Fracturing fluids and methods of making and using same

[00002] The present application is related to U.S. Provisional Patent Application Ser. No. 60/300,268 filed Jun. 22, 2001, the contents of which are incorporated herein by reference.

[00003] The invention relates to methods and compositions for treating subterranean formations. More particularly, it relates to methods and compositions for treating a subterranean formation penetrated by a wellbore into which a gel with a high viscosity is injected.

[00004] Viscous well treatment fluids are commonly utilized in the drilling, completion, and treatment of subterranean formations penetrated by wellbores. A viscous well treatment fluid is generally composed of a polysaccharide or synthetic polymer in an aqueous solution which is crosslinked by metallic compounds. Examples of well treatments in which metal-crosslinked polymers are used are hydraulic fracturing, gravel packing operations, water blocking, and other well completion operations.

[00005] Hydraulic fracturing techniques are widely employed to enhance oil and gas production from subterranean formations. During hydraulic fracturing, a proppant-laden fluid is injected into a well bore under high pressure. Once the natural reservoir pressures are exceeded, the fracturing fluid initiates a fracture in the formation which generally continues to grow during pumping. The treatment design generally requires the fluid to reach a maximum viscosity as it enters the fracture which affects the fracture length and width. The viscosity of most fracturing fluids is generated from water-soluble polysaccharides, such as galactomannans or cellulose derivatives. Employing crosslinking agents, such as borate, titanate, or zirconium ions, can further increase the viscosity. The gelled fluid may be accompanied by a propping agent (i.e., proppant) which results in placement of the proppant within the fracture thus produced. The proppant remains in the produced fracture to prevent the complete closure of the fracture and to form a conductive channel extending from the well bore into the formation being treated once the fracturing fluid is recovered.

[00006] In formulating a fracturing fluid, several factors generally are considered. First, the fracturing fluid should preferably have sufficient viscosity to create suitable fracture geometry. Generally, most treatments are designed to obtain a specified fracture length. In addition to fracture length, it is also common to create a fracture that has a width at least three times greater than the largest proppant size. Typically, the viscosity of a fracturing fluid is designed to satisfy the requirements of both the fracture length and fracture width. Second, the viscosity of a fracturing fluid should preferably be high enough for the fluid to adequately transport the proppant from the surface to the fracture. Suitable fluids are those which can suspend the proppant with minimal settling. Third, a fracturing fluid should preferably have minimal fluid loss to the formation.

[00007] Multiple patents and publications have attempted to prepare a fracturing fluid with a combination of these desirable features.

[00008] U.S. Pat. No. 4,477,360 suggests the use of an aqueous gel containing a zirconium salt and a polyhydroxyl-containing compound. The gel is suggested for use in fracturing fluids, and has a high viscosity. The polyhydroxyl compounds have 3 to 7 carbon atoms, and a preferred compound is glycerol. Gelling agents include various polysaccharides.

[00009] U.S. Pat. No. 4,635,727 offers methods of fracturing a subterranean formation using a base guar gum gel and a crosslinking system. A preferred crosslinking system includes zirconium lactate and aluminum chlorohydrate.

[00010] U.S. Pat. No. 5,305,832 proposes methods for using crosslinked guar polymers at a pH such that the cationic charge density of the polymer is at its maximum. The pH is chosen to minimize thermal degradation and to minimize polymer gel loading. The pH varied depending on the polymer used, but were typically in the range of about 10 to about 12.

[00011] U.S. Pat. No. 5,972,850 offers an aqueous metal hydrated galactomannan gum buffered to pH 9 to 11, and methods for its use in fracturing a subterranean formation. Metal ions suggested to crosslink the galactomannan gum include boron, zirconium, and titanium ions.

[00012] U.S. Pat. No. 6,017,855 suggests methods for fracturing subterranean formations using fluids having reduced polymer loadings. The fluids contain modified polymers having randomly distributed anionic substituents. The polymers can be crosslinked to form viscous gels that are stable at low polymer concentrations. Modification of the polymers lead to lowered C* concentrations (the concentration necessary to cause polymer chain overlap).

[00013] U.S. Pat. No. 6,060,436 proposes the use of borate ion crosslinked galactomannan gums in fracturing fluids. The crosslinking is delayed by release of borate ions from a polyol complex.

