WO2001051767A2

WO2001051767A2 - Addition of solids to generate viscosity downhole

Info

Publication number: WO2001051767A2
Application number: PCT/US2001/001161
Authority: WO
Inventors: Ben J. Palmer
Original assignee: Schlumberger Technology Corporation
Priority date: 2000-01-14
Filing date: 2001-01-12
Publication date: 2001-07-19
Also published as: WO2001051767A3; AU2001229444A1

Abstract

A fluid that is useful in well stimulation operations, and in particular, in hydraulic fracturing treatments, comprises a carrier fluid; a proppant; and a polymeric viscosifier, which is typically a polymer with a melting temperature at least about 120°F and that resists degradation at temperatures of about 300°F. The polymeric viscosifier can be a polyolefin, particularly polypropylene or polyethylene. The fluid is especially useful in stimulating production in formations with a temperature of about 300°F or higher.

Description

Addition of Solids to Generate Viscosity Downhole

Technical Field of the Invention

This Invention relates to the stimulation of hydrocarbon wells and in particular to fluids and methods for hydraulic fracturing of a high-temperature subterranean formation.

Background of the Invention Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a "reservoir") by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the hydrocarbon to reach the surface. In order for the hydrocarbon to be "produced," that is travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flowpath from the formation to the wellbore. This flowpath is through the formation rock — e.g., sandstone, carbonates — which has pores of sufficient size, connectivity, and number to provide a conduit for the hydrocarbon to move through the formation.

Hence, one of the most common reasons for a decline in hydrocarbon production is "damage" to the formation that plugs the rock pores and therefore impedes the flow of the hydrocarbon. This damage generally arises from another fluid deliberately injected into the wellbore, for instance, drilling fluid. Even after drilling, some drilling fluid remains in the region of the formation near the wellbore, which may dehydrate and form a coating on the wellbore. The natural effect of this coating is to decrease permeability to the hydrocarbon moving from the formation in the direction of the wellbore. Damage can also occur naturally if certain types of hydrocarbon, i.e. waxes and asphaltenes, are present in the formation. Another form of damage can occur when drilling fluids, or other fluids added by the well operator, combine with minerals present in the formation to form "inorganic scale," e.g. barium sulfate, calcium sulfate, or calcium carbonate.

Another reason for lower-than-expected production is that the formation is naturally "tight" (low permeability formation), that is, the pores are sufficiently small that the hydrocarbon migrates toward the wellbore only very slowly. The common denominator in both cases (damage and naturally tight reservoirs) is low permeability. Techniques performed by hydrocarbon producers to increase the net permeability of the reservoir are referred to as "stimulation." Essentially, one can perform a stimulation technique by: (1) injecting chemicals into the wellbore to react with and dissolve the damage (e.g., wellbore coating); (2) injecting chemicals through the wellbore and into the formation to react with and dissolve small portions of the formation to create alternative flowpaths for the hydrocarbon (thus rather than removing the damage, redirecting the migrating hydrocarbon around or through the damage); or (3) injecting chemicals through the wellbore and into the formation at pressures sufficient to actually fracture the formation, thereby creating a large flow channel though which hydrocarbon can more readily move from the formation and into the wellbore. The present invention is directed primarily to the third of these processes.

Hydraulic fracturing involves literally breaking or fracturing a portion of the surrounding strata, by injecting a specialized fluid into the wellbore directed at the face of the geologic formation at pressures sufficient to initiate and extend a fracture in the formation (i.e. above the minimum in situ rock stress). More particularly, a fluid is injected through a wellbore, and then the fluid exits the wellbore and is directed against the face of the formation at a pressure and flow rate sufficient to overcome the minimum in situ stress (also known as minimum principal stress) to initiate and/or extend a fracture(s) into the formation. If the well is completed with a casing, the fluid exits the wellbore through perforations in the well casing. If the well is completed openhole, where no casing and therefore no perforations exist, the fluid is injected through the wellbore and directly to the formation face.

In either case, this process typically creates a fracture zone, i.e., a zone having multiple fractures in the formation through which hydrocarbon can more easily flow to the wellbore. In practice, fracturing a well is a highly complex operation, in which tens of thousands of gallons of materials may be pumped into the formation at pressures high enough to split the formation in two, thousands of feet below the earth's surface.

Generally speaking, creating a fracture in a hydrocarbon-bearing formation requires a complex suite of materials. In the case of conventional fracturing treatments, four or five principal components are required: (1) a carrier fluid (usually water or brine), (2) a polymer gelling agent, (3) a cross-linker, (4) a proppant (commonly sand, or glass or ceramic beads; optionally, the proppant particles can be coated with resin to allow them to adhere), and (5) optionally a breaker. (Numerous other components are sometimes added, e.g. fluid loss agents, whose purpose is to control leak-off, or migration of the fluid into the fracture face). The purpose of these fluids is, first, to create and extend at least one fracture; second, once the fracture is opened sufficiently, to deliver proppant into the fracture. Proppant keeps the fracture from closing once the pumping operation is completed. The carrier fluid is simply the means by which the proppant and breaker are carried into the formation. Thus, the fracturing fluid is typically prepared by blending the polymer gelling agent with an aqueous solution (sometimes oil-based, sometimes a multi-phase fluid is desirable); often, the polymer gelling agent is a solvatable polysaccharide, e.g., galactomannan gums, glycomannan gums, and cellulose derivatives. A commonly used polymer gelling agent is guar or substituted guar. The purpose of the solvatable (or hydratable) polys accharides is: (1) to provide viscosity to the fluid so that it can create and extend the fracture; and (2) to thicken the aqueous solution so that proppant particles can be suspended in the solution for delivery into the fracture. Thus the polysaccharides function as viscosifiers, that is, they increase the viscosity of the aqueous solution at least 10-fold, and possibly as much as 1000-fold or more. In many fracturing treatments, a cross-linking agent is added which further increases the viscosity of the solution by cross-linking the polymer. The borate ion has been used extensively as a crosslinking agent for hydrated guar gums and other galactomannans to form aqueous gels. Other suitable cross-linking agents include titanium, chromium, iron, aluminum, borate, and zirconium compounds.

