CN108315005B - Sand-free fracturing fluid with high flow conductivity, preparation method thereof, fracturing process and application - Google Patents
Sand-free fracturing fluid with high flow conductivity, preparation method thereof, fracturing process and application Download PDFInfo
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- 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
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- 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
- C09K8/84—Compositions based on water or polar solvents
- C09K8/86—Compositions based on water or polar solvents containing organic compounds
- C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
- C09K8/885—Compositions based on water or polar solvents containing organic compounds macromolecular compounds obtained otherwise than by reactions only involving carbon-to-carbon unsaturated bonds
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- C—CHEMISTRY; METALLURGY
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- 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
- C09K8/84—Compositions based on water or polar solvents
- C09K8/86—Compositions based on water or polar solvents containing organic compounds
- C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
- C09K8/887—Compositions based on water or polar solvents containing organic compounds macromolecular compounds containing cross-linking agents
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- 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
- C09K8/84—Compositions based on water or polar solvents
- C09K8/86—Compositions based on water or polar solvents containing organic compounds
- C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
- C09K8/90—Compositions based on water or polar solvents containing organic compounds macromolecular compounds of natural origin, e.g. polysaccharides, cellulose
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- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
- C09K2208/08—Fiber-containing well treatment fluids
Abstract
The invention relates to a sand-free fracturing fluid with high flow conductivity, a preparation method, a fracturing process and application thereof. The sand-free fracturing fluid comprises a group A fracturing fluid containing curable resin prepolymer and a group B fracturing fluid containing curing agent and fiber, wherein the group A fracturing fluid and the group B fracturing fluid are matched for use. The fracturing fluid prepared by the method can enter all levels of cracks to form fiber reinforced porous resin, so that a pressed complex fracture network system can have high flow conductivity and support the cracks, and the oil and gas recovery rate is improved. The fracturing process is simple, and the fracturing risk is low.
Description
Technical Field
The invention relates to a sand-free fracturing fluid with high flow conductivity, a preparation method, a fracturing process and application thereof, and belongs to the technical field of hydraulic fracturing in the process of oil and natural gas exploitation.
Background
The hydraulic fracturing is an important technical means for increasing the yield of oil and gas wells, plays a key role in increasing the yield of conventional low-permeability and ultra-low-permeability oil and gas reservoirs and shale and compact sandstone reservoirs of unconventional oil and gas reservoirs, and is particularly an unconventional reservoir which is not subjected to a fracturing technology and underground oil and gas are difficult to extract. Hydraulic fracturing is to pump fracturing fluid into a stratum by using a high-pressure pump set to form one or more fractures with certain geometric dimensions, wherein the length of the fracture is generally dozens of meters to hundreds of meters, the height of the fracture is dozens of meters to dozens of meters, and the width of the fracture is several millimeters wide, and then sand-carrying fluid (mixture of the fracturing fluid and the proppant) with proppant is injected into the fracture. After fracturing, fracturing fluid is broken and is discharged to the ground, and the propping agent is left in the fracture to play a role in propping the fracture and keep the fracture in an open state. The pores among the proppant particles provide a flow passage for oil, gas and water in the stratum, thereby achieving the effect of fracturing stimulation. Proppant is the most critical factor in the effectiveness of stimulation, and proppant performance determines the conductivity of the fracture (the width of the fracture times the permeability of the fracture).