[00014] SPE 29446 (1995) discusses field results of well treatment with borate-crosslinked or titanate-crosslinked systems. Performance was observed to improve with the following treatments, in increasing order of improvement: titanate-crosslinked fluids, borate-crosslinked fluids, organoborate-crosslinked fluids, and organoborate-crosslinked fluids with a guar-specific enzyme breaker. Organoborates were offered as providing stronger crosslink junctions, greater elasticity, high viscosity, and reduced polymer loadings.

[00015] SPE 36496 (1996) offers the characterization of breaker efficiency by determining the size distribution of degraded polymer fragments. Reduced viscosity was discussed as not being fully indicative of molecular weight reduction. For example, the use of oxidative breakers is capable of reducing gel viscosity, but is relatively ineffective to reduce the polymer molecular weight. Guar specific enzymes were found to provide the most efficient molecular weight reduction of crosslinked fluids.

[00016] The success of a hydraulic fracturing treatment, in part, depends upon the creation of a high-permeability fracture. The long term production of a well is directly related to fracture conductivity, which is dependent upon the fracturing fluid used during the treatment and the cleanup of the fracturing fluid after the treatment. Excessive amounts of polymer gels and other insoluble residues may significantly reduce fracture conductivity. Therefore, there is a need for a fracturing fluid and a method of treating a subterranean formation which would result in good fracture conductivity.

[00017] The instant invention is generally directed towards fracturing fluids and methods for their use. Fracturing fluids disclosed herein comprise a liquid, a polymer soluble in the liquid, having a degree of substitution of ionic groups of about 0.01 to about 0.1, and a crosslinking agent capable of increasing the viscosity of the fracturing fluid by crosslinking the polymer in liquid.

[00018] Particular embodiments of the fracturing fluids display reversible cross-linking, allowing removal of the fracturing fluid once a well treatment is completed. The change in cross-linking can be accomplished by methods such as changing the pH.

[00019] Use of the disclosed fracturing fluids can result in improved fracture conductivity, reduced polymer loading, and causation of less formation damage than would be observed using conventional fracturing fluids.

[00087] Four polymer solutions were prepared as follows. Into 1 liter of rapidly agitated DI water was first added 1.0 ml of a 50% aqueous solution of tetramethylammonium chloride, followed by 4.8 g of guar based polymer. The specific polymers having varying degrees of substitution are defined below in Table 4. Next, 0.024 g of fumaric acid was added, followed by agitation for 2.5 minutes. A portion of the fluid was periodically removed to have the fluid's viscosity measured on a Grace M3500A viscometer at 511 sec⁻¹ at about 68° F. (20° C.) for a total of 15 minutes. The viscosity data is presented in Table 4.

[00002]

TABLE 4
Viscosity comparison results
Viscosity (cP at 511 sec−1)
Polymer	1 min.	2 min.	3 min.	4 min.	5 min.	10 min.	15 min.
Guar	27.2	28.4	29.4	29.9	30.1	31.1	32.1
0.03 DS CMG	16.6	19.6	20.4	21.7	22.9	26.8	28.6
0.06 DS CMG	31.1	32.3	32.9	33.3	33.5	33.7	33.7
0.09 DS CMG	36.1	37.2	37.4	37.4	37.0	36.4	36.2

[00088] This data suggests that as the degree of substitution level increases, the polymer solution viscosity also increases. This effect may be due to expansion of the polymer coils. The degree of expansion and rate of viscosity development is proportional to the amount of carboxylation.

[00089] The hydration test was repeated using 2.4 g of polymer and 0.012 g fumaric acid in 1 liter of the fluid described in Example 1, and viscosity measurements were made at 511 se⁻¹ with a Fann 35 viscometer. Initially, the polymer solution contained 0.1% v/v aqueous tetramethylammonium chloride (TMAC). Subsequently potassium chloride was added to 2% w/v. The viscosities of the two solutions are presented in Table 5. The percent decline is calculated as the difference between the 0.1% TMAC sample and the 0.1% TMAC+2% KCL sample, divided by the 0.1% TMAC sample, multiplied by 100%.