One problem in fracturing operations is that the polymers often degrade before the operation is completed, as a result of thermal, oxidative/free radical, or acid hydrolysis reactions. Guar and substituted guar polymers degrade very rapidly at high temperatures, such as about 300°F or higher. This degradation causes the viscosity of the fracturing fluid to decrease correspondingly. Reduction in viscosity can reduce the fluid's effectiveness in creating fractures and delivering proppant to the desired sites.

To overcome the degradation of the polymers at high temperature, the concentration of the polymer in the fracturing fluid can be increased, the polymer can be crosslinked, or both. However, using such a fracturing fluid, when water leaks into the formation during the fracturing process, the polymer concentrates in the fracture zone, leading to "gumming" of the fracture zone and reduced permeability to hydrocarbons. Two approaches have been used in an attempt to maintain the desired minimum viscosity in the fracturing fluid d ring the fracturing operation. One is to increase the initial loading of the polymer in the flu d, thus increasing the fluid's initial viscosity. However, this approach increases the energy required to pump the fluid into and through the wellbore. This and the cost of the additional polymer increases the overall cost of the fracturing operation, and also can lower well performance due to reduced conductivity in the proppant pack. A second approach is to include a stabilizer in the fracturing fluid, to minimize polymer degradation. Commonly used stabilizers include methanol and sodium thiosulfate (Na₂S₂O₃). Although the mechanism of action of these stabilizers is not fully understood, it is believed that they act as oxygen scavengers, and thus prevent polymer degradation that would otherwise be caused by oxygen dissolved in the fracturing fluid. However, methanol is flammable and therefore is generally avoided. A substantial quantity of sodium thiosulfate is required when it is used as a stabilizer. Neither of these two compounds is sufficiently effective as a stabilizer. The problem of polymer degradation is becoming even more important recently because of the increasing incidence of very deep, hot (e.g., temperature > 250° F) wells. Therefore, there is a need for improved fracturing fluids that are suitable for use at high temperatures.

Summary of the Invention

The present invention relates to the use of fluids in hydraulic fracturing operations. One embodiment of the invention is a well treatment fluid composition that comprises a carrier fluid; a proppant; and a polymeric viscosifier. A fluid comprising the carrier fluid and the polymeric viscosifier, but not the proppant, may herein be referred to as a "clear fluid." A "polymeric viscosifier" in this context is a polymer that has a melting temperature at least about 120°F and, preferably, resists thermal degradation at about 300°F (i.e. maintains the viscosity of the fracturing fluid at 20 cP or higher for at least 90 minutes). In one embodiment, the polymeric viscosifier comprises a polyolefin. In a preferred embodiment, the polyolefin is polypropylene, polyethylene, or mixtures thereof. The composition can optionally further comprise at least one of a solvatable polysaccharide or a viscoeleastic surfactant. A "solvatable polysaccharide" in this context is a polysaccharide that undergoes rapid thermal degradation at temperatures between about 120°F and about 300°F. In one embodiment, the solvatable polysaccharide is guar, hydroxypropyl guar, carboxymethyl guar, carboxymethylhydroxypropyl guar, hydroxyethyl cellulose, carboxymethylhydroxyethyl cellulose, hydroxypropyl cellulose, xanthan, or mixtures thereof. A "viscoelastic surfactant" is a molecule with both hydrophobic and hydrophilic portions, and is capable of forming micelles. A preferred viscoelastic surfactant is erucyl bis(2-hydroxyethyl) methyl ammonium chloride, either alone or in combination with other viscoelastic surfactants. Alternative viscoelastic surfactants may be employed either alone or in combination, including erucyl trimethyl ammonium chloride; N-methyl-N,N-bis(2- hydroxyethyl) rapeseed ammonium chloride; oleyl methyl bis(hydroxyethyl) ammonium chloride; octadecyl methyl bis(hydroxyethyl) ammonium bromide; octadecyl tris(hydroxyethyl) ammonium bromide; octadecyl dimethyl hydroxyethyl ammonium bromide; cetyl dimethyl hydroxyethyl ammonium bromide; cetyl methyl bis(hydroxyethyl) ammonium salicylate; cetyl methyl bis(hydroxyethyl) ammonium 3,4,-dichlorobenzoate; cetyl tris(hydroxyethyl) ammonium iodide; bis(hydroxyethyl) soya amine; N-methyl, N- hydroxyethyl tallow amine; bis(hydroxyethyl) octadecyl amine; cosyl dimethyl hydroxyethyl ammonium bromide; cosyl methyl bis(hydroxyethyl) ammonium chloride; cosyl tris(hydroxyethyl) ammonium bromide; dicosyl dimethyl hydroxyethyl ammonium bromide; dicosyl methyl bis(hydroxyethyl) ammonium chloride; dicosyl tris(hydroxyethyl) ammonium bromide; hexadecyl ethyl bis(hydroxyethyl) ammonium chloride; hexadecyl isopropyl bis(hydroxyethyl) ammonium iodide; N,N-dihydroxypropyl hexadecyl amine, N-methyl, N- hydroxyethyl hexadecyl amine; N,N-dihydroxyethyl dihydroxypropyl oleyl amine; N,N- dihydroxypropyl soya amine; N,N-dihydroxypropyl tallow amine; N-butyl hexadecyl amine; N-hydroxyethyl octadecyl amine; N-hydroxyethyl cosyl amine; cetylamino, N-octadecyl pyridinium chloride; N-soya-N-ethyl morpholinium ethosulfate; methyl- 1-oleyl amido ethyl- 2-oleyl imidazolinium-methyl sulfate; and methyl- 1 -tallow amido ethyl-2-tallow imidazolinium-methyl sulfate.

