CN117821050B - Compact gas reservoir fracturing fluid system and fracturing method - Google Patents
Compact gas reservoir fracturing fluid system and fracturing method Download PDFInfo
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- 239000012530 fluid Substances 0.000 title claims abstract description 75
- 238000000034 method Methods 0.000 title claims abstract description 32
- 239000007788 liquid Substances 0.000 claims abstract description 34
- 238000002347 injection Methods 0.000 claims abstract description 27
- 239000007924 injection Substances 0.000 claims abstract description 27
- 239000004576 sand Substances 0.000 claims abstract description 18
- 239000012747 synergistic agent Substances 0.000 claims abstract description 16
- 239000000839 emulsion Substances 0.000 claims description 69
- 239000007789 gas Substances 0.000 claims description 30
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 claims description 18
- 239000003795 chemical substances by application Substances 0.000 claims description 17
- 239000002245 particle Substances 0.000 claims description 14
- 239000002131 composite material Substances 0.000 claims description 9
- 229910052757 nitrogen Inorganic materials 0.000 claims description 9
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- 238000006467 substitution reaction Methods 0.000 claims description 4
- 238000011010 flushing procedure Methods 0.000 claims description 3
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- 239000000654 additive Substances 0.000 abstract description 7
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- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 12
- ROOXNKNUYICQNP-UHFFFAOYSA-N ammonium persulfate Chemical compound [NH4+].[NH4+].[O-]S(=O)(=O)OOS([O-])(=O)=O ROOXNKNUYICQNP-UHFFFAOYSA-N 0.000 description 6
- 230000000052 comparative effect Effects 0.000 description 5
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
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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
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- C—CHEMISTRY; METALLURGY
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- 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
- C09K8/80—Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
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- C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
- C09K2208/10—Nanoparticle-containing well treatment fluids
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Abstract
The invention provides a tight gas reservoir fracturing fluid system and a fracturing method, and relates to the technical field of tight gas reservoir hydraulic fracturing. The pumping procedure of the fracturing method is divided into 5 stages, and low-viscosity liquid is adopted in the annular low-replacement stage; the pre-liquid stage adopts low mucus in the early stage and adopts high mucus in the later stage; the sand carrying fluid stage adopts high viscosity fluid; the displacement liquid stage and the squeezing stage both adopt low-viscosity liquid. The differentiation is accompanied by injection of nano synergistic agent, 0.3 to 0.5 percent of nano synergistic agent is added in the front-end liquid stage, and 0.1 to 0.3 percent of nano synergistic agent is added in the front-end stage of sand-carrying liquid. According to the invention, the nano cleanup additive is differentially added into the fracturing fluid and penetrates into the nano reservoir pore throat, so that the flowback effect of the fracturing fluid is improved, the production is quickly built, and the single well productivity is improved.
Description
Technical Field
The invention relates to the technical field of hydraulic fracturing of tight gas reservoirs, in particular to a tight gas reservoir fracturing fluid system and a fracturing method.
Background
Su Lige tight sandstone gas reservoirs are affected by low pores, low permeability and low abundance, and the reservoir has poor physical properties, low reservoir abundance, small single well control reservoir, and basically no natural productivity of gas wells, and the reservoir must be modified by adopting a fracturing technology to obtain benefit development. The selection of the fracturing fluid performance and fracturing mode has important influence on improving the single well yield of the tight gas reservoir.
For unconventional compact sandstone isohypotonic and ultralow permeability reservoirs, water-based fracturing fluid is generally adopted for fracturing operation on site. However, a large amount of fracturing fluid is easy to form a water lock in the small pore throat of the low-grade reservoir (the median pore throat radius is about 50 nm) due to capillary resistance and can not be discharged, a gas seepage channel is blocked, water seal gas is formed, and the productivity of a gas well is reduced, so that the timely and efficient backflow of water lock fluid is particularly important. In the prior art, fluorocarbon cleanup additives and alcohols are mainly used for preventing water from locking and improving the flowback rate of fracturing fluid, but common additives can be quickly adsorbed by a reservoir and propping agents and cannot effectively reach the tight rock pores in time.
In recent years, the application of nanotechnology to enhance hydraulic fracturing effects has begun to be of increasing interest. Compared with the conventional cleanup additive, the nano synergistic agent (with the median particle diameter of 1-100 nm) can transport more surfactant to the deep of pores, and the adsorbed solution has lower surface tension, higher contact angle and stronger waterproof locking capability. However, the differences of the physical and chemical properties of different nano-synergists are large, the concomitant injection proportion of the nano-synergist is very important for the performance of the nano-synergist, and in addition, the fracturing mode plays a very important role in playing the role of the nano-synergist in reducing the water lock of deep reservoirs, improving the seepage channels of low pore throat areas such as remote well microcracks and the like, but the related researches are freshly reported.