Chinese patent document CN103821491A provides a sand fracturing process, which is to pump a fiber-containing sand-carrying fluid and a pure jelly spacer fluid into a fracture of an oil and gas well in an alternate circulation manner, the fiber-containing sand-carrying fluid entering the fracture of the oil and gas well is dispersed by perforation blastholes on a pipe column to form different shapes of lumps, and is stacked from inside to outside in the fracture to form a sand column, gaps between adjacent lumps of the fiber-containing sand-carrying fluid in the sand column are filled with the pure jelly spacer fluid, and the cross section of the whole sand column is in a stacked stone wall shape; the sand column supports the cracks in the closing process and the cracks after closing, and pure jelly spacer fluid parts in the sand column form low-resistance and high-flow-rate seepage channels of oil gas after gel breaking, so that the single-well yield of the oil gas well is increased. Chinese patent document CN104727799A discloses a pulse sand fracturing method for realizing high flow conductivity of a fracture, which comprises the following steps: 1. aiming at the staged multi-cluster fracturing of the horizontal well of the ultra-low permeability reservoir, judging whether a higher fracture conductivity can be formed through pulse type sand fracturing by researching the characteristics of the ultra-low permeability reservoir, and if so, executing the step 2; 2. in the fracturing process, through a pulse type sand adding process, fiber fracturing liquid is used for solidifying sand, and a column support is formed in the artificial fracture, so that a channel network with high-speed flow conductivity is formed in the artificial fracture, the artificial fracture has high flow conductivity, and the single-well yield is improved.
All need add sand among the above-mentioned prior art, require high to fracturing fluid viscosity etc. and fracturing fluid viscosity is low then can carry the proppant difficulty, can not make the proppant fully suspend in fracturing fluid, and the fracturing cost is higher to be difficult to go deep into the depths of crack hole. In the traditional fracturing technology, a large amount of propping agents are needed, so that the difficulty of fracturing construction is increased; the high-concentration proppant is easy to sand block, and is easy to cause fracture failure; the use of the propping agent and the high-performance fracturing fluid greatly increases the fracturing cost; after the fracturing construction is completed, the fracturing fluid needs to be broken and returned to the ground, and if the return is not thorough, the fracturing fluid can cause damage to a reservoir, the stratum permeability is reduced, and the fracturing effect is not ideal. The invention is therefore proposed.
Disclosure of Invention
Aiming at the defects of the prior art, the invention provides a sand-free fracturing fluid with high flow conductivity. The sand-free fracturing fluid can go deep into the deep of the crack pores, improves the oil and gas recovery ratio, is simple and feasible, and can greatly reduce the fracturing cost and the construction risk.
The invention also provides a preparation method of the sand-free fracturing fluid with high flow conductivity, a fracturing process and application.
The technical scheme of the invention is as follows:
a sand-free fracturing fluid comprises a group A fracturing fluid containing curable resin prepolymer and a group B fracturing fluid containing curing agent and fiber, wherein the group A fracturing fluid and the group B fracturing fluid are matched for use.
The group A fracturing fluid is prepared by adding a curable resin prepolymer into the existing fracturing fluid 1; the group B fracturing fluid is prepared by adding a curing agent and fibers into the existing fracturing fluid 2.
The existing fracturing fluid 1 or the existing fracturing fluid 2 is a commercially available product or a fracturing fluid product prepared according to the prior art; the existing fracturing fluid 1 or fracturing fluid 2 may be the same or different.
Preferably, according to the invention, the existing fracturing fluid 1 or fracturing fluid 2 is a guanidine gum fracturing fluid. The guanidine gum fracturing fluid can be purchased in the market and also can be prepared according to the prior art; the preparation method of the guanidine gum fracturing fluid is preferably as follows:
guar gum powder is dissolved in water to prepare a gum solution with the mass concentration of 0.2-0.6%, then a cross-linking agent sodium tetraborate solution with the mass concentration of 50% is added according to the mass ratio of 1: 4-6 of the guar gum, and the mixture is stirred at room temperature to obtain the guanidine gum fracturing fluid.
According to the invention, the curable resin prepolymer in the group A fracturing fluid is preferably melamine resin prepolymer, phenolic resin prepolymer or epoxy resin prepolymer; most preferably, the curable resin prepolymer is an epoxy resin prepolymer. Commercially available or prepared according to the prior art.
The invention preferably adopts the following preparation method of the epoxy resin prepolymer: mixing acrylic rosin and triethylamine in an inert gas atmosphere, heating to melt the acrylic rosin, adding butanediol diglycidyl ether, reacting at 130 ℃, stopping the reaction when the acid value (KOH) of the reaction liquid is lower than 1mg/g, filtering and washing to obtain an epoxy resin prepolymer; the mass ratio of the butanediol diglycidyl ether to the acrylic rosin is 1-3: 1; the mass of the triethylamine is 0.01-0.04% of that of the acrylic acid rosin.