The composition can optionally further comprise a delay agent (such as a bicarbonate salt), a viscosity breaker agent, or one or more other additives, such as scale inhibitors, surfactants, biocides, proppant flowback inhibitors, and breaker aids.

Another aspect of the present invention is a method of hydraulically fracturing a subterranean formation. The method includes the step of injecting a well treatment fluid composition via a wellbore into a subterranean formation at a flow rate and pressure sufficient to produce or extend a fracture in the formation. The well treatment fluid composition comprises a carrier fluid, a proppant, and a polymeric viscosifier, as mentioned above. The compositions and methods of the present invention provide several substantial advantages over prior fracturing fluids and methods. Though not to be bound by theory, it is believed that at formation temperatures of about 200°F or higher, the polymeric viscosifier will melt to form an emulsion with the carrier fluid. This emulsion can quickly reach a viscosity sufficient to transport proppant into the fracture zone (e.g., 20-120 cP). The polymeric viscosifier' s resistance to thermal degradation will make it less likely than prior art fluids to suffer reduction of viscosity to excessively low levels. The present invention also is relatively simple and inexpensive to manufacture.

Brief Description of the Drawings Figure 1 shows the viscosity of a control solution comprising cross-linked carboxymethylhydroxypropyl guar (3), and five experimental fluids (the control solution, further comprising one of 0.5 wt% Kevlar™ (poly( -phenyleneterephtalamide), DuPont) (1), 0.5 wt% Nomex™ (poly-metaphenylene diamine, DuPont) (2), 0.5 wt% nylon (5), 0.5 wt% polypropylene (6), or 0.5 wt% Kynol™ (novoloid, Nippon Kynol) (4)) as a function of time, with the temperature (7) increasing from ambient temperature to 325°F and being maintained at the latter temperature for about 210 min.

Figure 2 shows the percentage of retained permeability in a conductivity test of a control solution comprising cross-linked carboxymethylhydroxypropyl guar ("None") and four experimental fluids (the control solution, further comprising one of 0.5 wt% Nomex™ (poly-metaphenylene diamine) ("Nomex"), 0.5 wt% Dacron™ (polyethylene terephthalate, Dupont) ("Polyester"), or 0.5 wt polypropylene ("Polypropylene"). The percentage of retained permeability of the control solution was defined as 100%.

Detailed Description of Preferred Embodiments Components of the Fracturing Fluid

While the compositions of the present invention are described herein as comprising certain materials, it should be understood that the composition can optionally comprise two or more chemically different such materials. For example, a composition could comprise a mixture of two or more polymeric viscosifiers having the characteristics described above. Likewise, two or more optional solvatable polysaccharides, viscoelastic surfactants, or a mixture thereof could be present in the composition. Two or more of any of the other components could also be present in the composition.

A well stimulating fluid, alternatively referred to as a "fracturing fluid," of the present invention will comprise a carrier fluid. Water and brine are the most commonly used carrier fluids. Emulsions or other combinations of aqueous and organic fluids can also be used. The fracturing fluid will also comprise a proppant. Suitable proppants include, but are not limited to, sand, bauxite, glass beads, and ceramic beads. If sand is used, it will typically be from about 20 to about 100 U.S. Standard Mesh in size. Mixtures of suitable proppants can be used. Optionally, the proppant or proppants can be coated with a resin to allow consolidation of the proppant particles into a mass. The concentration of proppant in the fracturing fluid can be any concentration known in the art, and will typically be in the range of about 0.5 to about 20 ppa (pounds of proppant added) per gallon of clean fluid.

The fracturing fluid also comprises a polymeric viscosifier. The polymeric viscosifier is a polymer that has a melting point greater than about 120°F. A suitable polymeric viscosifier is polypropylene, polyethylene, or mixtures thereof, especially with a molecular weight of at least about 100 kD. Other polymeric viscosifiers include polypropylene, Dacron (polyethylene terephthalate), nylon, and polybutadiene. The concentration of polymeric viscosifier in the fracturing fluid is preferably in the range of from about 0.1 to about 3 wt%. The fracturing fluid can be prepared at the surface by combining the carrier fluid, the proppant, and the polymeric viscosifier in a solid form. The polymeric viscosifier can be provided in any solid form, such as fibers, pellets, chips, or flakes. Fibers (defined as particles with one spatial dimension very much greater than the other two, e.g. at least 10: 1 : 1 ) provide an advantage by increasing proppant transport at low temperature (below the melting point of the polymeric viscosifier). However, one of skill in the art will recognize that the different solid forms of the polymeric viscosifier may have particular advantages and disadvantages that render each one more or less suitable for a particular formulation or intended use.