[00002]

TABLE 5
Viscosity of solutions containing salts
	Viscosity (cP at 511 sec-1)
Polymer	0.1% TMAC	0.1% TMAC + 2% KCL	% Decline
Guar	12.0	12.0	0
0.03 DS CMG	12.0	10.5	12.5
0.06 DS CMG	13.0	11.0	15.4
0.09 DS CMG	14.0	12.0	14.3

[00090] This example shows that the viscosity increases with increasing carboxylation of the polymer. This example also shows that salts tend to neutralize the ionic effects responsible for enhanced polymer chain expansion causing the viscosity to decrease. Notice that the viscosity of guar, a non-ionic polymer, is unaffected by the addition of salt. The collapse of chain expansion and reduction in viscosity due to salt may enhance well clean-up processes after the fracturing treatment as the fracturing fluid becomes contaminated with saline formation water or salts present in the treated formation.

[00091] Fracturing fluid was prepared by adding 2.4 g of guar gum (commercially available as GW-4 (without anionic substitution), BJ Services, Houston, Tex.) to 1 liter of deionized water. Afterward, 1 ml of a 50% aqueous tetramethyl ammonium chloride solution was added to the hydrating polymer solution. The polymer solution viscosity was measured with a Fann 35 viscometer and found to have 14.5 cP at 511 sec⁻¹. After about 30 minutes, the pH of the fluid was adjusted to 10.45 with a 3.0 ml of 45% aqueous potassium carbonate solution, followed by the addition of 3.0 ml of a sodium tetraborate tetrahydrate in glycerol (XLW-4, available from BJ Services, Houston, Tex.). The boron content of the borate crosslinker was 5.50% as B₂O₃.

[00092] About 45 g of this solution was weighed into a Fann 50C cup. The cup was then placed on a Fann 50C viscometer and pressured to about 200 psi (14 kg/cm²) with nitrogen. The sample was sheared at 450 sec⁻¹ for 2 minutes, followed by a rate sweep using 105, 85, 64, and 42 sec⁻¹ for about 2 minutes. The oil bath temperature was pre-set to 180° F. (82° C.) and the bath was raised to submerge the sample cup. The rate sweep was repeated every 30 minutes, and the interim rate between sweeps was 105 sec⁻¹. The stresses associated to each rate used in the sweep together with the rates were used to calculate the Power Law indices n′ and K′. The n′ is referred to as the flow behavior index and the K′ is the consistency index in the American Petroleum Institute's Bulletin RP-39. The bulletin also provides a method to calculate the viscosity of a pseudoplastic fracturing fluid using the n′ and K′ values. The calculated viscosities of the fluid described in this example, as well as the other examples unless otherwise noted, are presented at 40 sec⁻¹. The fluid in this example showed an initial viscosity of 352 cP at 40 sec⁻¹ at a temperature of 183° F. (84° C.). After 30 minutes, the fluid viscosity remained about 350 cP at 40 sec⁻¹ and a pH of 10.4. A viscosity of 200 cP at 40 sec⁻¹ is presently preferred to transport proppant during the fracturing treatment. This fluid showed no sign of degrading in the first 30 minutes, but had a relatively lower viscosity than the polymer used in Example 5.

[00093] Example 3 was repeated, except that 2.40 g of carboxymethyl guar having a degree of substitution of 0.15 (commercially available as GW-45, BJ Services, Houston, Tex.) was substituted for the guar gum. A volume of 5.0 ml of sodium tetraborate tetrahydrate in glycerol (XLW-4, available from BJ Services, Houston, Tex.) was found to be optimum for this Example. The boron content of the borate crosslinker was 5.50% as B₂O₃. The polymer solution was treated as described above and placed in a Fann 50C cup. The polymer solution viscosity was measured with a Fann 35 viscometer and found to have 21.3 cP at 511 sec⁻¹. After 30 minutes on the Fann 50, the viscosity was 15 cP at 40 sec⁻¹, and after an hour was 16 cP at 40 sec⁻¹. The Farm 50 results suggest that little, because of the low viscosity, if any, cross-linking occurred with the borate cross-linker under these conditions.

[00094] Example 4 was repeated, except that 2.40 g of carboxymethyl guar having a DS of 0.04 was substituted for the guar gum (the polymer was obtained from Rhone Poulenc, Cranbury, N.J.; sample number SCN 13738). Sodium tetraborate tetrahydrate in glycerol (XLW-4, available from BJ Services, Houston, Tex.) was added to give a boron content of 5.50% as B₂O₃. The polymer solution viscosity was measured with a Fann 35 viscometer and found to be 15.6 cP at 511 sec⁻¹. The Fann 50 results indicated that after 30 minutes, the viscosity of the polymer solution was 645 cP at 40 sec⁻¹, after an hour was 575 cP at 40 sec⁻¹, and after two hours was 477 cP at 40 sec⁻¹.