According to the invention, the content of the curable resin prepolymer in the group A fracturing fluid is preferably 50-80 wt%.
According to the invention, the mass content of the curing agent in the B group of fracturing fluid is preferably 50-80 wt%.
According to the invention, the fibers in the B group fracturing fluid are organic fibers or inorganic fibers; preferably, the inorganic fibers are glass fibers or surface-modified glass fibers. Commercially available or prepared according to the prior art.
Preferably, the surface modified glass fiber is surface modified by mixing the glass fiber and the nano-particles at 50-150 ℃; the mass ratio of the nanoparticles to the glass fibers is 10:1-1: 1; the nano particles are nano silicon dioxide or nano titanium dioxide. The method for modifying the surface of the glass fiber by the nano particles is carried out according to the prior art.
Preferably according to the invention, the fibres have a length of 8 to 12 mm; preferably the fibre length is 10 mm.
According to the invention, the content of the fibers in the B group of fracturing fluids is preferably 0.2-0.6% by mass.
According to the invention, the mass ratio of the fiber to the curing agent in the group B fracturing fluid is (0.2-0.5) to (2-60); preferably (0.2-0.5) to (30-40); further preferably 0.4: 30.
According to the invention, preferably, the matching use of the group A fracturing fluid and the group B fracturing fluid is as follows: the mass ratio of the curing agent is 100 (2-60); further preferably, the curable resin prepolymer: the mass ratio of the curing agent is 100 (30-40); most preferably, the curable resin prepolymer: the curing agent is used in a mass ratio of 100: 30.
According to the invention, the curing agent in the B group of fracturing fluid is a waterborne polyurethane curing agent. The waterborne polyurethane curing agent can be obtained commercially or prepared according to patent document CN 105968304A.
A preparation method of sand-free fracturing fluid with high flow conductivity comprises the following steps:
(1) preparation of group A fracturing fluid
Dispersing curable resin prepolymer in the existing fracturing fluid 1 to obtain A group of fracturing fluid;
(2) preparation of group B fracturing fluid
Dispersing a curing agent and fibers in the existing fracturing fluid 2 to obtain a group B fracturing fluid;
the existing fracturing fluid 1 or fracturing fluid 2 may be the same or different.
A sand-free fracturing process with high flow conductivity comprises the following steps of:
and (2) injecting the group A of fracturing fluid of the sand-free fracturing fluid into a stratum pump, pumping the group B of fracturing fluid of the sand-free fracturing fluid into the stratum pump after a crack is formed, and carrying out resin synthesis and/or coating reaction under the action of stratum temperature and hydraulic fracturing to form the fiber reinforced porous resin with a porous spongy structure.
A sand-free fracturing fluid with high flow conductivity is applied to oil and gas exploitation hydraulic fracturing.
The sand-free fracturing process includes pumping the fracturing fluid A into stratum to form high pressure in the well bottom, so as to open artificial crack in stratum, pumping the fracturing fluid B into stratum, mixing the fracturing fluid B with fiber reinforcing ribs, and under the action of stratum temperature and fracturing, making A, B fracturing fluid produce resin synthesis and/or coating chemical reaction underground. The fiber reinforced porous resin can provide a flow guide channel for oil, gas and water on one hand, and on the other hand, the high-strength integral resin can play a role in supporting cracks.
The invention has the following beneficial effects:
1. the fracturing fluid and the fracturing process do not need to use a propping agent, so that the sand blocking situation is avoided in the fracturing process, and the problem of frequent sand blocking in the traditional fracturing method is solved;
2. the fracturing fluid and the fracturing process do not need to carry sand, so that the requirement on viscosity is avoided, the requirement on a chemical agent is low, the pumping pressure is greatly reduced, and the construction risk is reduced;
3. the fracturing fluid does not need to be drained back, the problem of damage to a reservoir is solved, the fracturing construction period is shortened, and the fracturing cost is greatly reduced.
