CA2783471C - Method of fracturing subterranean formations with crosslinked fluid - Google Patents
Method of fracturing subterranean formations with crosslinked fluid Download PDFInfo
- Publication number
- CA2783471C CA2783471C CA2783471A CA2783471A CA2783471C CA 2783471 C CA2783471 C CA 2783471C CA 2783471 A CA2783471 A CA 2783471A CA 2783471 A CA2783471 A CA 2783471A CA 2783471 C CA2783471 C CA 2783471C
- Authority
- CA
- Canada
- Prior art keywords
- fracturing fluid
- fluid
- entrance site
- apparent viscosity
- viscosity
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired - Fee Related
Links
Classifications
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/62—Compositions for forming crevices or fractures
- C09K8/66—Compositions based on water or polar solvents
- C09K8/68—Compositions based on water or polar solvents containing organic compounds
- C09K8/685—Compositions based on water or polar solvents containing organic compounds containing cross-linking agents
Abstract
Subterranean formations, such as tight gas formations, may be subjected to hydraulic fracturing by introducing into the formation a fracturing fluid of an aqueous fluid, a hydratable polymer, a crosslinking agent and proppant. The fracturing fluid is prepared in a blender and then pumped from the blender into the wellbore which penetrates the formation. The fluid enters the reservoir through an entrance site. The apparent viscosity of the fluid decreases distally from the entrance site such that at least one of the following conditions prevails at in situ conditions: (a) the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the apparent viscosity of the fracturing fluid at the entrance site; (b) the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 15% of the apparent viscosity of the fracturing fluid at the entrance site; or (c) the apparent viscosity of the fracturing fluid is less than 10 cP within 15 minutes after being introduced through the entrance site.
Description
APPLICATION FOR PATENT
INVENTOR: CHARLES ELMER BELL; HAROLD DEAN
BRANNON
TITLE: METHOD OF FRACTURING SUBTERRANEAN
FORMATIONS WITH CROSSLINKED FLUID
SPECIFICATION
Field of the Invention [0001] The invention relates to a method of fracturing a subterranean formation with an aqueous fluid which contains a hydratable polymer and a crosslinking agent wherein the apparent viscosity of the fluid decreases distally from the entrance site of the reservoir.
Background of the Invention [0002]
Hydraulic fracturing often requires the use of well treating materials capable of enhancing the production of fluids and natural gas from low permeability formations. In a typical hydraulic fracturing treatment, a fracturing treatment fluid containing a solid proppant is injected into the formation at a pressure sufficiently high enough to cause the formation or enlargement of fractures in the reservoir. The fractures radiate outwardly from the wellbore, typically from a few meters to hundreds of meters, and extend the surface area from which oil or gas drains into the well. The proppant is deposited in the fracture, where it remains after the treatment is completed. After deposition, the proppant serves to prevent closure of the fracture and to form a conductive channel extending from the wellbore into the formation being treated. As such, the proppant enhances the ability of fluids or natural gas to migrate from the formation to the wellbore through the fracture.
INVENTOR: CHARLES ELMER BELL; HAROLD DEAN
BRANNON
TITLE: METHOD OF FRACTURING SUBTERRANEAN
FORMATIONS WITH CROSSLINKED FLUID
SPECIFICATION
Field of the Invention [0001] The invention relates to a method of fracturing a subterranean formation with an aqueous fluid which contains a hydratable polymer and a crosslinking agent wherein the apparent viscosity of the fluid decreases distally from the entrance site of the reservoir.
Background of the Invention [0002]
Hydraulic fracturing often requires the use of well treating materials capable of enhancing the production of fluids and natural gas from low permeability formations. In a typical hydraulic fracturing treatment, a fracturing treatment fluid containing a solid proppant is injected into the formation at a pressure sufficiently high enough to cause the formation or enlargement of fractures in the reservoir. The fractures radiate outwardly from the wellbore, typically from a few meters to hundreds of meters, and extend the surface area from which oil or gas drains into the well. The proppant is deposited in the fracture, where it remains after the treatment is completed. After deposition, the proppant serves to prevent closure of the fracture and to form a conductive channel extending from the wellbore into the formation being treated. As such, the proppant enhances the ability of fluids or natural gas to migrate from the formation to the wellbore through the fracture.
[0003] Many different materials have been used as proppants including sand, glass beads, walnut hulls, and metal shot as well as resin-coated sands, intermediate strength ceramics, and sintered bauxite; each employed for their ability to cost effectively withstand the respective reservoir closure stress environment. The apparent specific gravity (ASG) of these materials is indicative of relative strength;
the ASG of sand being 2.65 and the ASG of sintered bauxite being 3.4. While increasing ASG provides greater strength, it also increases the degree of difficulty of proppant transport and reduces propped fracture volume. Fracture conductivity is therefore often reduced by the use of materials having high ASG. More recently, attention has been drawn to the use of ultra lightweight (ULW) materials as proppant materials. Such materials have an apparent specific gravity (ASG) less than or equal to 2.45.
the ASG of sand being 2.65 and the ASG of sintered bauxite being 3.4. While increasing ASG provides greater strength, it also increases the degree of difficulty of proppant transport and reduces propped fracture volume. Fracture conductivity is therefore often reduced by the use of materials having high ASG. More recently, attention has been drawn to the use of ultra lightweight (ULW) materials as proppant materials. Such materials have an apparent specific gravity (ASG) less than or equal to 2.45.
[0004] It is generally desirable for the fracturing fluid to reach maximum viscosity as it enters the fracture. The viscosity of most fracturing fluids may be attributable to the presence of a viscosifying agent, such as a viscoelastic surfactant or a viscosifying polymer, in the fluid. Conventional viscosifying polymers include such water-soluble polysaccharides as galactomannans and cellulose derivatives.
The presence of a crosslinking agent, such as one which contains borate (or generates borate), titanate, or zirconium ions, in the fracturing fluid can further increase the viscosity. The increased viscosity of the gelled fracturing fluid affects both fracture length and width, and serves to place the proppant within the produced fracture.
The presence of a crosslinking agent, such as one which contains borate (or generates borate), titanate, or zirconium ions, in the fracturing fluid can further increase the viscosity. The increased viscosity of the gelled fracturing fluid affects both fracture length and width, and serves to place the proppant within the produced fracture.
[0005]
Recently, low viscosity fluids (such as water, salt brine and slickwater) which do not contain a viscoelastic surfactant or viscosifying polymer have been used in the stimulation of low permeability formations. Such formations are also known as tight formations (including tight gas shale reservoirs exhibiting complex natural fracture networks). To effectively access tight formations wells are often drilled horizontally and then subjected to one or more fracture treatments to stimulate production. Fractures propagated with low viscosity fluids exhibit smaller fracture widths than experienced with relatively higher viscosity fluids, resulting in development of greater created fracture area from which the hydrocarbons can flow into the high conductive fracture pathways. In low permeability reservoirs, fracture area is generally considered proportional to the effectiveness of the fracture stimulation. Therefore, low viscosity fluids are generally preferred for stimulation of tight gas shale reservoirs.
Recently, low viscosity fluids (such as water, salt brine and slickwater) which do not contain a viscoelastic surfactant or viscosifying polymer have been used in the stimulation of low permeability formations. Such formations are also known as tight formations (including tight gas shale reservoirs exhibiting complex natural fracture networks). To effectively access tight formations wells are often drilled horizontally and then subjected to one or more fracture treatments to stimulate production. Fractures propagated with low viscosity fluids exhibit smaller fracture widths than experienced with relatively higher viscosity fluids, resulting in development of greater created fracture area from which the hydrocarbons can flow into the high conductive fracture pathways. In low permeability reservoirs, fracture area is generally considered proportional to the effectiveness of the fracture stimulation. Therefore, low viscosity fluids are generally preferred for stimulation of tight gas shale reservoirs.
[0006]
Slickwater fluids are basically fresh water or brine having sufficient friction reducing agent to minimize tubular friction pressures. Generally, such fluids have viscosities only slightly higher than unadulterated fresh water or brine;
typically, the friction reduction agents present in slickwater do not increase the viscosity of the fracturing fluid by any more than 1 to 2 cP. Such fluids are much cheaper than conventional fracturing fluids which contain a viscosifying agent. In addition, their characteristic low viscosity facilitates reduced fracture height growth in the reservoir during stimulation. Further, such fluids introduce less damage into the formation in light of the absence of a viscosifying polymer and/or viscoelastic surfactant in the fluid.
Slickwater fluids are basically fresh water or brine having sufficient friction reducing agent to minimize tubular friction pressures. Generally, such fluids have viscosities only slightly higher than unadulterated fresh water or brine;
typically, the friction reduction agents present in slickwater do not increase the viscosity of the fracturing fluid by any more than 1 to 2 cP. Such fluids are much cheaper than conventional fracturing fluids which contain a viscosifying agent. In addition, their characteristic low viscosity facilitates reduced fracture height growth in the reservoir during stimulation. Further, such fluids introduce less damage into the formation in light of the absence of a viscosifying polymer and/or viscoelastic surfactant in the fluid.