Disclosure of Invention
The invention aims at providing a compact gas reservoir fracturing fluid system.
The second purpose of the invention is to provide a fracturing method of the tight gas reservoir.
In order to achieve the above object of the present invention, the following technical solutions are specifically adopted:
In a first aspect, the invention provides a tight gas reservoir fracturing fluid system, comprising a fracturing fluid and a nano synergist ME-50, wherein the fracturing fluid comprises a low-viscosity emulsion and a high-viscosity emulsion;
wherein the concentration of the low-viscosity emulsion is 1.0-1.6%, and the viscosity is 39-51 mPa.s; the concentration of the high-viscosity emulsion is 1.8% -2.4%, and the viscosity is 60-90 mPa.s.
The low-viscosity emulsion and the high-viscosity emulsion are prepared by emulsion with corresponding concentration and viscosity. The emulsion is selected from biological composite emulsion such as Sichuan Shen and SRY-1, fucheng real FC-II and Oriental Baolin-CH 3.
The concentration of the low-viscosity bio-composite emulsion is, for example, 1.0%, 1.1%, 1.2%, 1.3%, 1.4%, 1.5%, 1.6%, and the viscosity is, for example, 39, 40, 42, 45, 46, 48, 50, 51 mPa.s; the concentration of the high-viscosity biocomposite emulsion is, for example, 1.8%, 2.0%, 2.2%, 2.4%, and the viscosity is, for example, 60, 65, 70, 75, 80, 85, 90 mPas.
Nanometer synergist ME-50 is available from great wall drilling fracturing company and is a nanometer-scale product formed by combining surfactant, organic solvent and water; the microcosmic micelle exists in a micelle form, the external part of the microcosmic micelle exists in a surfactant, and the internal part of the microcosmic micelle exists in an organic solvent. Specific performance indexes are shown in the following table.
In a second aspect, the invention provides a tight gas reservoir fracturing method comprising the steps of:
Step S1: annulus low substitution stage: injecting low-viscosity emulsion from an annulus between the oil pipe and the casing pipe, and replacing flushing fluid in the well shaft;
Step S2: a pre-liquid stage: sequentially injecting low-viscosity emulsion, low-viscosity emulsion added with propping agent and high-viscosity emulsion into the annulus to form a main fracture in a reservoir;
Step S3: sand carrying fluid stage: injecting high-viscosity emulsion added with propping agent into the annular space, wherein the adding concentration of the propping agent is gradually increased, and a plurality of branch joints are formed at the end part and around the main fracture along with the extension of the main fracture;
Step S4: and (3) displacing liquid phase: injecting low-viscosity emulsion;
step S5: and (3) extruding and injecting: injecting low-viscosity emulsion, extruding sand-carrying fluid in a shaft into a stratum, and then injecting a gel breaker to strengthen the gel breaking performance of the fracturing fluid;
Wherein the injection concentration of the low-viscosity emulsion is 1.0-1.6%, and the viscosity is 39-51 mPa.s; the injection concentration of the high-viscosity emulsion is 1.8-2.4%, and the viscosity is 60-90 mPa.s;
The pre-fluid stage and the sand-carrying fluid stage are also accompanied by nano synergistic agent ME-50, the pre-fluid stage is accompanied by nano synergistic agent ME-50 accounting for 0.3 to 0.5 percent of the volume of fracturing fluid (low-viscosity emulsion and/or high-viscosity emulsion added in the pre-fluid stage), and the sand-carrying fluid stage (especially the sand-carrying fluid pre-stage, the pre-stage refers to the stage 50 to 60 percent of the volume of sand-carrying fluid (the whole fracturing fluid in the stage)) is accompanied by nano synergistic agent ME-50 accounting for 0.1 to 0.3 percent of the volume of fracturing fluid (low-viscosity emulsion and/or high-viscosity emulsion added in the stage).
S1: annular low-replacement stage
In some embodiments, the injection rate of the low viscosity emulsion of step S1 is 0.5-1.5 m 3/min, such as, but not limited to, 0.5, 0.6, 0.7, 0.8, 0.9, 1.0, 1.2, 1.4, 1.5m 3/min.