4. The fracturing fluid and the fracturing process have larger fracturing effect on unconventional reservoirs such as shale and tight sandstone, and the unconventional reservoirs are often fractured to form complex fracture networks, the fractures are narrow, and a propping agent is difficult to fill into secondary fractures, so that the fracturing effect is influenced.
5. The fracturing fluid and the fracturing process can be used in slickwater fracturing, carbon dioxide/nitrogen/liquefied natural gas and other anhydrous fracturing technologies, and can also be used for pre-fracturing or used in combination with the traditional fracturing technology.
6. The fracturing fluid and the fracturing process provided by the invention have the advantages that the fracturing is changed into a simple and feasible process technology, the construction equipment is simplified, the design scheme is effectively simplified, and the fracturing risk is greatly reduced.
Drawings
Fig. 1 is a schematic diagram of a single resin-coated fiber, wherein 1 is resin and 2 is fiber.
Fig. 2 is a diagram showing the effect of laying the resin-coated fibers in the cracks, wherein 3 is the cured resin, 4 is the holes in the resin with the foam structure, and 5 is the fibers.
Detailed Description
The present invention will be further described with reference to the following examples, but is not limited thereto.
Meanwhile, the experimental methods described in the following examples are all conventional methods unless otherwise specified; the reagents and materials are commercially available, unless otherwise specified.
In the examples, the existing fracturing fluid used was a guanidine gum fracturing fluid, which was prepared according to the following method: 10g of guar gum powder (produced by billion chemical Co., Ltd., Yue Cuo, Ltd.) purchased from market is dissolved in 2500g of water to prepare raw gum liquid with the mass concentration of 0.4%; then 2g of a sodium tetraborate solution as a crosslinking agent with the mass concentration of 50% is added, and the mixture is stirred for 2min at room temperature to obtain the guanidine gum fracturing fluid.
The epoxy resin prepolymer is prepared by the following method: adding 100g of acrylic rosin and 0.03g of triethylamine into a four-mouth bottle with a stirrer, a condenser tube, a dropping funnel and a nitrogen conduit, introducing nitrogen, heating at 130 ℃ to melt the acrylic rosin, adding 100g of butanediol diglycidyl ether, reacting at 130 ℃ for 5 hours, filtering and washing to obtain the epoxy resin prepolymer.
The aqueous polyurethane curing agent used was prepared according to example 1 in patent document CN 105968304 a.
Example 1
A sand-free fracturing fluid comprises a group A fracturing fluid and a group B fracturing fluid, wherein the group A fracturing fluid is prepared by adding an epoxy resin prepolymer into a guanidine gum fracturing fluid, and the group B fracturing fluid is prepared by adding a water polyurethane curing agent and modified glass fibers into the guanidine gum fracturing fluid.
The preparation method of the sand-free fracturing fluid with high flow conductivity comprises the following steps:
(1) preparation of group A fracturing fluid
Dispersing 80g of epoxy resin prepolymer into 100g of guanidine gum fracturing fluid to obtain A group of fracturing fluid;
(2) preparation of group B fracturing fluid
And dispersing 24g of waterborne polyurethane curing agent, 0.32g of glass fiber with the length of 10mm and 3g of nano titanium dioxide in 100g of guanidine gum fracturing fluid to obtain the group B fracturing fluid.
The mass ratio of the aqueous polyurethane curing agent in the group B of fracturing fluid to the epoxy resin prepolymer in the group A of fracturing fluid is 30: 100.
The mass ratio of the glass fiber in the group B fracturing fluid to the epoxy resin prepolymer in the group A fracturing fluid is 0.4: 100.
The group A fracturing fluid and the group B fracturing fluid are used in a matching mode according to the mass ratio of 1: 1.
The sand-free fracturing process by using the fracturing fluid comprises the following steps:
and (2) injecting the group A of fracturing fluid of the sand-free fracturing fluid into a stratum pump, pumping the group B of fracturing fluid of the sand-free fracturing fluid into the stratum pump after a crack is formed, and carrying out resin synthesis and/or coating reaction under the action of stratum temperature and hydraulic fracturing to form the fiber reinforced porous resin with a porous spongy structure.