[0007] While the use of low viscosity fluids is desirable for use in the stimulation of low permeability formations, the pumping of proppant-laden slickwater fluids has proven to be costly since proppant consistently settles in the manifold lines before the fluid reaches the wellhead. This is particularly evident when the fracturing fluid contains a higher concentration of proppant and/or when the proppant employed has an ASG in excess of 2.45. Such materials are very likely to settle in the manifolds before the fluid ever reaches the wellhead.
Since proppant settling is affected by the viscosity of the treatment fluid, a high pump velocity is required to prevent settling. However, under certain conditions rate alone is insufficient to prevent settling as settling is also dependent on proppant size and specific gravity. Further, since manifolds have different dimensions, mere modification of fluid pump rate in one area may not address the problem in another.
Since proppant settling is affected by the viscosity of the treatment fluid, a high pump velocity is required to prevent settling. However, under certain conditions rate alone is insufficient to prevent settling as settling is also dependent on proppant size and specific gravity. Further, since manifolds have different dimensions, mere modification of fluid pump rate in one area may not address the problem in another.
[0008] In addition to the settling of proppant in the manifold lines, there is a real danger of proppant settling inside the fluid end of the pump. Within the pump, pistons move under a sinusoidal wave pattern. As such, the pistons move slowly, then faster, then slow and then stop momentarily. The process repeats for each of the pistons. Settling of proppant in the housing of the pump may damage the pistons as the pistons attempt to move or crush the proppant. This is particularly a problem when proppants are composed of high compressive strength, such as ceramics.
[0009] Proppant settling from low viscosity treating fluids within the horizontal section of the wellbore is also of concern. Such settling can occur as a result of insufficient slurry flow velocity and/or insufficient viscosity to suspend the proppant. Excessive proppant settling within a horizontal wellbore can necessitate cessation of fracturing treatments prior to placement of the desired volumes.
In order to mitigate settling issues, high pumping rates are typically employed to effectively suspend the proppant for transport within the horizontal wellbore section. However, high pumping rates can result in higher than desirable treating pressures and excessive fracture height growth.
In order to mitigate settling issues, high pumping rates are typically employed to effectively suspend the proppant for transport within the horizontal wellbore section. However, high pumping rates can result in higher than desirable treating pressures and excessive fracture height growth.
[00010] Alternatives are desired therefore for proppant-laden fracturing fluids which provide the benefits of slickwater in tight gas reservoirs but which do not cause damage to pumping equipment or do not allow for proppant settling in horizontal wellbores.
Summary of the Invention [00011] A method of fracturing having particular applicability in tight gas reservoirs consists of blending water and a viscosifying polymer, crosslinking agent and proppant in a mixer and introducing the viscous fluid into the wellhead.
The viscosity of the fracturing fluid during blending is typically between from about 10 to about 120 cP at a temperature range between from about 80 F to about 125 F.
Increased viscosity at the surface (during blending) protects the surface equipment when pumping the suspended proppant into the wellhead. In addition, the viscous nature of the fracturing fluid enables the fluid to transport the proppant to the perforating sites in the wellbore while minimizing settling.
Summary of the Invention [00011] A method of fracturing having particular applicability in tight gas reservoirs consists of blending water and a viscosifying polymer, crosslinking agent and proppant in a mixer and introducing the viscous fluid into the wellhead.
The viscosity of the fracturing fluid during blending is typically between from about 10 to about 120 cP at a temperature range between from about 80 F to about 125 F.
Increased viscosity at the surface (during blending) protects the surface equipment when pumping the suspended proppant into the wellhead. In addition, the viscous nature of the fracturing fluid enables the fluid to transport the proppant to the perforating sites in the wellbore while minimizing settling.
[00012] The loading of the hydratable polymer in the fracturing fluid is from about 6 to about 18 pptg, preferably from about 6 to about 12 pptg. The low loading of the viscosifying polymer in the fracturing fluid causes the viscosity of the fluid to rapidly decrease upon entering the entrance site of perforation.
[00013] Even without breakers, the fluid is heat sensitive and degrades quickly such that the viscosity of the fluid within 100 feet from the perforation is no greater than about 5 cP, typically no greater than about 3 cP.
[00014] The viscosifying polymer is preferably a hydratable polymer including galactomannan gums, guars, derivatized guars, cellulose and cellulose derivatives, starch, starch derivatives, xanthan, derivatized xanthan and mixtures thereof.
Particularly preferred viscosifying polymers are derivatized and underivatized guars having an intrinsic viscosity greater than about 14 dL/g, more typically greater than 16dL/g.
Particularly preferred viscosifying polymers are derivatized and underivatized guars having an intrinsic viscosity greater than about 14 dL/g, more typically greater than 16dL/g.
[00015] The method described has particular applicability in low permeability reservoirs, such as those having permeabilities between from about 10 nanodarcies to about 1.0 mD, including shale and limestone.
Brief Description of the Drawings [00016] In order to more fully understand the drawings referred to in the detailed description of the present invention, a brief description of each drawing is presented, in which:
Brief Description of the Drawings [00016] In order to more fully understand the drawings referred to in the detailed description of the present invention, a brief description of each drawing is presented, in which:
[00017] FIG. 1 is a schematic representation of the invention illustrating the viscosity profile of a fracturing fluid from the time the fluid is blended until the fluid travels distally 1,000 feet from the reservoir perforation site.
[00018] FIGs. 2 through 6 are viscosity and temperature profiles over time of aqueous fracturing fluids defined herein.
Detailed Description of the Preferred Embodiments [00019] The fracturing method, defined by the invention, uses a fracturing fluid which is prepared by blending together an aqueous fluid, a hydratable polymer, a crosslinking agent and proppant (and buffering agent, if needed) in a blender.
The blending typically occurs on-the-fly. As the fluid is pumped from the blender into the wellhead, sufficient viscosity is developed such that proppant does not tend to settle from the fluid. As such, proppant settling in the manifold lines and the housing of the pump is minimized (to the extent that any settling occurs).
Thus, unlike slickwater fluids, the fracturing fluids described herein minimize pump failures or damage to the pistons and/or manifolds of the pump.
Detailed Description of the Preferred Embodiments [00019] The fracturing method, defined by the invention, uses a fracturing fluid which is prepared by blending together an aqueous fluid, a hydratable polymer, a crosslinking agent and proppant (and buffering agent, if needed) in a blender.
The blending typically occurs on-the-fly. As the fluid is pumped from the blender into the wellhead, sufficient viscosity is developed such that proppant does not tend to settle from the fluid. As such, proppant settling in the manifold lines and the housing of the pump is minimized (to the extent that any settling occurs).
Thus, unlike slickwater fluids, the fracturing fluids described herein minimize pump failures or damage to the pistons and/or manifolds of the pump.
[00020] Unlike slickwater fluids, the fracturing fluid defined herein is viscous which is required in order to transport the proppant from the blender to the wellhead. Since the loading of polymer in the fracturing fluid is low, the apparent viscosity of the fluid dramatically decreases after it enters into the reservoir. For instance, at in-situ conditions, the apparent viscosity of the fracturing fluid 100 feet from the reservoir perforation sites (or entrance site) may be less than 10 percent of the apparent viscosity of the fracturing fluid at the entrance site of the reservoir.
Preferably, the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 5 percent of the viscosity of the fracturing fluid at the entrance site.
More preferably, the apparent viscosity of the fluid 200 feet from the entrance site is less than 1 percent of the viscosity of the fracturing fluid at the entrance site.
Preferably, the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 5 percent of the viscosity of the fracturing fluid at the entrance site.
More preferably, the apparent viscosity of the fluid 200 feet from the entrance site is less than 1 percent of the viscosity of the fracturing fluid at the entrance site.
[00021] Alternatively, the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site may be less than 15% of the apparent viscosity of the fracturing fluid at the reservoir entrance site. More typically, the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 10% of the apparent viscosity of the fracturing fluid at the entrance site. Alternatively, the apparent viscosity of the fracturing fluid minutes after introduction into the entrance site is less than 5% of the apparent viscosity of the fracturing fluid at the entrance site.
[00022] In another embodiment, the apparent viscosity of the fracturing fluid may be less than 10 cP within 15 minutes after being introduced through the entrance site of the reservoir. More typically, the apparent viscosity of the fracturing fluid is less than 5 cP within 15 minutes after being introduced through the entrance site. Alternatively, the apparent viscosity of the fracturing fluid is less than 3 cP within 30 minutes after being introduced through the entrance site.
[00023] FIG. 1 illustrates a typical profile of the fracturing fluid defined herein as compared to fracturing fluids of the prior art. As illustrated, the fracturing fluid defined herein is labeled as "Fracturing Fluid". The Fracturing Fluid is compared to a conventional crosslinked gel which does not contain a delayed crosslinking agent and a conventional crosslinked gel which does contain a delayed crosslinking agent. In addition, the Fracturing Fluid is compared to slickwater. For each of the four fluids, it is assumed that an equivalent amount of proppant is in each fluid.
