3 are each independently alkyl of from 1 to about 4 carbon atoms. Amine oxides are preferred in which R; is an alkyl group, and those in which Rx is an alkyl group of from 8 to 12 carbon atoms (in particular where x is a linear alkyl group), and are more preferred wherein R2 and R3 are each methyl groups or ethyl. BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 is entitled Gas permeability vs. Chain length This Figure illustrates Percent Recovery Percent vs. the Chain Length of the aliphatic group, Ri of various amine oxides. DETAILED DESCRIPTION OF THE INVENTION The amino oxides used in the present invention are known compounds and many are commercially available. They can be produced by various methods, one of which is by contacting a tertiary amine (corresponding to the formula R? R2R3N, where Ri, R2 and R3 are as defined above) with a peroxide in a suitable aqueous reaction medium. The products thus produced are aqueous liquids having amine oxides in a concentration of up to 30 percent by weight. Aqueous solutions of the amine oxides are an easy and preferred form of the product of this invention, because they can be easily pumped or otherwise measured in the fracturing fluid, or mixed with the other components of the fracturing fluid. Examples of the amine oxides of the above Formula I include, but are not limited to, those in which Ri is a straight chain alkyl group of 8 to 20 carbon atoms (eg, octyl, nonyl, decyl, dodecyl, tetradecyl , octadecyl, and the like) or a straight chain alkenyl group of from 18 to 20 carbon atoms (eg, oleyl, erucyl, and the like) and R2 and R3 are each methyl, ethyl, n-butyl or 2-methyl groups; -hydroxyethyl. The most preferred amine oxides are n-octyldimethylamine oxide and n-decyldimethylamine oxide. Although all the amine oxides of the formula I could reasonably be classified as surfactants, many are known as foaming agents, but preferred amine oxides for use in the present invention (eg, n-octyldimethylamine oxide and n-decyldimethylamine oxide) ) are not particularly efficient foaming agents. For example, preferred amine oxides have a half-life in foam of less than one (1) minute when tested in aqueous 2% potassium chloride solution (2% KCT), 3% hydrochloric acid, aqueous chloride solution of 0.2% teramethylammonium or API brine. The half-life in foam is determined by the analyzes as described in USP 4,108,782, columns 5 and 6, under the headings "Initial Foam Volume Test" and "Foa Half-Life Test", the description of which is incorporated herein by reference . Therefore, the preferred amine oxides do not promote the formation of emulsions (the foams are a type of emulsion) in the presence of the forming fluids and provide a desirable change (i.e., increase) in the contact angle. The amine oxides are added to the fracturing fluids in small but sufficient amounts to promote rapid cleaning. Typically, they are added as an aqueous solution in amounts of from about 0.01 to about 1 percent by weight of the amine oxide, on a weight-for-weight (w / w) basis, and preferably from about 0.006 to about 0.024 percent. by weight. The amine oxides can be added "on the fly" to the fracturing fluid while pumping in the sounding or the amine oxides can be added to the so-called "fracturing tank" containing the mixing water for the fracturing fluid. The order of addition of the amine oxide to the fracturing fluid is not critical. The amine oxides appear to be compatible essentially with all the ingredients of the fracturing fluid, as far as the inventors know. They are compatible with acids (such as hydrochloric acid) and, consequently, can be used in so-called "acid fracturing" jobs where an aqueous acid is used as a fracturing fluid (commonly with acid inhibitors present). The amine oxides are also compatible with bases, and can be used in fracturing fluids having a basic pH which are common in fracturing fluids containing guar or guar derivatives (eg, hydroxypropyl guar ("HPG"), carboxymethyl guar, carboxymethylhydroxypropyl guar ("CMHPG")) as viscosifiers; these fluids can be crosslinked with borates or zirconium or titanium crosslinking agents as well as other species). Fracturing fluids typically have a pH range of from about 4 to about 12, and the amine oxides can be used in such fluids. Fracturing fluids with a basic pH tend to be thermally more stable, and therefore are generally preferred for use in the fracturing of low permeability formations. The fracturing fluids of the present invention may also contain other additives typically found in fracturing fluids. E.g., sustaining agents, other fluid loss additives, non-emulsifiers, breaker systems, formation stabilizers, bactericides, and the like. The fracturing fluids of the present invention are used according to known methods for fracturing underground formations. See, for example, the fracturing procedures described in the text "Reservoir Stimulation" cited above. EXAMPLES OF THE INVENTION The following examples will further illustrate the invention: Example 1-9: Various amine oxides, and a commercial fluorocarbon surfactant (identified as F75N, not an example of the invention), were analyzed in certain fluids in flow tests core using the procedures described below. The amine oxides each corresponded to Formula I:
wherein R 2 and R 3 are each methyl, and R x is n-octyl, n-decyl, n-dodecyl, n-tetradecyl, n-hexadecyl, oleyl, erucyl (the last two groups are alkenyl groups of 18 and 22 atoms carbon, respectively). The data is illustrated in Figure 1 where the open circles correspond to the recovery of flow with a flow of brine, and the solid squares to the recovery of flow with nitrogen. Detailed kernel flow procedures are provided below. The data shows that the amine oxides provide a percentage recovery that differs with the chain length of the aliphatic Rx group in the amine oxide. Surprisingly, those amine oxides in which the aliphatic Rx group had 8 or 10 carbon atoms worked better (ie, had a higher percentage recovery) than the commercial surfactant F75N, one of the best additives in the industry to promote rapid cleaning . The data in Figure 1 also shows that the degree of cleaning or recovery of permeability can be modified by selecting an amine oxide with different chain lengths for the aliphatic Rx group. This provides the user with a means to vary the proportion at which cleaning is achieved and at which the well is produced. For example, if it is desired to achieve a rapid cleaning and production ratio, the user would select an amine oxide with a less carbon number for Rx (e.g., n-octyl or n-decyl). If the user wants a lower cleaning ratio (to prevent, for example, the channeling and possible incomplete return of the fracturing fluid), then the user could select an amine oxide with a higher number of carbons for R (eg, n-hexadecyl or n-octadecyl or oleyl). It is expected that mixtures of such amine oxides could also be used to achieve any particular desired cleaning result. The ability to vary the proportion of the returned flow, and achieve a predictable and controllable means to clean stimulation fluids to improve post-treatment gas permeability, is a useful tool in the engineer's arsenal. Amine oxides are environmentally more
"friendly" than the commercial fluorocarbon surfactant
(F75N) and they are effective in cost. It was also noted that the amine oxides in which Ri has a higher number of carbons (e.g., 16 to 18 or more) were viscoelastic as well as surface active. This combination of surface activity and viscoelasticity makes these amine oxides effective in well treatments where reduction of friction and good cleaning are particularly desirable. A leading industry provides such fracturing fluids (i.e., aqueous viscoelastic fluids that do not contain guar or any guar derivative) under the identity of "polishing water" treatments. Core Flow Procedures for Evaluation of Amine Oxide Brine flow: 1. Pre-permanent dry nuclei with N2 to equalize nuclei. 2. Cores saturated in DI water with 2% NaCl. 3. Determine the initial permeability for 2% NaCl with the flow in the direction of advance for a total of 25 pore volumes. 4. Pump the surfactant solution in the reverse direction for a total of five (5) pore volumes. 5. Determine the recovered permeability for 2% NaCl in the forward direction for a total of 25 pore volumes. 6. Determine the proportion of recovered permeability of 2% NaCl for the initial permeability of
2% NaCl. Kerosene flow: 1. Pre-permanent dry nuclei with N2 to equalize the nuclei. 2. Cores saturated in DI water with 2% NaCl. 3. Determine the initial permeability for 2% NaCl with the flow in the direction of advance for a total of 25 pore volumes. 4. Pump the surfactant solution in the reverse direction for a total of five (5) pore volumes. 5. Determine the permeability recovered for kerosene in the forward direction for a total of 25 pore volumes. 6. Determine the proportion of the permeability recovered from kerosene for the initial permeability of 2% NaCl. Nitrogen flow: 1. Pre-permanent dry nuclei with N2 to equalize the nuclei. 2. Cores saturated in DI water with 2% NaCl. 3. Determine the initial permeability for 2% NaCl with the flow in the direction of advance for a total of 25 pore volumes. 4. Pump the surfactant solution in the reverse direction for a total of five (5) pore volumes. 5. Determine the permeability recovered for nitrogen in the forward direction at 100 psi for a total time equivalent to 25 pore volumes of brine at 1.0 ml / min (+/- 140 minutes). 6. Determine the proportion of the permeability recovered for the initial permeability of 2% NaCl. Pore Volume Calculations: Assumption:
The porosity is 15%. Equation of Volume: CV =. { 3.1416 (D2) L} / 4 PV = CV (porosity) / 100 Where PV is the Pore Volume in ce, CV is the Kernel Volume in ce, D is the Kernel Diameter in cm and L is the Kernel Length in cm. The above equation with the assumed porosity of 15% produces a pore volume of 1.93 ce per one inch of core length. For simplicity, the pore volume will be rounded up to 2.0 ce per inch of core length. Example 10: A gas well is drilled in the Lobo 6 formation west of Texas at a depth of approximately 9,400 feet. The exploitation zone is found in a low permeability sandstone. The lower orifice temperature is approximately 240 ° F and the reservoir pressure is approximately 4,450 pounds per square inch (psi). The well is conventionally cemented and drilled using 4 shots per foot of interval. The well is broken with dilute hydrochloric acid and agglomerated. All perforations seem to accept the fluid. The well is then stimulated by fracture by sequentially injecting, at a pump rate of 28 barrels per minute (BPM), a filling fluid, a fracturing fluid containing suspending agent, and an influx according to the pumping scheme in Table 1 below:
Fluid A is an aqueous polymer solution of a guar derivative (CMHPG at 40 pounds polymer per 1,000 gallons of fracturing fluid), which contains a zirconate crosslinker, a high temperature gel stabilizer, a clay stabilizer and pH buffering agents. Fluid B is an aqueous polymer solution of a guar derivative (CMHPG at 35 pounds of polymer per 1,000 gallons of fracturing fluid), which contains a zirconate crosslinker, a high temperature gel stabilizer, a clay stabilizer and a switch for the gel polymer. The Fluids A and B further comprise the addition of n-decyl-N-dimethylamine oxide so that each modified fluid contains the amine oxide at a concentration of 0.1 percent, based on weight-for-weight. In most cases, this corresponds to adding the surfactant at a ratio of 1 to 2 gallons / thousand gallons; or 0.1-0.2% (v / v). In Phase 1, Fluid A is pumped as a filler fluid to fracture the formation. In Phases 2-8, a supporting agent is added to modified fracturing fluids A and B "on the fly" while the fluids are pumped, and skipped from an initial concentration of 2.0 PPP (pounds of aggregate added) in Phase 2 up to 8.0 PPP in Phase 8. In Phase 9, Fluid C, a commercial fracturing fluid, based on CMHPG at 35 pounds of polymer per 1,000 gallons of fracturing fluid, is used as an "influx" "to displace and push the fracturing fluid containing suspending agent out of the pipe and into the formation. The amine oxide of the invention is typically not necessary in the displacement / influx phase. After the influx, the work ends and the well closes. The work is pumped to complete without incident. An average length (Xf) of propped fracture of approximately 820 feet is obtained with an average conductivity (Kf) of approximately 1275 md.ft. The well is then covered for several hours and then drained. Cleaning substantially improves (20-25% or more) over previous work performed in offset wells using comparable dewatering parameters
(pressure and regulator size). Well gas production also improves substantially over previous offset wells. Similar results are obtained using the fracturing fluids and the procedure described in
Example 10 above except that the CMHPG polymer was cross-linked by a titanate cross-linker. Similar results are also obtained using fracturing fluids and the procedure described in Example 10 above except that guar is used as a viscosifier instead of CMHPG. Similar results are also obtained using the fracturing fluids and the procedure described in Example 10 above except that guar is used as a viscosifier instead of CMHPG and a titanate crosslinker is used in place of a zirconate crosslinker. Similar results are also obtained using the fracturing fluids and the procedure described in Example 10 above except that guar is used as a viscosifier instead of CMHPG and a borate crosslinker is used in place of a zirconate crosslinker. These fluids have a basic pH. Angle of Contact: As mentioned above, some preferred amine oxides, in the presence of the forming fluids, provide a desirable increase in the contact angle. The contact angles were measured according to a method consisting of packing finely divided solids in a tube and then measuring the proportion at which a fluid enters the package. When an aqueous fluid makes contact with the packing of finely divided solids, it will begin to move inside the package as a front. Assuming that the package consists of a set of capillaries, it is possible to derive an expression to describe the rate at which the fluid moves in the package. According to Rosen in "Surfactants and Interfacial Phenomena," Second Edition, John iley and Sons, 1989, p. 247, the distance, 1, that a liquid with a viscosity,?, Advances in time, t, is given by the following expression:
72 (kr) t? N cos # 2?
where r is the average capillary size of the voids through the dust and k is a constant related to the tortuosity. Obviously, then the amount kr depends on the packing of the solids. The amount kr is measured by passing a fluid with a known surface tension through the packing; Water is a convenient selection. The contact angle of the known surface tension fluid is also known or assumed to be 0, which is a good assumption in the case where the test fluid is water and the packing consists of sand, clay and silica flour. The method assumes that neither flocculation, dissolution, nor dispersion changes the packing of the particles. We assume that the contact angle of the space? I is 0. The method also assumes that the concentration of surfactant. never falls below the critical micelle concentration due to the absorption of the surfactant. Finally, since some amine oxides can increase the viscosity of the test solution, we must take into account any difference in viscosity. Therefore, we will let 72 represent the viscosity of the test solution. If we also use the relative data for the length of the absorption column, then l? = 1. We also know the surface tension of water without surfactant,? ¡. = 72 dynes / cm, which leads to the following formula for the contact angle (in radians):
72 /,? 2 = Arc eos reí The following table refers to the absorption data at the contact angle.
X DMAO means an amine oxide according to formula I, wherein R1 is X and R2 and R3 are methyl. Where X = Cn where X is a linear alkyl chain of n carbons. It is particularly noteworthy that several of the tested surfactants of the invention form a contact angle significantly larger than the contact angle of the F75N surfactant of the prior art, in particular, they form a contact angle greater than 60 degrees, and in some cases greater than 80 degrees, and in fact reach 90 degrees.