Examples 2 to 6
As described in example 1, the difference from example 1 is:
the mass ratio of the aqueous polyurethane curing agent in the group B of fracturing fluid to the epoxy resin prepolymer in the group A of fracturing fluid is 20:100, 35:100, 40:100, 50:100 and 60:100 respectively.
Examples 7 to 10
As described in example 1, the difference from example 1 is:
nano titanium dioxide is not added into the group B fracturing fluid, namely, the glass fiber is unmodified glass fiber, and the length of the glass fiber is 8 mm;
the mass ratio of the unmodified glass fiber to the epoxy resin prepolymer in the group A fracturing fluid is 0.2:100, 0.3:100,0.4:100 and 0.5:100 respectively.
Examples 11 to 14
As described in example 1, the difference from example 1 is:
nano titanium dioxide is not added into the group B fracturing fluid, namely, the glass fiber is unmodified glass fiber, and the length of the glass fiber is 10 mm;
the mass ratio of the unmodified glass fiber to the epoxy resin prepolymer in the group A fracturing fluid is 0.2:100, 0.3:100,0.4:100 and 0.5:100 respectively.
Examples 15 to 18
As described in example 1, the difference from example 1 is:
nano titanium dioxide is not added into the group B fracturing fluid, namely, the glass fiber is unmodified glass fiber, and the length of the glass fiber is 12 mm;
the mass ratio of the unmodified glass fiber to the epoxy resin prepolymer in the group A fracturing fluid is 0.2:100, 0.3:100,0.4:100 and 0.5:100 respectively.
Test example 1
And (3) curing the waterborne polyurethane curing agent in the fracturing fluid of the group 1-6B and the epoxy resin prepolymer in the fracturing fluid of the group 1-6A at room temperature for 24h, curing at 70 ℃ for 24h, naturally cooling to room temperature, and standing for 24h to obtain the epoxy resin to be tested.
The tensile shear strength of the epoxy resin is determined according to GB7124-1986 and the positive tensile adhesive strength of the epoxy resin is determined according to GB 6329-; determining the hardness of the epoxy resin according to GB 2411-; thermal analysis, namely placing 2-4 mg of an epoxy resin sample in a sealed pool, and measuring the thermal weight loss (TG) on a PerkinElmer DSC-2C differential scanning calorimeter in the United states, wherein the heating rate is 20 ℃/min.
The results are shown in tables 1 and 2.
TABLE 1 influence of mass ratio of aqueous epoxy hardener to epoxy resin prepolymer on mechanical properties of epoxy resins
As can be seen from Table 1, the mass ratio of the aqueous polyurethane curing agent in the fracturing fluid B of example 1, example 3 and example 4 to the epoxy resin prepolymer in the fracturing fluid A of example 4 is 30: 100-40: 100, the shear resistance of the epoxy resin is better and the positive tensile adhesive strength is better, wherein the mass ratio of the aqueous polyurethane curing agent in the fracturing fluid B of example 1 to the epoxy resin prepolymer in the fracturing fluid A of example 1 is preferably 30: 100. According to the Shore hardness value, the epoxy resin has the strongest mechanical pressure resistance when the mass ratio of the waterborne curing agent to the epoxy resin prepolymer is 30: 100.
TABLE 2 Mass ratio of aqueous curing agent to epoxy resin prepolymer influence on epoxy resin Heat resistance
The results of thermal analysis on the epoxy resins prepared by curing the aqueous polyurethane curing agents in the fracturing fluids of examples 1-6B and the epoxy resin prepolymers in the fracturing fluids of examples 1-6A on a differential scanning calorimeter are shown in Table 2. As can be seen from Table 2, the mass ratio of the waterborne polyurethane curing agent in the group B fracturing fluid to the epoxy resin prepolymer in the group A fracturing fluid is within the range of 30: 100-40: 100, the decomposition percentages below 400 ℃ are not greatly different, about 55%, and the extreme thermal decomposition temperature is high, but when the mass ratio is increased to 50:100, the decomposition percentage is obviously improved and reaches more than 65%.