The apparent viscosity of each of the fluids is then compared at the blender (where the crosslinking agent, hydratable polymer, proppant, and optionally a pH
buffering agent, are mixed with the aqueous fluid), the high pressure pump where the fluid is pumped into the wellhead, at the wellhead itself and at the wellbore. The apparent viscosity is then shown at the perforation, 100 ft from the perforation, 200 ft from the perforation, 500 ft from the perforation and 1,000 ft from the perforation. The Fracturing Fluid is shown as having the approximate apparent viscosity as the delayed and non-delayed crosslinked fluids at the blender and high pressure pump.
Further, the Fracturing Fluid is shown as having the approximate apparent viscosity as the delayed crosslinked fluid at the wellhead. At the wellbore and at the perforating site (entrance into the reservoir); the viscosity of the Fracturing Fluid approximates the viscosity of the conventional crosslinked fluid which does not contain a delayed crosslinking agent. As the Fracturing Fluid extends distally from the perforating site, the apparent viscosity of the Fracturing Fluid decreases. When the Fracturing Fluid is about 200 ft from the perforating entrance, the apparent viscosity of the Fracturing Fluid approximates the apparent viscosity of slickwater.
The apparent viscosity of each of the fluids is then compared at the blender (where the crosslinking agent, hydratable polymer, proppant, and optionally a pH
buffering agent, are mixed with the aqueous fluid), the high pressure pump where the fluid is pumped into the wellhead, at the wellhead itself and at the wellbore. The apparent viscosity is then shown at the perforation, 100 ft from the perforation, 200 ft from the perforation, 500 ft from the perforation and 1,000 ft from the perforation. The Fracturing Fluid is shown as having the approximate apparent viscosity as the delayed and non-delayed crosslinked fluids at the blender and high pressure pump.
Further, the Fracturing Fluid is shown as having the approximate apparent viscosity as the delayed crosslinked fluid at the wellhead. At the wellbore and at the perforating site (entrance into the reservoir); the viscosity of the Fracturing Fluid approximates the viscosity of the conventional crosslinked fluid which does not contain a delayed crosslinking agent. As the Fracturing Fluid extends distally from the perforating site, the apparent viscosity of the Fracturing Fluid decreases. When the Fracturing Fluid is about 200 ft from the perforating entrance, the apparent viscosity of the Fracturing Fluid approximates the apparent viscosity of slickwater.
[00024] The viscosifying polymer of the fracturing fluid defined herein may be a thickening polymer such as a hydratable polymer like, for example, one or more polysaccharides capable of forming a crosslinked gel. These include galactomannan gums, guars, derivatized guars, cellulose and derivatized celluloses, starch, starch derivatives, xanthan, derivatized xanthan and mixtures thereof.
Specific examples include, but are not limited to, guar gum, guar gum derivative, locust bean gum, welan gum, karaya gum, xanthan gum, scleroglucan, diutan, cellulose and cellulose derivatives, etc. More typical polymers or gelling agents include guar gum, hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar (CMHPG), hydroxyethyl cellulose (HEC), carboxymethyl hydroxyethyl cellulose (CMHEC), carboxymethyl cellulose (CMC), dialkyl carboxymethyl cellulose, etc.
Other examples of polymers include, but are not limited to, phosphomannans, .WO 2011/075629 = scleroglucans and dextrans. In a preferred embodiment, underivatized guar is employed.
Specific examples include, but are not limited to, guar gum, guar gum derivative, locust bean gum, welan gum, karaya gum, xanthan gum, scleroglucan, diutan, cellulose and cellulose derivatives, etc. More typical polymers or gelling agents include guar gum, hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar (CMHPG), hydroxyethyl cellulose (HEC), carboxymethyl hydroxyethyl cellulose (CMHEC), carboxymethyl cellulose (CMC), dialkyl carboxymethyl cellulose, etc.
Other examples of polymers include, but are not limited to, phosphomannans, .WO 2011/075629 = scleroglucans and dextrans. In a preferred embodiment, underivatized guar is employed.
[00025] Especially preferred are those derivatized and underivatized guars set forth in U.S. Patent Publication No. 20050272612 published on December 8,2005.
Such derivatized and underivatized guars are characterized by an intrinsic viscosity greater than about 14 dL/g, more typically greater than 16dL/g. This viscosity is indicative of higher molecular weight than that normally seen with derivatized and underivatized guars. The guars are obtained by improvements in the processing conditions used to convert the guar split (seed endosperm) to a fine powder.
Such derivatized and underivatized guars are characterized by an intrinsic viscosity greater than about 14 dL/g, more typically greater than 16dL/g. This viscosity is indicative of higher molecular weight than that normally seen with derivatized and underivatized guars. The guars are obtained by improvements in the processing conditions used to convert the guar split (seed endosperm) to a fine powder.
[00026] The cause of the increased molecular weight is due to improved processing conditions used to convert the guar split to a fine powder. Most often, the guar split, being about 0.3 cm in diameter, is partially hydrated and sheared through a roll mill to produce a flake. The flake, being more fragile, can then be dried and pulverized by a high impact mill. Throughout this process, there are times when the guar polymer is subjected to high mechanical shear. A means of obtaining a higher molecular weight polymer occurs at those places of high mechanical shear in the process. The shear process is modified so that the ultimate amount of shear is the same, but the rate of shear is reduced to allow the polymer chains in the split to relax rather than rupture. Therefore by reducing the shearing rate, the degree of rupture is reduced and the polymer molecular weight is higher.
[00027] The crosslinking agent used in the aqueous fracturing fluid defined herein may be any crosslinking agent suitable for crosslinking the hydratable polymer. Examples of suitable crosslinking agents include metal ions such as aluminum, antimony, zirconium and titanium-containing compounds, including organotitanates. Examples of suitable crosslin.kers may also be found in U.S.
Pat.
No. 5,201,370; U.S. Pat. No. 5,514,309, U.S. Pat. No. 5,247,995, U.S. Pat. No.
5,562,160, and U.S. Patent No. 6,110,875.
Pat.
No. 5,201,370; U.S. Pat. No. 5,514,309, U.S. Pat. No. 5,247,995, U.S. Pat. No.
5,562,160, and U.S. Patent No. 6,110,875.
[00028] In a preferred embodiment, the crosslinking agent is a source of borate ions such as a borate ion donating material. Examples of borate-based crosslinking agents include, but are not limited to, organo-borates, mono-borates, poly-borates, mineral borates, etc.
[00029] To obtain a desired pH value, a pH adjusting material preferably is added to the aqueous fluid after the addition of the polymer to the aqueous fluid.
Typical materials for adjusting the pH are commonly used acids, acid buffers, and mixtures of acids and bases. Normally, a pH between from about 9.5 to about 11.5 is desired. Thus, it typically is desired to use a buffering agent that is effective to provide the pH for the fluid may be used. Suitable buffering materials include potassium carbonate or mixtures of potassium carbonate and potassium hydroxide.
[00029] To obtain a desired pH value, a pH adjusting material preferably is added to the aqueous fluid after the addition of the polymer to the aqueous fluid.
Typical materials for adjusting the pH are commonly used acids, acid buffers, and mixtures of acids and bases. Normally, a pH between from about 9.5 to about 11.5 is desired. Thus, it typically is desired to use a buffering agent that is effective to provide the pH for the fluid may be used. Suitable buffering materials include potassium carbonate or mixtures of potassium carbonate and potassium hydroxide.
[00030] The aqueous fluid is brine, fresh water or salt water.
[00031] The proppant for use in the aqueous fracturing fluid may be any proppant suitable for hydraulic fracturing known in the art. Examples include, but are not limited to, silica, quartz sand grains, glass and ceramic beads, walnut shell fragments, aluminum pellets, nylon pellets, resin-coated sand, synthetic organic particles, glass microspheres, sintered bauxite, mixtures thereof and the like.
Alternatively, the proppant may be an ULW proppant. Proppants of intermediate to high strength having an ASG in excess of 2.45 are typically preferred, however, over ULW proppants.
Alternatively, the proppant may be an ULW proppant. Proppants of intermediate to high strength having an ASG in excess of 2.45 are typically preferred, however, over ULW proppants.
[00032] The viscosity of the fracturing fluid described herein, when being pumped from the blender into the wellbore, is typically between from about 10 to about 120 cP at a temperature range between from about 80 F to about 120 F, though a viscosity between from about 10 to about 50 cP is more preferred.
[00033] The loading of the hydratable polymer in the fracturing fluid is from about 6 to about 18 pptg, preferably from about 6 to about 12 pptg. In another preferred embodiment, the polymer loading in the fracturing fluid is from about 6 to about 10 pptg. Low loading means less formation damage. Since use of the fluid enables placement of proppant earlier in the fracturing job, the total volume of fluid required for a job is decreased (in comparison to a similar job using conventional fluids). As such, the fracturing fluid defined herein offers increased fluid efficiency over conventional fluids.