Optionally, the fracturing fluid can comprise at least one of a solvatable polysaccharide or a viscoelastic surfactant. Suitable solvatable polysaccharides include, for example, guar, hydroxypropyl gu;ιr, carboxymethyl guar, carboxymethylhydroxypropyl guar, hydroxyethyl cellulose, carboxyrr ethylhydroxyethyl cellulose, hydroxypropyl cellulose, xanthan, or mixtures thereof. Some viscoelastic surfactants are described in detail in U.S. Patent No. 5,964,295. Suitable viscoelastic surfactants useful in the present invention include erucyl bis(2-hydroxyethyl) methyl ammonium chloride; erucyl trimethyl ammonium chloride; N-methyl-N,N-bis(2-hydroxyethyl) rapeseed ammonium chloride; oleyl methyl bis(hydroxyethyl) ammonium chloride; octadecyl methyl bis(hydroxyethyl) ammonium bromide; octadecyl tris(hydroxyethyl) ammonium bromide; octadecyl dimethyl hydroxyethyl ammonium bromide; cetyl dimethyl hydroxyethyl ammonium bromide; cetyl methyl bis(hydroxyethyl) ammonium salicylate; cetyl methyl bis(hydroxyethyl) ammonium 3,4,- dichlorobenzoate; cetyl tris(hydroxyethyl) ammonium iodide; bis(hydroxyethyl) soya amine; N-methyl, N-hydroxyethyl tallow amine; bis(hydroxyethyl) octadecyl amine; cosyl dimethyl hydroxyethyl ammonium bromide; cosyl methyl bis(hydroxyethyl) ammonium chloride; cosyl tris(hydroxyethyl) ammonium bromide; dicosyl dimethyl hydroxyethyl ammonium bromide; dicosyl methyl bis(hydroxyethyl) ammonium chloride; dicosyl tris(hydroxyethyl) ammonium bromide; hexadecyl ethyl bis(hydroxyethyl) ammonium chloride; hexadecyl isopropyl bis(hydroxyethyl) ammonium iodide; N,N-dihydroxypropyl hexadecyl amine, N- methyl, N-hydroxyethyl hexadecyl amine; N,N-dihydroxyethyl dihydroxypropyl oleyl amine; N,N-dihydroxypropyl soya amine; N,N-dihydroxypropyl tallow amine; N-butyl hexadecyl amine; N-hydroxyethyl octadecyl amine; N-hydroxyethyl cosyl amine; cetylamino, N- octadecyl pyridinium chloride; N-soya-N-ethyl morpholinium ethosulfate; methyl- 1-oleyl amido ethyl-2-oleyl imidazolinium-methyl sulfate; and methyl- 1 -tallow amido ethyl-2-tallow imidazolinium-methyl sulfate. Other natural and synthetic polymers can be used as well. The use of a solvatable polysaccharide or a viscoelastic surfactant can be helpful in promoting transport of the proppant and the polymeric viscosifier in regions of the wellbore where the temperature is too low (e.g. about 100°F) for the polymeric viscosifier to be melted.

If a solvatable polysaccharide is used, its concentration can be lower than that found in conventional fracturing fluids which do not comprise a polymeric viscosifier. Typically, its concentration will be from about 0.14 wt% to about 0.72 wt% (about 11 lbs to about 61 lbs per thousand gallons of water). If a viscoelastic surfactant is used, its concentration typically will be in the range of about 0.5 vol% to about 5 vol%. If a solvatable polysaccharide is used, the fluid can comprise agents commonly used to modify the functional properties of the solvatable polysaccharide. For example, the fluid can comprise an organic zirconate cross-linking agent for the solvatable polysaccharide. One particularly preferred crosslinker is bis(hydroxyethyl)glycine zirconate, available from DuPont. (See U.S. Patent 4,808,739). In addition, the fluid can also comprise a delay agent, to delay the cross-linking of the solvatable polysaccharide. This permits the fracturing fluid to be pumped at a lower initial viscosity, while allowing the fluid viscosity to subsequently increase to the desired level after cross-linking begins. Suitable delay agents include, for example, bicarbonate salts. A particularly preferred delay agent is sodium bicarbonate. However, the need for a delay agent is generally diminished, as the solvatable polysaccharide is most needed at low temperature regions of the borehole, i.e. near the surface, i.e. shortly after the fluid is injected into the borehole.

Another additive that can be used with a solvatable polysaccharide is a stabilizing agent. The need for a stabilizing agent is also generally diminished, as stabilization of the solvatable polysaccharide is far less necessary given the presence of a polymeric viscosifier. The fluid can also comprise a breaker. The purpose of a breaker is to diminish the viscosity of the fracturing fluid so that this fluid is more easily recovered from the fracture during clean-up. Examples of breakers suitable for use in the method of the present invention include enzymes such as galactomannanase (for breaking solvatable polysaccharides based on galactomannan) and oxidizers such as ammonium persulfate. Additionally, the breakers can be encapsulated to delay their release, for example as described in U.S. Pat. No. 4,741,401 , which is incorporated herein by reference.