[00095] It should be noted that the viscosity of the polymer solution of Example 5 was lower than the solution in Example 4, suggesting the molecular weight of the polymer is less than that used in Example 4. However, after 30 minutes on the Fann 50, the cross-linked viscosity was nearly doubled that of Example 3 (using an unsubstituted guar gum) and 43 times higher than Example 4 (using a guar gum with a relatively high degree of substitution).

[00096] In this experiment, various polymers were compared as components in a fracturing fluid. The fluid was prepared by adding 1.0 ml of a 50 weight % aqueous solution of tetramethylammonium chloride and 2.40 g of polymer to 1 liter of rapidly agitated DI water. The polymers were obtained from the Aqualon Division of Hercules (Kenedy, Tex.). Fumaric acid (0.024 g) was added to allow adequate polymer hydration. After 30 minutes of hydration, the polymer solution was treated with 10.0 ml of a 45 wt. % aqueous solution of potassium carbonate to increase the fluid pH to above 10. Lastly, the fluid was treated with 5.0 ml of a borate crosslinker comprised as a diesel slurry containing two borate ores, colemanite and ulexite and supplied by the TBC Brinadd (Houston, Tex.) as FracSal II and contains 21.4% boron measured as B₂O₃.

[00097] After mixing, 45.0 g of fluid was placed in the sample cup and placed on a Fann 50C viscometer having a couette geometry with R1B5 wetted tools. The rheometer was pressured to 200 psi (14 kg/cm²) with nitrogen and sheared at 100 sec⁻¹ while heating to 200° F. (93° C.). Once at temperature, viscosity measurements at 100 sec⁻¹ were periodically made. The data is shown below in Table 6. “DS” refers to degree of substitution; “CMG” refers to carboxymethyl guar; and “NDT” refers to No Detectable Torque, suggesting a viscosity of less than 5 cP.

[00002]

TABLE 6
Comparison of polymers
	Viscosity (cP at 100 sec−1)	pH
Polymer	30 min	60 min	90 min	120 min	Before/After
Guar	NDT	NDT	NDT	NDT	11.1/10.2
0.03 DS CMG	91	74	82	60	11.1/10.3
0.06 DS CMG	231	285	237	268	11.2/10.5
0.09 DS CMG	266	286	352	329	11.2/10.0
0.15 DS CMG	NDT	5	5	5	11.2/10.2

[00098] This example shows that improved viscosity can be obtained using lower concentrations of polymer in the fracturing fluid. Furthermore, the data suggests that improved viscosity of fracturing fluids can be obtained from carboxymethyl guars having degree of substitution values ranging from 0.03 to about 0.09 and crosslinked with borate ions. Polymers having degree of substitution values about 0.15 or more perform poorly, as does guar itself, and do not adequately crosslink with borate based complexors with low amounts of polymer at temperatures above 150° F. (66° C.).

[00099] In this example, the intrinsic viscosity and C* value of the low degree of substitution polymers were determined. The moisture content of each polymer was determined and dilute solutions were prepared by dissolving about 0.25 g of “active” polymer, accounting for moisture, and 0.012 g fumaric acid in 1 liter of DI water containing 1.0 ml of a 50 weight % aqueous solution of tetramethylammonium chloride. After hydrating overnight, the solutions were further diluted with DI water containing 0.1% by volume tetramethylammonium chloride per liter of water to give polymer solutions of about 2.5×10⁻⁵ g/ml concentration (actual concentration in g/dL shown in Table 7 below).

[00100] The intrinsic viscosity was determined using a single point method described in the ASTM procedure D 4603-96, “Standard Test Method for Determining Inherent Viscosity of Poly(Ethylene Terephthalate) (PET) by Glass Capillary Viscometer”. The viscosity was measured in a Canon Fenske 100 tube and a constant temperature bath set at 78° F. (26° C.). The time necessary to drain the tube of 10 ml of the water used to dilute the polymer solutions described above was determined five times (t₀). Next, the time required to drain each polymer solution was also measured five times each (t).