S2: front liquid stage
In some embodiments, the injection rate of the low viscosity emulsion, the low viscosity emulsion with the proppant added, and the high viscosity emulsion of step S2 are each independently 5 to 6m 3/min, such as 5, 5.2, 5.4, 5.5, 5.6, 5.8, 6m 3/min, but not limited thereto.
In some embodiments, the proppant is added at a concentration of 50 to 120kg/m 3.
In some embodiments, the propping agent is a combination particle size ceramsite (density of 1.75g/cm 3) comprising a combination of 40-70 mesh (particle size of 0.212-0.425 mm), 30-50 mesh (particle size of 0.300-0.600 mm) and 20-40 mesh (particle size of 0.425-0.85 mm) ceramsite, wherein the 20-40 mesh ceramsite accounts for 10% -60% and the other mesh number ratio can be adjusted according to the water content of the reservoir. Mixing in a sand tank in proportion before injection.
S3: sand carrying fluid stage
In some embodiments, the injection rate of the proppant added high viscosity emulsion of step S3 is 5-6 m 3/min, such as, but not limited to, 5, 5.2, 5.4, 5.5, 5.6, 5.8, 6m 3/min.
In some embodiments, the proppant is added at a concentration (sand concentration) of 50-600 kg/m 3, with the sand concentration increasing from small to large steps over time, such as, but not limited to, 50, 60, 70, 80, 90, 100, 120, 150, 200, 250, 300, 350, 400, 450, 500, 550, 600kg/m 3.
S4: displacing liquid stage
In some embodiments, the injection rate of the low viscosity emulsion of step S4 is 5-6 m 3/min, such as, but not limited to, 5, 5.2, 5.4, 5.5, 5.6, 5.8, 6m 3/min.
S5: extrusion stage
In some embodiments, the injection rate of the low viscosity emulsion of step S5 is 0.5-1.0 m 3/min, such as 0.5, 0.6, 0.7, 0.8, 0.9, 1.0m 3/min, but not limited thereto.
In some embodiments, the breaker of step S5 is injected at a rate of 2 to 3kg/min.
In some embodiments, a breaker is also added in the pad fluid stage, the carrier fluid stage, and the displacement fluid stage; and adding a capsule breaker in a pre-fluid stage and a sand-carrying fluid stage, and adding an ammonium persulfate breaker in a displacement fluid and squeezing stage.
In some embodiments, liquid nitrogen is added in the whole process of the pre-fluid stage and the sand-carrying fluid stage, and the liquid nitrogen discharge capacity is regulated according to the design and actual pressure conditions, and is generally 0.1-0.4 m 3/min.
The emulsion is biological composite emulsion, can be pumped by an independent additive proportion pump, and the adding concentration is adjusted according to the design and the actual pressure condition.
The nano-synergist can be pumped by an additive pump equipped with a sand mixing vehicle. The gel breaker can be added by a dry adding pump matched with the sand mixing vehicle. Liquid nitrogen may be added by a liquid nitrogen pump truck. The propping agent can be added by a sand mixing vehicle, and the adding concentration is adjusted according to the design and the actual pressure condition.
The injection mode in the fracturing method is annular injection, namely the fracturing fluid is injected from the annular space between the oil pipe and the sleeve, and the injection speed is regulated according to the pressure limiting and design requirements and is generally 3.0-6.0 m 3/min. The pumping procedure is divided into 5 stages, and the annular low-replacement stage adopts low mucus; the pre-liquid stage adopts low mucus in the early stage and adopts high mucus in the later stage; the sand carrying fluid stage adopts high viscosity fluid; the displacement liquid stage and the squeezing stage both adopt low-viscosity liquid. And liquid nitrogen is injected in the whole process of the front fluid and the sand carrying fluid. The differential nano synergist is injected, 0.3 to 0.5 percent of nano synergist (volume percent) is added in the front-end liquid stage, and 0.1 to 0.3 percent of nano synergist (volume percent) is adopted in the early stage of sand-carrying liquid.
According to the method, the nanometer cleanup additive is differentially added into the fracturing fluid and goes deep into the pore throat of the nanoscale reservoir, so that the flowback effect of the fracturing fluid is improved, the production is quickly built, and the single well productivity is improved.