However, the need for a breaker in the fracturing fluid and the method of the present invention will in many cases be diminished. Solvatable polysaccharides, such as guar and substituted guars, will rapidly lose viscosity at temperatures of about 300°F or higher even in the absence of a breaker. Polymeric viscosifiers will typically be hydrocarbon polymers, such as polyethylene. As a result, they will tend to be miscible in crude oil or other hydrocarbon fluids produced by the well. The polymeric viscosifiers can then be readily removed from the hydrocarbon fluids after production. Optionally, the fracturing fluid can further contain one or more additives such as surfactants, breaker aids, salts (e.g., potassium chloride), anti-foam agents, scale inhibitors, and bactericides. Also optionally, the fracturing fluid can contain materials designed to limit proppant flowback after the fracturing operation is complete by forming a porous pack in the fracture zone. Such materials, herein "proppant flowback inhibitors," can be any known in the art, such as are available from Schlumberger under the tradename Propnet™. Exemplary proppant flowback inhibitors include fibers or platelets of novoloid or novoloid-type polymers (United States Patent No. 5,782,300), such as are commercially available under the tradename Kynol. Other useful proppant flowback inhibitors include fibers or platelets of Kevlar (poly(/?-phenyleneterephtalamide)) or Nomex (poly-metaphenylene diamine). The proppant flowback inhibitors listed are heat resistant, and so are useful under high temperature. The proportion of the various components of a composition of the present invention will vary depending on the characteristics of the formation to be treated and other factors well known in the art. Typical concentration ranges for an exemplary composition of the "clean fluid" (i.e. before adding proppant) are as follows (percentages are by weight): water 95 - 99.5 % polymeric viscosifier 0.1 - 3 % solvatable polysaccharide 0.14 - 0.72 % crosslinker 0.02 - 0.15 % stabilizer 0.05 - 0.40 % salt (e.g. KC1) 0.1 - 2 % other additives 0.01 - 0.5 % each

The components of the fracturing fluid can be combined in a mixing tank above ground and then injected into the well and the target formation. Alternatively, one or more components, for example the breaker if used, can be stored by itself and injected into the wellbore and the formation after the fluid has been injected.

The composition of the present invention provides useful stability enhancement at temperatures of about 200° F or higher. Preferably the fracturing fluid of the present invention can maintain a viscosity of at least 20 cP for at least 90 minutes at 325° F.

In the method of the present invention, techniques for hydraulically fracturing a subterranean formation will be known to persons of ordinary skill in the art, and will involve pumping the fracturing fluid into the borehole and out into the surrounding formation. The fluid pressure is above the minimum in situ rock stress, thus creating or extending fractures in the formation. See Stimulation Engineering Handbook, John W. Ely, Pennwell Publishing Co., Tulsa, Oklahoma (1994).

In pumping the fracturing fluid into the borehole, it is most economical for the fluid to have as low a viscosity as possible, to minimize the energy expenditure of pumping. On the other hand, some viscosity is required to transport proppant and the polymeric viscosifier through regions where the polymeric viscosifier is a solid. One of ordinary skill in the art will be able to determine, based on the proppant, the polymeric viscosifier, the form of the polymeric viscosifier, and other variables, what further viscosity increase (through the addition of solvatable polysaccharide or viscoelastic surfactant) is desired.

Examples

Example 1. Viscosity Test

The viscosity of various compositions as a function of temperature was determined by the following procedure. As a control, a fluid containing a zirconate cross-linked carboxymethylhydroxypropyl guar in water (0.72 wt% (60 lbs per thousand gallons) (Fig. 1 , trace 3)) was prepared. Experimental fluids were prepared by adding to the control fluid additives up to 0.5 wt% of the composition. Five different experimental fluids were prepared, each comprising one of the following additives: Kevlar (poly(p- phenyleneterephtalamide)) (Fig. 1, trace 1), Nomex (poly-metaphenylene diamine) (Fig. 1 , trace 2), nylon (Fig. 1, trace 5), polypropylene (Fig. 1 , trace 6), or Kynol (novoloid) (Fig. 1 , trace 4). Nylon and polypropylene were examined as polymeric viscosifiers; Kevlar, Nomex, and Kynol were examined as proppant flowback inhibitors.

Samples of the control and each of the five experimental fluids were loaded onto a Fann 50 rheometer at approximately 80°F. Starting from t = 0 min, the temperature of the samples was varied according to the following schedule (Fig. 1, trace 7): (i) maintaining the temperature at about 75-80°F until about t = 5 min; (ii) linearly increasing the temperature from about 75°F to about 325°F from about t = 5 min till about t = 35 min; and (iii) maintaining the temperature at about 325 °F from about t = 35 min till about t = 240 min. Viscosity of each sample was monitored continuously using the API93F procedure.

The results are shown in Figure 1. During period (i) at ambient temperature, the viscosities of the control and all five experimental fluids were in the range of about 200 cP to about 400 cP. During period (ii). the viscosities of the control and the experimental fluids increased. The control reached a maximum viscosity of about 1500 cP at a temperature of about 160°F. The experimental fluids comprising nylon or polypropylene exhibited maximum viscosities in the range of about 1900 cP to about 2100 cP, at temperatures of about 160°F. The fluids comprising Kevlar and Kynol also exhibited maximum viscosities in about the same range and at temperatures from about 160°F to about 190°F. The experimental fluid comprising Nomex, in contrast, exhibited a maximum viscosity of only about 1000 cP, at approximately 175°F.

After reaching their maximum viscosities, and during period (iii) at 325°F, the viscosities of the fluids decreased. Presumably, some or all of the decrease in viscosity arose from thermal degradation of the carboxymethylhydroxypropyl guar present in each fluid. The viscosity of the control decreased steadily and fell to roughly 50 cP at t = 240 min. The viscosity of the fluids comprising nylon or Kynol also decreased steadily; however, the viscosity of each remained greater than that of the control until at least t = 130 min. The final viscosity of each was about 50 cP, comparable to the control.