In summary, as can be seen from the influence of the mass ratio of the aqueous polyurethane curing agent in the group B fracturing fluid to the epoxy resin prepolymer in the group a fracturing fluid on the mechanical properties and heat resistance of the epoxy resin, the mass ratio of the aqueous polyurethane curing agent to the epoxy resin prepolymer is in the range of 30:100 to 35:100, and particularly when the mass ratio is 30:100, the epoxy resin is completely cured, the extreme thermal decomposition temperature is highest, which is 387.9 ℃, and the structure is stable. This is because an excessive amount of the curing agent does not participate in the formation of a cured structure in the curing system, and when the curing system is exposed to a relatively high temperature environment, the heat resistance of the cured product is adversely affected due to its unstable chemical structure. Therefore, an excess of curing agent cannot be used to participate in the curing reaction.
Test example 2
Cylindrical resin test pieces 8.0mm high and 4.0mm inner diameter were prepared according to ISO9917 standard from the group A fracturing fluid and the group B fracturing fluid in examples 7 to 18. Preparing two semi-cylindrical polytetrafluoroethylene molds, filling fiber-reinforced porous epoxy resin into the two molds respectively in layers, then closing the molds, and adding glass plates at two ends for flattening. And (3) respectively illuminating for 40s along each direction by using a light curing lamp, separating the mold after the resin is completely cured, and taking out the resin test piece. After the test piece was completely cured, a compression test was performed.
According to the standard of compressive strength specified by the national standard of America, a universal tester is usedThe compression strength of the test sample is tested, the loading speed is 1.0mm/min, the failure value F (N) of the test sample during fracture is recorded, and the formula CS is 4F/pi d2(CS is the compressive strength and d is the diameter of the cylindrical sample).
The fracture conductivity evaluation instrument is used in the test, the instrument can simulate the stratum condition and can evaluate the long-term conductivity of the formed fiber reinforced porous epoxy resin foam structure. The maximum experiment temperature of the instrument is 150 ℃, and the maximum closing pressure is 200MPa, so that the practical requirements of oil fields in China can be completely met. The instrument was designed according to the API standard and the test results are shown in table 3.
TABLE 3 Performance testing of fiber-reinforced cellular epoxy resins under different fiber parameters
It can be seen from table 3 that when the length of the glass fiber is 10mm, the glass fiber can achieve higher compressive strength and flow conductivity, and the overlong fiber can affect the coating of the epoxy resin on the fiber, so that the holes of the whole fiber-reinforced porous epoxy resin foam structure are reduced, and the passing capacity of oil, gas and water is reduced. When the mass ratio of the glass fiber to the epoxy resin prepolymer is 0.4%, the compression strength and the flow conductivity can reach a larger peak value, and more holes are formed. When the mass ratio of the glass fiber to the epoxy resin prepolymer is higher than 0.4%, the fibers are too much intertwined with each other, so that the fibers are coated too much by the resin, and pores are formed little, thereby reducing the flow conductivity. Therefore, the optimum fiber parameter is preferably 10mm in length and 0.4% in mass ratio of the glass fiber to the epoxy resin prepolymer.
Test example 3
After the fracturing fluid A and the fracturing fluid B in the example 1 are used in a matching manner, the materials are cured at room temperature for 24 hours, then cured at 70 ℃ for 24 hours, naturally cooled to room temperature and placed for 24 hours, a conductivity test experiment is carried out on the formed porous epoxy resin sponge structure reinforced by the modified glass fibers, the test equipment is the same as that in the test example 2, is compared with quartz sand, resin sand and walnut shells, and whether the conductivity of the porous epoxy resin sponge structure reaches the conductivity of a normal proppant is tested, as shown in Table 4.