[00101] The intrinsic viscosity was calculated using equation 1 described in the ASTM method:
Intrinsic Viscosity=0.25(μr−1+3 ln μr)/C  Equation 1

[00103] Where μr=relative viscosity (t/t₀); t=average solution flow time (sec); t₀=average solvent flow time (sec); and C=polymer solution concentration (g/dL).

[00104] Once the intrinsic viscosity was determined, the C* value was calculated using Equation 2:
C*=2/[Intrinsic Viscosity]  Equation 2

[00106] The factor 2 in the numerator of Equation 2 was found to provide a reasonable estimate of the C* value of carboxymethyl guar polymers. The method reported by Geoffrey Robinson, Simon B. Ross-Murphy and Edwin R. Morris, “Viscosity-Molecular Weight Relationships, Intrinsic Chain Flexibility, and Dynamic Solution Properties of Guar Galactomannan” Carbohydrate Research, 107 (1982) p 17-32 provides a more rigorous method of determination of the C* value. The intrinsic viscosity and C* values of the various polymers are provided in Table 7.

[00002]

	TABLE 7
		Conc. For Eq 1	Intrinsic Viscosity	C*
	Polymer	(g/dL)	(dL/g)	(g/dL)
	Guar	4.998 × 10−3	13.24	—
	0.03 DS CMG	5.001 × 10−3	14.68	0.136
	0.06 DS CMG	4.993 × 10−3	18.44	0.108
	0.09 DS CMG	4.999 × 10−3	22.15	0.090

[00107] These results show favorable results obtained using polymers with degrees of substitution of about 0.03 to about 0.10, and C* values from about 0.08 weight percent to about 0.12 weight percent.

[00108] As demonstrated above, embodiments of the invention provide a fracturing fluid and a method of making and using the fracturing fluid. The fracturing fluid in accordance with some embodiments of the invention has improved fracture conductivity due to the use of a borate cross-linking agent. When reduced polymer loading is used, the resulting fracturing fluid may still be cross-linked by a borate or other cross-linking agent. As a result of the reduced polymer loading, less formation damage is caused by the fracturing fluid. The reduced polymer loading may also enhance the fracture conductivity. Moreover, because less polymers are used, the costs associated with well treatments are reduced. Additional characteristics and advantages provided by embodiments of the invention are apparent to those skilled in the art.

[00109] While the invention has described with respect to a limited number of embodiments, these embodiments are not intended to limit the scope of the invention as otherwise described and claimed herein. Variations and modifications from the described embodiments exist. For example, although a borate cross-linking agent is exemplified as a preferred cross-linking agent, this does not preclude the use of other types of cross-linking agents, such as antimony-based cross-linking agents. Similarly, although guar polymers are exemplified as preferred polymers in formulating a fracturing fluid, this does not preclude the use of other types of polymers, both synthetic and natural. While the preferred range of the degree of substitution is from about 0.01 to about 0.1, the range may change due to different types of ionic groups. Thus, other ranges of degree of substitution may yield similar or better results. Generally, it is more economical to employ an aqueous fluid to form a fracturing fluid, this does not preclude a non-aqueous fluid being formulated and used in accordance with embodiments of the invention. In cases where water is no longer the predominant component of a fracturing fluid, a hydratable or water-soluble polymer may not be necessary. Instead, other polymers such as water insoluble polymers, may be used. In describing the method of making and using the fracturing fluid, various steps are disclosed. These steps may be practiced in any order or sequence unless otherwise specified. Moreover, one or more steps may be combined into one single step. Conversely, one step may be practiced in two or more sub-steps. Whenever a number is disclosed herein, it should be interpreted to mean “about” or “approximate”, regardless of whether these terms are used in describing the number. The appended claims intend to cover all such variations and modifications as failing within the scope of the invention.

[00110] All of the compositions and/or methods disclosed and claimed herein can be made and executed without undue experimentation in light of the present disclosure. While the compositions and methods of this invention have been described in terms of preferred embodiments, it will be apparent to those of skill in the art that variations may be applied to the compositions and/or methods and in the steps or in the sequence of steps of the methods described herein without departing from the concept, spirit and scope of the invention. More specifically, it will be apparent that certain agents which are chemically related may be substituted for the agents described herein while the same or similar results would be achieved. All such similar substitutes and modifications apparent to those skilled in the art are deemed to be within the spirit, scope and concept of the invention.