The fluid comprising polypropylene showed a steady decrease in viscosity after peaking. However, its viscosity remained greater than that of any other fluid until about t = 85 min, and fell below 500 cP after about t = 1 10 min. Its final viscosity was about 100 cP, which was about twice that of the control. The viscosity of the fluid comprising Kevlar exhibited a rapid decrease after peaking.

However, the baseline viscosity of this fluid at 325°F was roughly 200 cP, which it retained until about t = 160 min. Thereafter, the viscosity declined to a final value of about 100 cP. The viscosity of this fluid was greater than that of the control after about t = 110 min.

The viscosity of the fluid comprising Nomex also exhibited a rapid decrease after peaking. The baseline viscosity of this fluid was in the range of 300-400 cP, which it retained from about t = 25 min until t = 85 min. At that time, the viscosity began to increase, reaching a high of about 900 cP before undergoing a steady decrease to approximately 100 cP at t = 240 min. The viscosity of this fluid was greater than that of the control after about t = 85 min. In conclusion, the results shown in Fig. 1 demonstrate that compositions comprising polypropylene or nylon have a higher viscosity than the control for at least about 90 min of maintenance at 325°F. The composition comprising polypropylene had a viscosity consistently about 400 cP greater than that of the control throughout this timeframe. Given that 325°F is greater than the melting points of polypropylene and nylon, and as the experimental fluids comprising polypropylene and nylon appeared at the conclusion of the test to be emulsions of polymer melt in water, we conclude that melting of the polymers during the experiment generated the greater viscosity of these fluids relative to the control.

The viscosity increases seen for the fluids containing Kevlar, Nomex, or Kynol relative to the control are presumably due to clumping of the fibers in the experimental apparatus. This presumption is addressed by the experiment involving Nomex described in Example 2.

Example 2. Conductivity Test

Fracture conductivity tests of fibers-containing fluids were conducted, using a cell of the "Cooke-type", which is analogous to that used in the American Petroleum Institute (API)-specified method for measuring proppant-only permeability (Cooke, C.E.: SPE 5114 "Effect of Fracturing Fluids on Fracture Conductivity," J. Pet. Tech., (Oct. 1975) 1273 - 82., API RP 56, "Recommended Practices for Testing Sand Used in Hydraulic Fracturing Operations: First Edition", American Petroleum Institute, March 1983).

To summarize, a highly modified API-type fracture conductivity cell was used in which proppant is confined between two precision machined cores. Fluid leakoff occurred through the cores during fracture closure, concentrating the control or experimental fluid within the proppant pack of the simulated fracture. The cell was then shut-in for, typically, about 12 hours at the test temperature (325°F) and closure stress (10,000 psi). After shut-in, a brine solution was flowed through the proppant pack (typically for about 5 hours) and the pressure differentials were monitored until a steady state was achieved. Proppant pack permeabilities were calculated from the fracture measurements, flow rate, and pressure drop data.

The dual core test cell was constructed of Monel and used the API-recommended ten square inch flow path and port spacing. A rock core, fixed in place by a lower piston, served as the proppant pack substratum. A sliding upper piston positioned a rock core onto the upper surface of the proppant pack. Each piston allowed passage of the fluid leakoff through the cores. A computer-controlled Dake hydraulic press with electronically-controlled heated platens confined the cell and heated it to the test temperature. The hydraulic press supplied both hydrostatic pressure to cause fluid loss and closure stress to the proppant.

Continuous brine flow against a 250 psi backpressure was accomplished using duplex chromatography pumps. The brine flow rate was computer-monitored by the weight of effluent collected on an electronic balance. The brine was heated by flow through a twenty foot coil of 1/8 inch 316 stainless steel tubing wrapped in electronically-controlled heat tape. The brine temperature was monitored at the cell entrance.

Validyne P305D differential pressure transducers were used to measure the pressure drops across three distinct segments (the upstream half, the downstream half, and the full length) of the proppant pack. This arrangement served as a check for leaks, plugged ports, level proppant placement, and transducer accuracy. The differential pressure transducers were calibrated to 0.0001 psi accuracy using a column of water.

A VAX Station 3200 computer was used to monitor and record cell and fluid temperatures, fluid loss and effluent balances, and cell hydrostatic, differential, and closure pressures. The hydraulic press was computer-controlled through all phases of a test. Also, permeabilities across the cell were calculated and reports were generated.

Proppant, herein 20/40 bauxite, was placed in the cell and leveled with a blade-type leveling device. A total of 64 g of 20/40 bauxite was added to the 10 in² cell. Thereafter, 2% wt KC1 cleanup fluid was used to saturate the proppant pack and to fill all cell ports. The control and experimental fluids, when used, were carefully added to the cell without disturbing the proppant pack. The upper core and piston were then put in place and all air bled from the cell as the piston was lowered. Closure stresses of 10,000 psi were employed. A control solution was prepared, comprising a zirconate cross-linked carboxymethylhydroxypropyl guar in water (0.72 wt% (60 lbs per thousand gallons) (Fig. 2, "None"). Experimental fluids were prepared by adding to the control fluid additives up to 0.5 wt% of the composition. Three different experimental fluids were prepared, each comprising one of the following additives: Nomex (poly-metaphenylene diamine) (Fig. 2, "Poly- metaphenylene diamine"), Dacron (polyethylene terephthalate) (Fig. 2, "Polyester"), or polypropylene (Fig. 2, "Polypropylene"). The percentages of retained permeability for the control and experimental fluids are shown in Fig. 2. The retained permeability of the control was defined as 100%. This represents the permeability imparted by the porous pack of 20/40 bauxite, reduced by "gumming" of the porous pack by decomposition of the carboxymethylhydroxypropyl guar at 325°F. In contrast, the experimental fluid comprising polypropylene exhibited a retained permeability of 146%. This indicates that the polypropylene transported decomposed carboxymethylhydroxypropyl guar out of the proppant pack.