Advantageous effects
(1) By concomitantly injecting a nano synergist ME-50 in water-based fracturing, connectivity is improved on the one hand: the pore throat of the compact sandstone low-grade reservoir is small, the sorting property is poor, and the nano synergist is smaller than or equal to the pore throat radius of the reservoir, namely 'getting in and getting out'; on the other hand, the exhaust driving pressure is reduced: the capillary force of the low-grade reservoir layer causes high drainage and driving pressure, the nano synergistic agent has the characteristics of low surface tension, change of wetting contact angle and the like, and the seepage capability, namely 'coming out', is improved, and the performances of the two aspects reduce the water lock of the deep reservoir layer and improve the seepage channels of low pore throat areas such as far-well microcracks and the like. The low-viscosity emulsion controls the net pressure of the initial joint, prevents the joint height from breaking through the interlayer, and ensures that the joint extends in the dominant reservoir; compared with the low-viscosity emulsion, the high-viscosity emulsion has stronger sand carrying effect, is favorable for realizing the sand adding of high sand ratio and ensures the crack supporting effect.
(2) In the fracturing method, annulus injection is adopted, the annular flow channels of the oil pipe and the sleeve are large, the friction resistance performance requirement on fracturing fluid is small, and the selection range and injection speed of the fracturing fluid are increased; the nanometer synergistic agent is added in a differentiated way on the pumping procedure and liquid nitrogen is injected, so that the flow-back difficulty is reduced, the flow-back energy is supplemented, and the flow-back speed is increased; the particle size supports are combined, so that filling and supporting of hydraulic cracks with different dimensions are realized, and the flow conductivity is improved. Finally, the quick flow back and the quick production establishment after the pressing are realized, and the aims of low injury, increased discharge and high yield are achieved.
The present invention has been described in detail hereinabove, but the above embodiments are merely exemplary in nature and are not intended to limit the present invention. Furthermore, there is no intention to be bound by any theory presented in the preceding prior art or summary or the following examples.
Detailed Description
The invention is further illustrated by the following examples, which are provided for illustrative purposes only and are not to be construed as limiting the scope of the invention as claimed.
Unless otherwise indicated, all materials, reagents, methods and the like used in the examples are those conventionally used in the art.
The data of the embodiment are derived from a tight sandstone gas reservoir of the Songlig gas field in China, the gas well type is a vertical well, the well completion mode is perforation well completion, and the fracturing mode is hydraulic fracturing.
The sources of the fracturing fluid system are as follows:
the biological composite emulsion is from Sichuan Shenhe, brand SRY-1.
The nanometer synergist ME-50 is from great wall drilling fracturing company with the brand ME-50.
The combined particle size propping agent is combined particle size ceramsite (density is 1.75g/cm 3), and comprises 40-70 meshes (particle size is 0.212-0.425 mm), 30-50 meshes (particle size is 0.300-0.600 mm) and 20-40 meshes (particle size is 0.425-0.85 mm) of ceramsite, wherein the 20-40 meshes of ceramsite accounts for 40%, the 40-70 meshes of ceramsite accounts for 20%, the 30-50 meshes of ceramsite accounts for 40%, and the ceramsite is mixed in a sand tank according to proportion before injection.
Example 1
The specific implementation process of fracturing is as follows:
Step S1: annulus low substitution stage: injecting low-viscosity biological composite emulsion (namely low-viscosity liquid, wherein the concentration of the biological composite emulsion and water is 1.6% and the viscosity is 51 mPa.s) from an annulus between the oil pipe and the casing, and replacing the well-flushing liquid in the well bore.
Step S2: a pre-liquid stage: injecting low-viscosity liquid (with the concentration as above) into annulus, and then injecting low-viscosity liquid (slug) added with the combined particle size propping agent and high-viscosity biological composite emulsion (namely high-viscosity liquid, wherein the biological composite emulsion and water are pumped in proportion to enable the concentration to be 2.3%, the viscosity to be 81 mPa.s), so that a main crack with a certain length and a wide range is formed in a reservoir.
Step S3: sand carrying fluid stage: high-viscosity liquid (the concentration is as above) of the combined particle size propping agent is injected into the annular space, the propping agent is added in the concentration range of 200-530 kg/m 3, the propping agent is lifted from small steps to large steps, and a plurality of branch cracks are formed at the end parts and around the main cracks along with the extension of the main cracks.
Step S4: and (3) displacing liquid phase: injecting low-viscosity liquid.
Step S5: and (3) extruding and injecting: injecting low-viscosity fluid, extruding sand-carrying fluid in a shaft into a stratum, and then injecting ammonium persulfate gel breaker with low discharge capacity to strengthen the gel breaking performance of the fracturing fluid.
Further, the pre-fluid stage and the sand-carrying fluid stage are accompanied by injection of nano synergist ME-50, the pre-fluid stage is accompanied by injection of 0.4%, and the sand-carrying fluid pre-stage is accompanied by injection of 0.2%.