[00034] When the hydratable polymer of the aqueous fracturing fluid is that disclosed in U.S. Patent No. 20050272612, it has been found that less loading of polymer is required to provide the fluid the requisite viscosity. In particular, it has been observed that fracturing fluids containing the underivatized or derivatized guar of U.S. Patent Publication No. 20050272612 require a much lower loading of polymer than a substantially similar fracturing fluid (which contains a hydratable polymer other than one disclosed in U.S. Patent Publication No. 20050272612);
the two fracturing fluids having equivalent viscosity.
the two fracturing fluids having equivalent viscosity.
[00035] At polymer loadings in excess of about 12 pptg, it is typically desirable to include a breaker in the fluid to assist in the degradation of the hydratable polymer once the fracturing fluid has entered into the fracture. Any suitable breakers are used, including, but not limited to, solid acid precursors, for example, polyglycolic acid (PGA) or polylactic acid (PLA) particles such as beads, plates, or fibers, other delayed acids, delayed oxidizers or delayed bases. In addition, enzymatic breakers known in the art may be used.
[00036] The need for friction reducers in the fluid is decreased or eliminated.
Since the loading of viscosifying polymer is low, the amount of residual polymer in the formation is decreased. In most cases, the fracturing fluid defined herein (having a minimal of a friction reducer, if any) is less damaging than those conventional fluids which contain commonly used friction reducers, such as polyacrylamides.
Since the loading of viscosifying polymer is low, the amount of residual polymer in the formation is decreased. In most cases, the fracturing fluid defined herein (having a minimal of a friction reducer, if any) is less damaging than those conventional fluids which contain commonly used friction reducers, such as polyacrylamides.
[00037] The method described herein has particular applicability in the fracturing of tight gas formations, especially those having a permeability less than 1 millidarcy. The method has applicability in those formations having a permeability of less than 100 microdarcy, and even less than 1 microdarcies. The method even has applicability in those formations having a permeability of less than 1 microdarcy and even less than 500 nanodarcies [00038] The method described herein has particular applicability in the fracturing of any formation which may be hydraulically fractured with slickwater.
.WO 2011/075629 In a preferred embodiment, the method described herein is applied to formations of shale and tight gas sands, as well as limestone.
.WO 2011/075629 In a preferred embodiment, the method described herein is applied to formations of shale and tight gas sands, as well as limestone.
[00039] While the method described herein may normally be used in horizontal wells, the method may be used in vertical wells.
[00040] The following examples are illustrative of some of the embodiments of the present invention. Other embodiments within the scope of the claims herein will be apparent to one skilled in the art from consideration of the description set forth herein.
[00041] All percentages set forth in the Examples are given in terms of weight units except as may otherwise be indicated.
[00042] Example I.
A fluid was formulated by mixing at room temperature in a blender underivatized guar having an intrinsic viscosity greater than 16 dL/g, commercially available from BJ Services Company as GW-2, a borate crosstinker, commercially available from BJ Services Company as XLW-10. The loading of the polymer in the fluid varied to be between 6 and 10 pptg (pounds per thousand gallons).
The amount of crosslinker in the fluid was varied to be between 1.0 and 3.0 gptg (gallons per thousand gallons). The fluid was buffered to a pH of 9Ø About 30 ml of the fluid was then placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (R1) cup assembly. The cup was then placed on a Fann 50 viscometer. The sample was sheared by a rate sweep of 100 sec-' for about 1 minute. FIG. 2 shows the results wherein 10 pptg of the fluid with 1 and 2gptg XLW-10 had initial viscosities of 500 cP and 350 cP, respectively, declining after 5minutes to about 400 cP and 200 cP, respectively, and after 10 minutes, to about 250 cP and 150cP, respectively. After 45 minutes, these fluids had viscosities of' between 80 and 90cP. Further, 8 pptg of the fluid having 1.5 and 2 gptg of XLW-10 crosslinker had initial viscosities of 220 and 250 cP, respectively. After 10 minutes, the 8 pptg fluids exhibited 35 to 60 cP. After 45 minutes, the fluids had viscosities of 30 and 35 cP. A 6 pptg fluid having 2-3 gptg XLW-10 had initial viscosities of 80cP, declining to between 10 and 30 cP after 10 minutes. After 45 minutes, the fluids had viscosities between 10 and 15cP.
A fluid was formulated by mixing at room temperature in a blender underivatized guar having an intrinsic viscosity greater than 16 dL/g, commercially available from BJ Services Company as GW-2, a borate crosstinker, commercially available from BJ Services Company as XLW-10. The loading of the polymer in the fluid varied to be between 6 and 10 pptg (pounds per thousand gallons).
The amount of crosslinker in the fluid was varied to be between 1.0 and 3.0 gptg (gallons per thousand gallons). The fluid was buffered to a pH of 9Ø About 30 ml of the fluid was then placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (R1) cup assembly. The cup was then placed on a Fann 50 viscometer. The sample was sheared by a rate sweep of 100 sec-' for about 1 minute. FIG. 2 shows the results wherein 10 pptg of the fluid with 1 and 2gptg XLW-10 had initial viscosities of 500 cP and 350 cP, respectively, declining after 5minutes to about 400 cP and 200 cP, respectively, and after 10 minutes, to about 250 cP and 150cP, respectively. After 45 minutes, these fluids had viscosities of' between 80 and 90cP. Further, 8 pptg of the fluid having 1.5 and 2 gptg of XLW-10 crosslinker had initial viscosities of 220 and 250 cP, respectively. After 10 minutes, the 8 pptg fluids exhibited 35 to 60 cP. After 45 minutes, the fluids had viscosities of 30 and 35 cP. A 6 pptg fluid having 2-3 gptg XLW-10 had initial viscosities of 80cP, declining to between 10 and 30 cP after 10 minutes. After 45 minutes, the fluids had viscosities between 10 and 15cP.
[00043] Example 2.
A fluid was formulated by adding GW-2 to water in a blender at room temperature and then adding to the fluid a borate crosslinker, commercially available from BJ Services Company as XLW-32. A 10% caustic solution (sodium hydroxide) was then added until pH of the fluid was about 9 and the crosslinked fluid formed in approximately 5 seconds. The loading of the polymer in the fluid was between from 0.5 gptg to 2.0 gptg. The amount of crosslinker in the fluid was varied to be between 1.25 gptg and 1.75 gptg. About 30 ml of a 10 pptg fluid was then placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (R1) cup assembly. The cup was then placed on a Fann 50 viscometer. The sample was sheared by a rate sweep of 100 sec-1 for about 1 minute. The stresses associated to each rate were used to calculate the power law indices n and K; n refers to flow behavior index and K refers to consistency index set forth in the American Petroleum Institute's Bulletin RP-39. The fluid viscosity was then calculated by using the n' and k' values. FIG. 3 demonstrates the 10 pptg fluid was acceptable at low polymer loadings at 100 F and 120 F. particular, FIG. 3 shows that the pptg fluid with 1.5 gpt XLW-32 and 1.5 gptg 10% caustic at 100 F had a maximum initial viscosity of 225 cP at 100 sec' andviscosity of 130 cP at 100 sec -after 60 minutes. Testing of the 10 pptg fluid with 1.25 gptg XLW-32 and 0.5 gptg 10% caustic showed lower initial viscosities between 160 and 175 cP and a maintained viscosity between 80 and 100 cP at 100 sec-1 after 60 minutes.
A fluid was formulated by adding GW-2 to water in a blender at room temperature and then adding to the fluid a borate crosslinker, commercially available from BJ Services Company as XLW-32. A 10% caustic solution (sodium hydroxide) was then added until pH of the fluid was about 9 and the crosslinked fluid formed in approximately 5 seconds. The loading of the polymer in the fluid was between from 0.5 gptg to 2.0 gptg. The amount of crosslinker in the fluid was varied to be between 1.25 gptg and 1.75 gptg. About 30 ml of a 10 pptg fluid was then placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (R1) cup assembly. The cup was then placed on a Fann 50 viscometer. The sample was sheared by a rate sweep of 100 sec-1 for about 1 minute. The stresses associated to each rate were used to calculate the power law indices n and K; n refers to flow behavior index and K refers to consistency index set forth in the American Petroleum Institute's Bulletin RP-39. The fluid viscosity was then calculated by using the n' and k' values. FIG. 3 demonstrates the 10 pptg fluid was acceptable at low polymer loadings at 100 F and 120 F. particular, FIG. 3 shows that the pptg fluid with 1.5 gpt XLW-32 and 1.5 gptg 10% caustic at 100 F had a maximum initial viscosity of 225 cP at 100 sec' andviscosity of 130 cP at 100 sec -after 60 minutes. Testing of the 10 pptg fluid with 1.25 gptg XLW-32 and 0.5 gptg 10% caustic showed lower initial viscosities between 160 and 175 cP and a maintained viscosity between 80 and 100 cP at 100 sec-1 after 60 minutes.