The experimental fluid comprising Nomex exhibited retained permeability of 47%. Because this fibrous compound neither melted nor decomposed under the experimental conditions, its reduced retained permeability relative to the control is presumably a result of the occupation of space in the proppant pack by the compound.

Unexpectedly, the experimental fluid comprising Dacron also exhibited a retained permeability less than the control, 54%. It is believed that, instead of melting at the test temperature, Dacron was attacked by the zirconate cross-linker. As a result, presumably the Dacron decomposed to particles too large to flow free of the proppant pack, which led to greater gumming than occurred in the control, and hence, lower retained permeability.

In summary, the addition of polypropylene enhanced the retained permeability of the proppant pack in the test apparatus by 46% over carboxymethylhydroxypropyl guar alone. The results of Examples 1 and 2 indicate that polypropylene can increase the viscosity of a fracturing fluid and also decrease gumming of the proppant pack.

The preceding description of specific embodiments of the present invention is not intended to be a complete list of every possible embodiment of the invention. Persons skilled in this field will recognize that modifications can be made to the specific embodiments described here that would be within the scope of the present invention.

Claims

WHAT IS CLAIMED IS:

1. A well treatment fluid composition, comprising: a carrier fluid; a proppant; and a polymeric viscosifier having a melting point greater than about 120°F.

2. The composition of claim 1, wherein the polymeric viscosifier comprises a polyolefin having a melting point greater than about 120°F.

3. The composition of claim 2, wherein the polyolefin is polypropylene, polyethylene, or mixtures thereof.

4. The composition of claim 3, wherein the polypropylene or polyethylene has a molecular weight of at least 100 kD.

5. The composition of claim 1 , wherein the polymeric viscosifier comprises nylon, polyethylene terephthalate, polybutadiene, or mixtures thereof.

6. The composition of claim 1 , wherein the polymeric viscosifier is present at about 0.1 wt% to about 3 wt%.

7. The composition of claim 6, wherein the polymeric viscosifier is present at about 0.5 wt%.

8. The composition of claim 1, wherein the proppant comprises sand, bauxite, glass, or ceramic.

9. The composition of claim 1, further comprising at least one of a solvatable polysaccharide or a viscoelastic surfactant.

0. The composition of claim 9, wherein the solvatable polysaccharide is selected from guar, hydroxypropyl guar, carboxymethyl guar, carboxymethylhydroxypropyl guar, hydroxyethyl cellulose, carboxymethylhydroxyethyl cellulose, hydroxypropyl cellulose, xanthan, or mixtures thereof; or wherein the viscoelastic surfactant is selected from erucyl bis(2-hydroxyethyl) methyl ammonium chloride; erucyl trimethyl ammonium chloride; N-methyl-N,N-bis(2-hydroxyethyl) rapeseed ammonium chloride; oleyl methyl bis(hydroxyethyl) ammonium chloride; octadecyl methyl bis(hydroxyethyl) ammonium bromide; octadecyl tris(hydroxyethyl) ammonium bromide; octadecyl dimethyl hydroxyethyl ammonium bromide; cetyl dimethyl hydroxyethyl ammonium bromide; cetyl methyl bis(hydroxyethyl) ammonium salicylate; cetyl methyl bis(hydroxyethyl) ammonium 3,4,-dichlorobenzoate; cetyl tris(hydroxyethyl) ammonium iodide; bis(hydroxyethyl) soya amine; N-methyl, N-hydroxyethyl tallow amine; bis(hydroxyethyl) octadecyl amine; cosyl dimethyl hydroxyethyl ammonium bromide; cosyl methyl bis(hydroxyethyl) ammonium chloride; cosyl tris(hydroxyethyl) ammonium bromide; dicosyl dimethyl hydroxyethyl ammonium bromide; dicosyl methyl bis(hydroxyethyl) ammonium chloride; dicosyl tris(hydroxyethyl) ammonium bromide; hexadecyl ethyl bis(hydroxyethyl) ammonium chloride; hexadecyl isopropyl bis(hydroxyethyl) ammonium iodide; N,N-dihydroxypropyl hexadecyl amine, N-methyl, N-hydroxyethyl hexadecyl amine; N,N-dihydroxyethyl dihydroxypropyl oleyl amine; N,N-dihydroxypropyl soya amine; N,N-dihydroxypropyl tallow amine; N-butyl hexadecyl amine; N-hydroxyethyl octadecyl amine; N-hydroxyethyl cosyl amine; cetylamino, N-octadecyl pyridinium chloride; N-soya-N-ethyl morpholinium ethosulfate; methyl- 1-oleyl amido ethyl-2-oleyl imidazolinium-methyl sulfate; methyl- 1 -tallow amido ethyl-2-tallow imidazolinium-methyl sulfate; or mixtures thereof.

11. The composition of claim 9, wherein the solvatable polysaccharide is present at about

0.14 wt% to about 0.72 wt%, or wherein the viscoelastic surfactant is present at about 0.5 vol% to about 5 vol%.