TABLE 4 Long-term conductivity test results
As can be seen from the test data in table 4, when the closing pressure is low, the flow conductivity of the fiber-reinforced porous epoxy resin obtained in example 1 is not as good as that of natural proppants such as quartz sand and walnut shells. However, when the closing pressure is higher, the flow conductivity exceeds that of other natural proppants, which shows that the natural proppants are easy to break under high pressure, so that the flow conductivity among the proppants is reduced, and the fracture is not favorable. The fiber reinforced porous epoxy resin obtained by the invention has low breakage rate and good foam structure integrity under high pressure due to the special pressure resistance, still has good flow conductivity, and is suitable for high-pressure strata.
In example 1, the glass fiber is modified by the nano titanium dioxide particles, and is tightly bonded with the resin, and the nano titanium dioxide particles have higher reactivity and can participate in the curing process of the epoxy resin, so that the interface effect between two phases is remarkably improved. Therefore, the modified glass fiber reinforced porous epoxy resin prepared in example 1 enables the bonding strength between the fiber and the resin to achieve more ideal use conditions.
Claims (6)
1. A sand-free fracturing process with high flow conductivity comprises the steps of using a sand-free fracturing fluid, wherein the sand-free fracturing fluid comprises a group A fracturing fluid containing curable resin prepolymer and a group B fracturing fluid containing curing agent and fiber, and the group A fracturing fluid and the group B fracturing fluid are matched for use;
the sand-free fracturing process comprises the following steps:
injecting the group A of fracturing fluid of the sand-free fracturing fluid into a stratum pump to form a crack, pumping the group B of fracturing fluid of the sand-free fracturing fluid into the stratum pump, and carrying out resin synthesis and/or coating reaction under the action of stratum temperature and hydraulic fracturing to form fiber reinforced porous resin with a porous spongy structure;
the curable resin prepolymer is melamine resin prepolymer, phenolic resin prepolymer or epoxy resin prepolymer; the mass content of curable resin prepolymers in the group A fracturing fluid is 50-80 wt%;
the mass content of the curing agent is 50-80wt%, and the mass content of the fiber is 0.2-0.6 wt%; the fiber is glass fiber or surface modified glass fiber, and the curing agent is a waterborne polyurethane curing agent; the mass ratio of the fiber to the curing agent is (0.2-0.5) to (2-60); the surface modified glass fiber is prepared by mixing glass fiber and nanoparticles at 50-150 ℃ for surface modification, wherein the mass ratio of the nanoparticles to the glass fiber is 10:1-1:1, and the nanoparticles are nano silicon dioxide or nano titanium dioxide;
the group A fracturing fluid and the group B fracturing fluid are prepared from curable resin prepolymers: the curing agent =100 (2-60) is used in combination in a mass ratio.
2. The sand-free fracturing process with high conductivity according to claim 1, wherein the curable resin prepolymer is an epoxy resin prepolymer.
3. The sand-free fracturing process with high conductivity of claim 1, wherein the fiber length is 8-12 mm.
4. The sand-free fracturing process with high conductivity of claim 1, wherein the mass ratio of the fiber to the curing agent in the fracturing fluid of group B is (0.2-0.5) to (30-40).
5. The sand-free fracturing process with high conductivity according to claim 1, wherein the group A fracturing fluid and the group B fracturing fluid are prepared from curable resin prepolymers: the curing agent =100 (30-40) is used in combination according to the mass ratio.
6. The sand-free fracturing process with high flow conductivity of claim 1, wherein the preparation method of the sand-free fracturing fluid comprises the following steps:
(1) preparation of group A fracturing fluid
Dispersing curable resin prepolymer in the existing fracturing fluid 1 to obtain A group of fracturing fluid;
(2) preparation of group B fracturing fluid
Dispersing a curing agent and fibers in the existing fracturing fluid 2 to obtain a group B fracturing fluid;
the existing fracturing fluid 1 or fracturing fluid 2 may be the same or different.
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| CN113337266B (en) * | 2021-04-21 | 2023-03-28 | 西南石油大学 | Fracturing fluid system for enhancing pressure bearing capacity of proppant and application method thereof |
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