[00044] Example 3.
A fluid was formulated by mixing at a temperature range of from 75 F to 150 F in a blender water, from 2.0 to 3.0 underivatized guar having an intrinsic viscosity-greater than 16 dL/g, commercially available from BJ Services Company as GW-2LDF and 3 gpt of a self-buffering borate crosslinker, commercially available from TBC-Brinadd as PfP BXL 0.2. The pH of the fluid was buffered to 9Ø About 30 ml of the fluid was then placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (R1) cup assembly. The cup was then placed on a Fann 50 viscometer. The sample was subjected to a shear rate of 511 sec-1.
FIG. 4 shows the viscosity profiles of fluids having 8, 10 and 12 pptg. As illustrated, the crosslinked fluid viscosities of each of the example formulations were reduced by 40% to 60% due to increasing the fluid temperature from 75 F to 150 F.
A fluid was formulated by mixing at a temperature range of from 75 F to 150 F in a blender water, from 2.0 to 3.0 underivatized guar having an intrinsic viscosity-greater than 16 dL/g, commercially available from BJ Services Company as GW-2LDF and 3 gpt of a self-buffering borate crosslinker, commercially available from TBC-Brinadd as PfP BXL 0.2. The pH of the fluid was buffered to 9Ø About 30 ml of the fluid was then placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (R1) cup assembly. The cup was then placed on a Fann 50 viscometer. The sample was subjected to a shear rate of 511 sec-1.
FIG. 4 shows the viscosity profiles of fluids having 8, 10 and 12 pptg. As illustrated, the crosslinked fluid viscosities of each of the example formulations were reduced by 40% to 60% due to increasing the fluid temperature from 75 F to 150 F.
[00045] Example 4.
A fluid was formulated by adding GW-2 to water in a blender at room temperature and then adding to the fluid a self-buffering borate crosslinker, commercially available from BJ Services Company as XLW-10. The crosslinked fluid formed in approximately 5 seconds. The loading of the polymer in the fluid was between from 6 pptg to 10 gptg. The amount of crosslinker in the fluid was varied to be between 1.5 gptg and 3.0 gptg. About 30 ml of a 10 pptg fluid was then placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (R1) cup assembly. The cup was then placed on a Fann 50 viscometer. The sample was sheared by a rate sweep of 100 sec-1 for about 1 minute. The stresses associated to each rate were used to calculate the power law indices n and K; n refers to flow behavior index and K refers to consistency index set forth in the American Petroleum Institute's Bulletin RP-39. The fluid viscosity was then calculated by using the n' and k' values. FIG. 5 shows the viscosity profiles of each of the fluids as the temperatures was increased from ambient to 120 F. Initial viscosities for the example fluids at 75 F ranged from 70cP for the 6 pptg GW-2/1.5 gpt XLW-10 formulation, to 500 cP for the 10 pptg GW-2/2.0 gpt XLW-10 case. Fluid temperatures were observed to approach the desired test temperature of 120 F
after 20 minutes, at which time the 8 pptg polymer formulations exhibited viscosities between 20 cP and 30 cP. Viscosities of the 6 pptg formulations after 20 minutes were approximately 10 cP.
A fluid was formulated by adding GW-2 to water in a blender at room temperature and then adding to the fluid a self-buffering borate crosslinker, commercially available from BJ Services Company as XLW-10. The crosslinked fluid formed in approximately 5 seconds. The loading of the polymer in the fluid was between from 6 pptg to 10 gptg. The amount of crosslinker in the fluid was varied to be between 1.5 gptg and 3.0 gptg. About 30 ml of a 10 pptg fluid was then placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (R1) cup assembly. The cup was then placed on a Fann 50 viscometer. The sample was sheared by a rate sweep of 100 sec-1 for about 1 minute. The stresses associated to each rate were used to calculate the power law indices n and K; n refers to flow behavior index and K refers to consistency index set forth in the American Petroleum Institute's Bulletin RP-39. The fluid viscosity was then calculated by using the n' and k' values. FIG. 5 shows the viscosity profiles of each of the fluids as the temperatures was increased from ambient to 120 F. Initial viscosities for the example fluids at 75 F ranged from 70cP for the 6 pptg GW-2/1.5 gpt XLW-10 formulation, to 500 cP for the 10 pptg GW-2/2.0 gpt XLW-10 case. Fluid temperatures were observed to approach the desired test temperature of 120 F
after 20 minutes, at which time the 8 pptg polymer formulations exhibited viscosities between 20 cP and 30 cP. Viscosities of the 6 pptg formulations after 20 minutes were approximately 10 cP.
[00046] Example 5.
A fluid was formulated by adding 10 pptg of GW-2 to water in a blender at room temperature and then adding 3 ppt of boric acid as a crosslinker, 2 gptg of 10% caustic to bring the pH to about 9.5, and 0.125 ppt to 0.5 ppt of ammonium persulfate breaker, available from BJ Services as GBW-5. The crosslinked fluid began to form in approximately 5 seconds. About 30 ml of a 10 pptg fluid was then =
placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (RI) cup assembly. The cup was then placed on. a Farm 50 viscometer. The sample was sheared by a rate sweep of 100 sec-I for about I minute. The stresses associated to each rate were used to calculate the power law indices n and K; n refers to flow behavior index and K refers to consistency index set forth in the American Petroleum Institute's Bulletin RP-39. The fluid viscosity was then calculated by using then' and k' values. FIG. 6 shows the viscosity profiles of each of the fluids as the temperatures was increased from ambient to 150 F. Viscosities for the example fluids were approximately 40 cP after about 30 seconds, and peaked at greater than 60 cP between 2 minutes and 5 minutes. After approximately 10 minutes, the temperature had increased to about 120 F, and the viscosities of each of the fluids declined to between 10 and 15 cP. After 20 minutes, the temperature was at the target of I50 F and the fluids viscosities were observed to be less than 10 cP for each of the fluid formulations including breaker.
A fluid was formulated by adding 10 pptg of GW-2 to water in a blender at room temperature and then adding 3 ppt of boric acid as a crosslinker, 2 gptg of 10% caustic to bring the pH to about 9.5, and 0.125 ppt to 0.5 ppt of ammonium persulfate breaker, available from BJ Services as GBW-5. The crosslinked fluid began to form in approximately 5 seconds. About 30 ml of a 10 pptg fluid was then =
placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (RI) cup assembly. The cup was then placed on. a Farm 50 viscometer. The sample was sheared by a rate sweep of 100 sec-I for about I minute. The stresses associated to each rate were used to calculate the power law indices n and K; n refers to flow behavior index and K refers to consistency index set forth in the American Petroleum Institute's Bulletin RP-39. The fluid viscosity was then calculated by using then' and k' values. FIG. 6 shows the viscosity profiles of each of the fluids as the temperatures was increased from ambient to 150 F. Viscosities for the example fluids were approximately 40 cP after about 30 seconds, and peaked at greater than 60 cP between 2 minutes and 5 minutes. After approximately 10 minutes, the temperature had increased to about 120 F, and the viscosities of each of the fluids declined to between 10 and 15 cP. After 20 minutes, the temperature was at the target of I50 F and the fluids viscosities were observed to be less than 10 cP for each of the fluid formulations including breaker.
Claims (33)
1. A method of fracturing a subterranean formation penetrated by a wellbore, comprising the steps of:
formulating a viscous fracturing fluid by blending together an aqueous fluid, a hydratable polymer, a crosslinking agent and proppant in a blender;
pumping the viscous fracturing fluid from the blender into the wellbore, and through an entrance site in the wellbore into the reservoir; and propagating fractures within the reservoir while decreasing the viscosity of the viscous fracturing fluid distally from the entrance site, wherein at least one of the following conditions prevail at in situ conditions during propagation of the fractures:
(a) the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the apparent viscosity of the fracturing fluid at the entrance site;
(b) the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 15% of the apparent viscosity of the fracturing fluid at the entrance site;
or (c) the apparent viscosity of the fracturing fluid is less than 10 cP within 15 minutes after being introduced through the entrance site.
formulating a viscous fracturing fluid by blending together an aqueous fluid, a hydratable polymer, a crosslinking agent and proppant in a blender;
pumping the viscous fracturing fluid from the blender into the wellbore, and through an entrance site in the wellbore into the reservoir; and propagating fractures within the reservoir while decreasing the viscosity of the viscous fracturing fluid distally from the entrance site, wherein at least one of the following conditions prevail at in situ conditions during propagation of the fractures:
(a) the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the apparent viscosity of the fracturing fluid at the entrance site;
(b) the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 15% of the apparent viscosity of the fracturing fluid at the entrance site;
or (c) the apparent viscosity of the fracturing fluid is less than 10 cP within 15 minutes after being introduced through the entrance site.
2. The method of claim 1 , wherein the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the apparent viscosity of the fracturing fluid at the entrance site.