12. The composition of claim 1 , further comprising at least one additive selected from the group consisting of scale inhibitors, surfactants, proppant flowback inhibitors, breakers, and biocides.

13. The composition of claim 8, further comprising at least one additive selected from a delay agent or a crosslinking agent.

14. The composition of claim 1 , wherein the well treatment fluid exhibits a viscosity of at least 20 cP within 10 min of exposure to a temperature of at least 300°F.

15. The composition of claim 1 , wherein the well treatment fluid exhibits a viscosity of at least 20 cP within 90 min of exposure to a temperature of at least 325°F.

16. The composition of claim 12, wherein the proppant flowback inhibitor is poly(/?- phenyleneterephtalamide), poly-metaphenylene diamine, novoloid, or mixtures thereof.

17. A method of hydraulically fracturing a subterranean formation, comprising the step of: injecting a well treatment fluid composition via a wellbore into a subterranean formation at a flow rate and pressure sufficient to produce or extend a fracture in the formation, wherein the well treatment fluid composition comprises: a carrier fluid; a proppant; and a polymeric viscosifier having a melting point greater than about 120°F.

18. The method of claim 17, wherein the polymeric viscosifier comprises a polyolefin having a melting point greater than about 120°F.

19. The method of claim 17, wherein the polymeric viscosifier is polypropylene, polyethylene, or mixtures thereof.

20. The method of claim 19, w erein the polypropylene or polyethylene has a molecular weight of at least 100 kD.

21. The method of claim 17, wherein the polymeric viscosifier comprises nylon, polyethylene terephthalate, polybutadiene, or mixtures thereof.

22. The method of claim 17, wherein the polymeric viscosifier is present at about 0.1 wt% to about 3 wt%.

23. The method of claim 22, wherein the polymeric viscosifier is present at about 0.5 wt%.

24. The method of claim 17, wherein the proppant comprises sand, bauxite, glass, or ceramic.

25. The method of claim 17, wherein the well treatment fluid composition further comprises at least one of a solvatable polysaccharide or a viscoelastic surfactant.

26. The method of claim 25, wherein the solvatable polysaccharide is guar, hydroxypropyl guar, carboxymethyl guar, carboxymethylhydroxypropyl guar, hydroxyethyl cellulose, carboxymethylhydroxyethyl cellulose, hydroxypropyl cellulose, xanthan, or mixtures thereof; or the viscoelastic surfactant is erucyl bis(2-hydroxyethyl) methyl ammonium chloride; erucyl trimethyl ammonium chloride; N-methyl-N,N-bis(2-hydroxyethyl) rapeseed ammonium chloride; oleyl methyl bis(hydroxyethyl) ammonium chloride; octadecyl methyl bis(hydroxyethyl) ammonium bromide; octadecyl tris(hydroxyethyl) ammonium bromide; octadecyl dimethyl hydroxyethyl ammonium bromide; cetyl dimethyl hydroxyethyl ammonium bromide; cetyl methyl bis(hydroxyethyl) ammonium salicylate; cetyl methyl bis(hydroxyethyl) ammonium 3,4,-dichlorobenzoate; cetyl tris(hydroxyethyl) ammonium iodide; bis(hydroxyethyl) soya amine; N-methyl, N- hydroxyethyl tallow amine; bis(hydroxyethyl) octadecyl amine; cosyl dimethyl hydroxyethyl ammonium bromide; cosyl methyl bis(hydroxyethyl) ammonium chloride; cosyl tris(hydroxyethyl) ammonium bromide; dicosyl dimethyl hydroxyethyl ammonium bromide; dicosyl methyl bis(hydroxyethyl) ammonium chloride; dicosyl tris(hydroxyethyl) ammonium bromide; hexadecyl ethyl bis(hydroxyethyl) ammonium chloride; hexadecyl isopropyl bis(hydroxyethyl) ammonium iodide; N,N- dihydroxypropyl hexadecyl amine, N-methyl, N-hydroxyethyl hexadecyl amine; N,N- dihydroxyethyl dihydroxypropyl oleyl amine; N,N-dihydroxypropyl soya amine; N,N- dihydroxypropyl tallow amine; N-butyl hexadecyl amine; N-hydroxyethyl octadecyl amine; N-hydroxyethyl cosyl amine; cetylamino, N-octadecyl pyridinium chloride; N- soya-N-ethyl morpholinium ethosulfate; methyl- 1-oleyl amido ethyl-2-oleyl imidazolinium-methyl sulfate; methyl- 1 -tallow amido ethyl-2-tallow imidazolinium- methyl sulfate; or mixtures thereof.

27. The method of claim 25, wherein the solvatable polysaccharide is present at about 0.14 wt% to about 0.72 wt%, or the viscoelastic surfactant is present at about 0.5 vol% to about 5 vol%.

28. The method of claim 17, wherein the fluid further comprises at least one additive selected from the group consisting of scale inhibitors, surfactants, proppant flowback inhibitors, breakers, and biocides.

29. The method of claim 25, wherein the fluid further comprises at least one additive selected from a delay agent or a crosslinking agent.

30. The method of claim 17, wherein the well treatment fluid exhibits a viscosity of at least 20 cP within 10 min of exposure to a temperature of at least 300°F.

31. The method of claim 17, wherein the well treatment fluid exhibits a viscosity of at least 20 cP within 90 min of exposure to a temperature of at least 325°F.

32. The method of claim 28, wherein the proppant flowback inhibitor is poly(p- phenyleneterephtalamide), poly-metaphenylene diamine, novoloid, or mixtures thereof.