3. The method of claim 2, wherein the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 5 percent of the viscosity of the fracturing fluid at the entrance site.
4. The method of claim 1, wherein the apparent viscosity of the fluid 200 feet from the entrance site is less than 1 percent of the viscosity of the fracturing fluid at the entrance site.
5. The method of claim 1, wherein the subterranean formation is shale.
6. The method of claim 1, wherein the subterranean formation is a tight gas formation.
7. The method of claim 1, wherein the intrinsic viscosity of the hydratable polymer in the aqueous fluid is greater than about 14 g/dL.
8. The method of claim 7, wherein the intrinsic viscosity of the hydratable polymer in the aqueous fluid is greater than about 16 g/dL.
9. The method of claim 1, wherein the loading of the hydratable polymer in the fracturing fluid is from about 6 to about 18 pounds per thousand gallons.
10. The method of claim 9, wherein the loading of the hydratable polymer in the fracturing fluid is from about 8 to about 12 pounds per thousand gallons.
11. The method of claim 9, wherein the loading of the hydratable polymer in the fracturing fluid is from about 6 to about 10 pounds per thousand gallons.
12. The method of claim 1, wherein the hydratable polymer is guar, derivatized guar or derivatized cellulose.
13. The method of claim 1, wherein the crosslinking agent is a source of borate ions.
14. The method of claim 1, wherein the fluid further contains a buffering agent effective to provide a pH for the fluid in the range from about 9.5 to 11.5.
15. The method of claim 1, wherein the viscosity of the aqueous fluid when pumped into the wellhead is between from about 10 to about 120 cP.
16. The method of claim 15, wherein the viscosity of the aqueous fluid when pumped into the wellhead is between from about 10 to about 50 cP.
17. The method of claim 12, wherein the hydratable polymer is underivatized guar.
18. The method of claim 8, wherein the hydratable polymer is underivatized guar.
19. The method of claim 14, wherein the aqueous fluid further comprises at least one breaker.
20. A method of fracturing a subterranean formation penetrated by a wellbore, comprising:
a) pumping a viscous fracturing fluid comprising an aqueous fluid, a hydratable polymer, a crosslinking agent and proppant from a blender into the wellhead of the wellbore and through an entrance site in the wellbore into the reservoir;
b) propagating fractures within the formation; and c) decreasing the apparent viscosity of the fluid distally from the entrance site during propagation of the fractures such that the viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the viscosity of the fracturing fluid at the entrance site.
a) pumping a viscous fracturing fluid comprising an aqueous fluid, a hydratable polymer, a crosslinking agent and proppant from a blender into the wellhead of the wellbore and through an entrance site in the wellbore into the reservoir;
b) propagating fractures within the formation; and c) decreasing the apparent viscosity of the fluid distally from the entrance site during propagation of the fractures such that the viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the viscosity of the fracturing fluid at the entrance site.
21. The method of claim 20, wherein the viscosity of the aqueous fluid when pumped into the wellhead is between from about 10 to about 120 cP.
22. The method of claim 20, wherein the subterranean formation is shale.
23. The method of claim 20, wherein the loading of the hydratable polymer in the fracturing fluid is from about 6 to about 18 pounds per thousand gallons.
24. The method of claim 1, wherein the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 15% of the apparent viscosity of the fracturing fluid at the entrance site.
25. The method of claim 24, wherein the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 10% of the apparent viscosity of the fracturing fluid at the entrance site.
26. The method of claim 25, wherein the apparent viscosity of the fracturing fluid 30 minutes after introduction into the entrance site is less than 5% of the apparent viscosity of the fracturing fluid at the entrance site.
27. The method of claim 1, wherein the apparent viscosity of the fracturing fluid is less than cP within 15 minutes after being introduced through the entrance site.
28. The method of claim 27, wherein the apparent viscosity of the fracturing fluid is less than 5 cP within 15 minutes after being introduced through the entrance site.
29. The method of claim 28, wherein the apparent viscosity of the fracturing fluid is less than 3 cP within 30 minutes after being introduced through the entrance site.
30. A method of fracturing a tight subterranean formation penetrated by a wellbore comprising:
(a) pumping through a wellhead of the wellbore a viscous fracturing fluid comprising water, a hydratable polymer, a crosslinking agent and proppant;
(b) transporting the viscous fracturing fluid through an entrance site in the wellbore into the reservoir; and (c) propagating fractures in the formation while decreasing the viscosity of the viscous fracturing fluid such that at least one of the following conditions prevail:
(i) the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the apparent viscosity of the fracturing fluid at the entrance site;
(ii) the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 15% of the apparent viscosity of the fracturing fluid at the entrance site; or (iii) the apparent viscosity of the fracturing fluid is less than 10 cP
within 15 minutes after being introduced through the entrance site.
(a) pumping through a wellhead of the wellbore a viscous fracturing fluid comprising water, a hydratable polymer, a crosslinking agent and proppant;
(b) transporting the viscous fracturing fluid through an entrance site in the wellbore into the reservoir; and (c) propagating fractures in the formation while decreasing the viscosity of the viscous fracturing fluid such that at least one of the following conditions prevail:
(i) the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the apparent viscosity of the fracturing fluid at the entrance site;
(ii) the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 15% of the apparent viscosity of the fracturing fluid at the entrance site; or (iii) the apparent viscosity of the fracturing fluid is less than 10 cP
within 15 minutes after being introduced through the entrance site.
31. The method of claim 30, wherein the subterranean formation is shale.
32. The method of claim 30, wherein the loading of the hydratable polymer in the fracturing fluid is from about 6 to about 18 pounds per thousand gallons.
33. A method of fracturing a subterranean formation penetrated by a wellbore, wherein the permeability of the subterranean formation is between from about 10 nanodarcies to about 1.0 mD, the method comprising:
(a) forming a viscous fracturing fluid by blending water, viscosifying polymer, crosslinking agent and proppant in a blender, wherein the viscous fracturing fluid has a viscosity between from about 10 to about 120 cP at a temperature range between from about 80° F to about 125° F;
(b) pumping the viscous fracturing fluid from the blender into the wellhead of the wellbore while minimizing settling of proppant from the fluid during the pumping;
(c) transporting the viscous fracturing fluid through an entrance site in the wellbore;
(d) propagating fractures in the formation; and (e) decreasing the viscosity of the viscous fracturing fluid upon the fluid entering the entrance site such that at least one of the following conditions prevail:
(i) the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the apparent viscosity of the fracturing fluid at the entrance site;
(ii) the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 15% of the apparent viscosity of the fracturing fluid at the entrance site; or (iii) the apparent viscosity of the fracturing fluid is less than 10 cP
within 15 minutes after being introduced through the entrance site.
(a) forming a viscous fracturing fluid by blending water, viscosifying polymer, crosslinking agent and proppant in a blender, wherein the viscous fracturing fluid has a viscosity between from about 10 to about 120 cP at a temperature range between from about 80° F to about 125° F;
(b) pumping the viscous fracturing fluid from the blender into the wellhead of the wellbore while minimizing settling of proppant from the fluid during the pumping;
(c) transporting the viscous fracturing fluid through an entrance site in the wellbore;
(d) propagating fractures in the formation; and (e) decreasing the viscosity of the viscous fracturing fluid upon the fluid entering the entrance site such that at least one of the following conditions prevail:
(i) the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the apparent viscosity of the fracturing fluid at the entrance site;
(ii) the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 15% of the apparent viscosity of the fracturing fluid at the entrance site; or (iii) the apparent viscosity of the fracturing fluid is less than 10 cP
within 15 minutes after being introduced through the entrance site.
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US12/642,662 US8371383B2 (en) | 2009-12-18 | 2009-12-18 | Method of fracturing subterranean formations with crosslinked fluid |
| US12/642,662 | 2009-12-18 | ||
| PCT/US2010/060979 WO2011075629A1 (en) | 2009-12-18 | 2010-12-17 | Method of fracturing subterranean formations with crosslinked fluid |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2783471A1 CA2783471A1 (en) | 2011-06-23 |
| CA2783471C true CA2783471C (en) | 2014-12-09 |
Family
ID=43618766
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2783471A Expired - Fee Related CA2783471C (en) | 2009-12-18 | 2010-12-17 | Method of fracturing subterranean formations with crosslinked fluid |
Country Status (9)
| Country | Link |
|---|---|
| US (1) | US8371383B2 (en) |
| EP (1) | EP2513245A1 (en) |
| CN (1) | CN102782081B (en) |
| AU (1) | AU2010330876B2 (en) |
| BR (1) | BR112012014932A2 (en) |
| CA (1) | CA2783471C (en) |
| CO (1) | CO6541632A2 (en) |
| MX (1) | MX351767B (en) |
| WO (1) | WO2011075629A1 (en) |
Families Citing this family (23)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US9194223B2 (en) * | 2009-12-18 | 2015-11-24 | Baker Hughes Incorporated | Method of fracturing subterranean formations with crosslinked fluid |
| US8517095B2 (en) | 2010-08-09 | 2013-08-27 | Baker Hughes Incorporated | Method of using hexose oxidases to create hydrogen peroxide in aqueous well treatment fluids |
| US20130118750A1 (en) * | 2011-11-15 | 2013-05-16 | Hongren Gu | System And Method For Performing Treatments To Provide Multiple Fractures |
| US9580642B2 (en) | 2011-11-22 | 2017-02-28 | Baker Hughes Incorporated | Method for improving isolation of flow to completed perforated intervals |
| US9637675B2 (en) | 2011-11-22 | 2017-05-02 | Baker Hughes Incorporated | Use of composites having deformable core and viscosifying agent coated thereon in well treatment operations |
| US8899332B2 (en) | 2011-11-22 | 2014-12-02 | Baker Hughes Incorporated | Method for building and forming a plug in a horizontal wellbore |
| EP2817383A4 (en) * | 2012-02-22 | 2016-04-06 | Tucc Technology Llc | Hybrid aqueous-based suspensions for hydraulic fracturing operations |
| CA2899331A1 (en) * | 2013-02-11 | 2014-08-14 | Baker Hughes Incorporated | Method of fracturing subterranean formations with crosslinked fluid |
| WO2014137625A1 (en) | 2013-03-04 | 2014-09-12 | Baker Hughes Incorporated | Method of fracturing with liquefied natural gas |
| US10822935B2 (en) | 2013-03-04 | 2020-11-03 | Baker Hughes, A Ge Company, Llc | Method of treating a subterranean formation with natural gas |
| US10808511B2 (en) | 2013-03-08 | 2020-10-20 | Baker Hughes, A Ge Company, Llc | Method of enhancing the complexity of a fracture network within a subterranean formation |
| US10202833B2 (en) | 2013-03-15 | 2019-02-12 | Schlumberger Technology Corporation | Hydraulic fracturing with exothermic reaction |
| US9739132B2 (en) | 2013-08-07 | 2017-08-22 | Baker Hughes Incorporated | Well treatment fluids and methods |
| US9714375B2 (en) | 2013-08-22 | 2017-07-25 | Baker Hughes Incorporated | Delayed viscosity well treatment methods and fluids |
| AU2013399663B2 (en) | 2013-09-04 | 2017-01-12 | Halliburton Energy Services, Inc. | Fracturing fluids comprising fibers treated with crosslinkable, hydratable polymers and related methods |
| CA2954266C (en) * | 2014-08-15 | 2019-05-21 | Halliburton Energy Services, Inc. | Crosslinkable proppant particulates for use in subterranean formation operations |
| US10113405B2 (en) * | 2014-08-29 | 2018-10-30 | Independence Oilfield Chemicals, LLC | Method and materials for hydraulic fracturing with delayed crosslinking of gelling agents |
| WO2017035370A1 (en) * | 2015-08-27 | 2017-03-02 | Baker Hughes Incorporated | Methods and materials for evaluating and improving the production of geo-specific shale reservoirs |
| US20170037303A1 (en) | 2015-08-03 | 2017-02-09 | Ecolab Usa Inc. | Compositions and methods for delayed crosslinking in hydraulic fracturing fluids |
| US10550315B2 (en) | 2016-07-15 | 2020-02-04 | Ecolab Usa Inc. | Compositions and methods for delayed crosslinking in hydraulic fracturing fluids |
| US10954771B2 (en) | 2017-11-20 | 2021-03-23 | Schlumberger Technology Corporation | Systems and methods of initiating energetic reactions for reservoir stimulation |
| WO2019164694A1 (en) | 2018-02-26 | 2019-08-29 | Baker Hughes, A Ge Company, Llc | Method of enhancing conductivity from post frac channel formation |
| CN109441421B (en) * | 2018-11-16 | 2021-05-14 | 中国海洋石油集团有限公司 | Method for enhancing hydraulic impact fracturing effect |
Family Cites Families (69)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US3058909A (en) | 1957-07-23 | 1962-10-16 | Atlantic Refining Co | Method and composition for formation fracturing |
| US3215634A (en) | 1962-10-16 | 1965-11-02 | Jersey Prod Res Co | Method for stabilizing viscous liquids |
| US3743613A (en) | 1971-02-05 | 1973-07-03 | Dow Chemical Co | Galactomannan gum based composition for sealing permeable formations |
| US3974077A (en) | 1974-09-19 | 1976-08-10 | The Dow Chemical Company | Fracturing subterranean formation |
| US4242098A (en) | 1978-07-03 | 1980-12-30 | Union Carbide Corporation | Transport of aqueous coal slurries |
| US4336145A (en) | 1979-07-12 | 1982-06-22 | Halliburton Company | Liquid gel concentrates and methods of using the same |
| US4579942A (en) | 1984-09-26 | 1986-04-01 | Union Carbide Corporation | Polysaccharides, methods for preparing such polysaccharides and fluids utilizing such polysaccharides |
| US4619776A (en) | 1985-07-02 | 1986-10-28 | Texas United Chemical Corp. | Crosslinked fracturing fluids |
| US4801389A (en) | 1987-08-03 | 1989-01-31 | Dowell Schlumberger Incorporated | High temperature guar-based fracturing fluid |
| US5082579A (en) | 1990-01-16 | 1992-01-21 | Bj Services Company | Method and composition for delaying the gellation of borated galactomannans |
| US5160643A (en) | 1990-01-16 | 1992-11-03 | Bj Services Company | Method for delaying the gellation of borated galactomannans with a delay additive such as glyoxal |
| US5145590A (en) | 1990-01-16 | 1992-09-08 | Bj Services Company | Method for improving the high temperature gel stability of borated galactomannans |
| US5067566A (en) | 1991-01-14 | 1991-11-26 | Bj Services Company | Low temperature degradation of galactomannans |
| US5114327A (en) | 1991-01-25 | 1992-05-19 | Williamson James T | Rapid cooling apparatus for an injection molding machine |
| US5252235A (en) | 1991-05-24 | 1993-10-12 | Zirconium Technology Corporation | Borate cross-linking solutions |
| US5226479A (en) | 1992-01-09 | 1993-07-13 | The Western Company Of North America | Fracturing fluid having a delayed enzyme breaker |
| US5247995A (en) | 1992-02-26 | 1993-09-28 | Bj Services Company | Method of dissolving organic filter cake obtained from polysaccharide based fluids used in production operations and completions of oil and gas wells |
| US5201370A (en) | 1992-02-26 | 1993-04-13 | Bj Services Company | Enzyme breaker for galactomannan based fracturing fluid |
| US5224544A (en) | 1992-02-26 | 1993-07-06 | Bj Services Company | Enzyme complex used for breaking crosslinked cellulose based blocking gels at low to moderate temperatures |
| US5253711A (en) | 1992-03-02 | 1993-10-19 | Texas United Chemical Corp. | Process for decomposing polysaccharides in alkaline aqueous systems |
| US5226481A (en) | 1992-03-04 | 1993-07-13 | Bj Services Company | Method for increasing the stability of water-based fracturing fluids |
| US5310002A (en) * | 1992-04-17 | 1994-05-10 | Halliburton Company | Gas well treatment compositions and methods |
| US5259455A (en) | 1992-05-18 | 1993-11-09 | Nimerick Kenneth H | Method of using borate crosslinked fracturing fluid having increased temperature range |
| US5624886A (en) | 1992-07-29 | 1997-04-29 | Bj Services Company | Controlled degradation of polysaccharides |
| US5447199A (en) | 1993-07-02 | 1995-09-05 | Bj Services Company | Controlled degradation of polymer based aqueous gels |
| US5445223A (en) | 1994-03-15 | 1995-08-29 | Dowell, A Division Of Schlumberger Technology Corporation | Delayed borate crosslinked fracturing fluid having increased temperature range |
| GB9411269D0 (en) | 1994-06-06 | 1994-07-27 | Archaeus Tech Group | Delayed acid for gel breaking |
| US5681796A (en) | 1994-07-29 | 1997-10-28 | Schlumberger Technology Corporation | Borate crosslinked fracturing fluid and method |
| US5562160A (en) | 1994-08-08 | 1996-10-08 | B. J. Services Company | Fracturing fluid treatment design to optimize fluid rheology and proppant pack conductivity |
| US5566759A (en) | 1995-01-09 | 1996-10-22 | Bj Services Co. | Method of degrading cellulose-containing fluids during completions, workover and fracturing operations of oil and gas wells |
| US5806597A (en) | 1996-05-01 | 1998-09-15 | Bj Services Company | Stable breaker-crosslinker-polymer complex and method of use in completion and stimulation |
| DE19654251A1 (en) | 1996-12-23 | 1998-06-25 | Rhodia Ag Rhone Poulenc | Process for the isolation of guaran from guar endosperm |
| US6110875A (en) | 1997-03-07 | 2000-08-29 | Bj Services Company | Methods and materials for degrading xanthan |
| US6649572B2 (en) | 1997-05-27 | 2003-11-18 | B J Services Company | Polymer expansion for oil and gas recovery |
| AU751713B2 (en) | 1997-05-27 | 2002-08-22 | Bj Services Company | Improved polymer expansion for oil and gas recovery |
| US5981446A (en) | 1997-07-09 | 1999-11-09 | Schlumberger Technology Corporation | Apparatus, compositions, and methods of employing particulates as fracturing fluid compositions in subterranean formations |
| US6035936A (en) | 1997-11-06 | 2000-03-14 | Whalen; Robert T. | Viscoelastic surfactant fracturing fluids and a method for fracturing subterranean formations |
| US6387853B1 (en) | 1998-03-27 | 2002-05-14 | Bj Services Company | Derivatization of polymers and well treatments using the same |
| AU3482499A (en) | 1998-04-14 | 1999-11-01 | Halliburton Energy Services, Inc. | Methods and compositions for delaying the crosslinking of crosslinkable polysaccharide-based lost circulation materials |
| US6024170A (en) | 1998-06-03 | 2000-02-15 | Halliburton Energy Services, Inc. | Methods of treating subterranean formation using borate cross-linking compositions |
| US6251838B1 (en) | 1998-10-02 | 2001-06-26 | Benchmark Research & Technologies, Inc. | Suspended delayed borate cross-linker |
| US6138760A (en) | 1998-12-07 | 2000-10-31 | Bj Services Company | Pre-treatment methods for polymer-containing fluids |
| AU782936B2 (en) | 2000-10-16 | 2005-09-08 | Baker Hughes Incorporated | Borate crosslinked fracturing fluid viscosity reduction breaker mechanism and products |
| US6620769B1 (en) | 2000-11-21 | 2003-09-16 | Hercules Incorporated | Environmentally acceptable fluid polymer suspension for oil field services |
| WO2002055843A1 (en) | 2001-01-09 | 2002-07-18 | Bj Services Company | Well treatment fluid compositions and methods for their use |
| US6767868B2 (en) | 2001-02-22 | 2004-07-27 | Bj Services Company | Breaker system for fracturing fluids used in fracturing oil bearing formations |
| US6844296B2 (en) | 2001-06-22 | 2005-01-18 | Bj Services Company | Fracturing fluids and methods of making and using same |
| GB2383355A (en) | 2001-12-22 | 2003-06-25 | Schlumberger Holdings | An aqueous viscoelastic fluid containing hydrophobically modified polymer and viscoelastic surfactant |
| US6810959B1 (en) * | 2002-03-22 | 2004-11-02 | Bj Services Company, U.S.A. | Low residue well treatment fluids and methods of use |
| AU2003263753A1 (en) | 2002-06-25 | 2004-01-06 | Rhodia, Inc. | Molecular weight reduction of polysaccharides by electron beams |
| US7007757B2 (en) | 2002-06-25 | 2006-03-07 | Bj Services Company Canada | Fracturing fluids containing borate esters as crosslinking agents and method of using same |
| WO2004083600A1 (en) | 2003-03-18 | 2004-09-30 | Bj Services Company | Method of treating subterranean formations using mixed density proppants or sequential proppant stages |
| US7207386B2 (en) | 2003-06-20 | 2007-04-24 | Bj Services Company | Method of hydraulic fracturing to reduce unwanted water production |
| US7303018B2 (en) | 2003-07-22 | 2007-12-04 | Bj Services Company | Method of acidizing a subterranean formation with diverting foam or fluid |
| NO20045474L (en) | 2003-12-18 | 2005-06-20 | Bj Services Co | Procedure for acid treatment stimulation using viscoelastic gelatin agent |
| US8895480B2 (en) | 2004-06-04 | 2014-11-25 | Baker Hughes Incorporated | Method of fracturing using guar-based well treating fluid |
| US7726399B2 (en) | 2004-09-30 | 2010-06-01 | Bj Services Company | Method of enhancing hydraulic fracturing using ultra lightweight proppants |
| US7278486B2 (en) * | 2005-03-04 | 2007-10-09 | Halliburton Energy Services, Inc. | Fracturing method providing simultaneous flow back |
| US7603896B2 (en) | 2005-09-16 | 2009-10-20 | Bj Services Company | Fluid flow model and method of using the same |
| US7481276B2 (en) | 2006-05-12 | 2009-01-27 | Bj Services Company | Method of inhibiting and/or preventing corrosion in oilfield treatment applications |
| US20090120647A1 (en) | 2006-12-06 | 2009-05-14 | Bj Services Company | Flow restriction apparatus and methods |
| US7669655B2 (en) | 2007-02-13 | 2010-03-02 | Bj Services Company | Method of fracturing a subterranean formation at optimized and pre-determined conditions |
| US7699106B2 (en) * | 2007-02-13 | 2010-04-20 | Bj Services Company | Method for reducing fluid loss during hydraulic fracturing or sand control treatment |
| AR068867A1 (en) | 2007-10-15 | 2009-12-09 | Kemira Chemicals Inc | FLUID COMPOSITIONS FOR WELL TREATMENT INCLUDING A FORMATION OF DELAYED PERCARBONATE DELAYED AND METHODS TO USE THEM |
| US7913762B2 (en) | 2008-07-25 | 2011-03-29 | Baker Hughes Incorporated | Method of fracturing using ultra lightweight proppant suspensions and gaseous streams |
| US8205675B2 (en) | 2008-10-09 | 2012-06-26 | Baker Hughes Incorporated | Method of enhancing fracture conductivity |
| US20100204069A1 (en) | 2009-02-10 | 2010-08-12 | Hoang Van Le | METHOD OF STIMULATING SUBTERRANEAN FORMATION USING LOW pH FLUID |
| US8030250B2 (en) * | 2009-07-17 | 2011-10-04 | Baker Hughes Incorporated | Method of treating subterranean formations with carboxylated guar derivatives |
| US20110092696A1 (en) * | 2009-10-21 | 2011-04-21 | PfP Technology, LLC. | High performance low residue guar for hydraulic fracturing and other applications |
-
2009
- 2009-12-18 US US12/642,662 patent/US8371383B2/en active Active
-
2010
- 2010-12-17 BR BR112012014932A patent/BR112012014932A2/en not_active Application Discontinuation
- 2010-12-17 WO PCT/US2010/060979 patent/WO2011075629A1/en active Application Filing
- 2010-12-17 CN CN201080057950.8A patent/CN102782081B/en not_active Expired - Fee Related
- 2010-12-17 MX MX2012007068A patent/MX351767B/en active IP Right Grant
- 2010-12-17 AU AU2010330876A patent/AU2010330876B2/en not_active Ceased
- 2010-12-17 CA CA2783471A patent/CA2783471C/en not_active Expired - Fee Related
- 2010-12-17 EP EP10801503A patent/EP2513245A1/en not_active Withdrawn
-
2012
- 2012-06-12 CO CO12098444A patent/CO6541632A2/en unknown
Also Published As
| Publication number | Publication date |
|---|---|
| AU2010330876A1 (en) | 2012-06-21 |
| CA2783471A1 (en) | 2011-06-23 |
| CO6541632A2 (en) | 2012-10-16 |
| US20110146996A1 (en) | 2011-06-23 |
| EP2513245A1 (en) | 2012-10-24 |
| BR112012014932A2 (en) | 2016-03-08 |
| MX351767B (en) | 2017-10-27 |
| CN102782081A (en) | 2012-11-14 |
| MX2012007068A (en) | 2012-07-30 |
| US8371383B2 (en) | 2013-02-12 |
| WO2011075629A1 (en) | 2011-06-23 |
| AU2010330876B2 (en) | 2015-01-29 |
| CN102782081B (en) | 2015-11-25 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| CA2783471C (en) | Method of fracturing subterranean formations with crosslinked fluid | |
| US9410415B2 (en) | Method of fracturing subterranean formations with crosslinked fluid | |
| US9175208B2 (en) | Compositions and methods for breaking hydraulic fracturing fluids | |
| Barati et al. | A review of fracturing fluid systems used for hydraulic fracturing of oil and gas wells | |
| US9771783B2 (en) | Method of fracturing with non-derivatized guar containing fluid | |
| US7195065B2 (en) | Stabilizing crosslinked polymer guars and modified guar derivatives | |
| CN105358651B (en) | Iron-containing breaker compounds and methods of their use | |
| CA2861119C (en) | Method of delaying crosslinking in well treatment operation | |
| US8307901B2 (en) | Methods of fracturing subterranean formations using sulfonated synthetic gelling agent polymers | |
| US20120252707A1 (en) | Methods and compositions to delay viscosification of treatment fluids | |
| CA2899331A1 (en) | Method of fracturing subterranean formations with crosslinked fluid | |
| Zhao | Investigation of the Applications of Nanofibrillated Cellulose in the Oil Industry | |
| WO2018128537A1 (en) | Crosslinker slurry compositions and applications |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request | ||
| MKLA | Lapsed |
Effective date: 20211217 |