Further, liquid nitrogen is added in the front-end liquid stage and the sand-carrying liquid stage in the whole process, and the discharge capacity is 0.1-0.2 m 3/min.
Further, a capsule breaker is added in a pre-fluid stage and a sand-carrying fluid stage, and an ammonium persulfate breaker is added in a displacement fluid stage and an extrusion stage.
In the fracturing process, parameters such as oil pipe pressure, casing pipe pressure, discharge capacity, sand concentration and the like are collected.
And after the fracturing is finished, carrying out open flow according to the open flow system of the gas well, and if the open flow cannot be carried out by self-flow, adopting an induced flow measure. After the shut-in pressure diffusion is finished, the blowout is carried out by utilizing a nozzle, a blowout pipeline is opened, fracturing fluid is blown out to a blowout prevention pond, and the production can be carried out after the flowback is finished.
The specific pumping parameters are shown in table 2.
TABLE 2
Note that: the ceramsite in the table is calculated according to the volume density of 1.75g/cm 3 and apparent density of 2.90g/cm 3; "/" indicates none.
Comparative test
Wells similar to the examples were selected and the following conditions were changed according to a similar operational procedure:
1. the nanometer synergistic agent ME-50 is changed into a discharge assisting agent Panjin Hui industry HM-II;
2. The nanometer synergistic agent ME-50 is replaced by imported nanometer synergistic agent Andong AntonFlo-800;
3. The nano synergist ME-50 is added in the front fluid stage by 0.1% and added in the sand-carrying fluid stage by 0.5%.
And comparing the ignition time of the flow-back stage, wherein the ignition time of the embodiment is 1.5h. The ignition time of the first flowback in the comparison test is 6h, the ignition time of the second flowback in the comparison test is 2h, and the ignition time of the third flowback in the comparison test is 3h.
The comparative pressure back flow rate, example back flow rate is 60%. The first flowback rate of the comparative experiment is 43%, the second flowback rate of the comparative experiment is 55%, and the third flowback rate of the comparative experiment is 52%.
It can be seen that the embodiment has the shortest ignition time in the flowback stage and the highest flowback rate after pressure, improves flowback effect and shortens well construction period. The successful application of the invention has positive guiding and reference significance for the hydraulic fracturing of the tight gas reservoir.
The above embodiments are only for illustrating the technical solution of the present invention, and are not limited thereto. Although the invention has been described in detail with reference to the foregoing embodiments, it will be understood by those of ordinary skill in the art that: modifications may be made to the technical solutions described in the foregoing embodiments, or equivalents may be substituted for some or all of the technical features thereof, without departing from the spirit and scope of the present invention as defined in the claims; and such modifications or substitutions are intended to be within the scope of the present invention as defined by the claims.
Claims (12)
1. The tight gas reservoir fracturing fluid is characterized by comprising low-viscosity emulsion, high-viscosity emulsion and nano synergistic agent ME-50;
The low-viscosity emulsion and the high-viscosity emulsion are prepared from biological composite emulsion of SRY-1 of Sichuan Shen and company, the concentration of the low-viscosity emulsion is 1.0% -1.6%, and the viscosity is 39-51 mPa.s; the concentration of the high-viscosity emulsion is 1.8% -2.4%, and the viscosity is 60-90 mPa.s.
2. A tight gas reservoir fracturing method comprising the steps of:
Step S1: annulus low substitution stage: injecting low-viscosity emulsion from an annulus between the oil pipe and the casing pipe, and replacing flushing fluid in the well shaft;
step S2: a pre-liquid stage: sequentially injecting low-viscosity emulsion, low-viscosity emulsion added with propping agent and high-viscosity emulsion into the annulus to form a main fracture in a reservoir;
Step S3: sand carrying fluid stage: injecting high-viscosity emulsion added with propping agent into the annular space, wherein the adding concentration of the propping agent is gradually increased, and a plurality of branch joints are formed at the end part and around the main fracture along with the extension of the main fracture;
Step S4: and (3) displacing liquid phase: injecting low-viscosity emulsion;
step S5: and (3) extruding and injecting: injecting low-viscosity emulsion, extruding sand-carrying fluid in a shaft into a stratum, and then injecting a gel breaker to strengthen the gel breaking performance of the fracturing fluid;
the low-viscosity emulsion and the high-viscosity emulsion are prepared from biological composite emulsion of SRY-1 of Sichuan Shen and company, the injection concentration of the low-viscosity emulsion is 1.0% -1.6%, and the viscosity is 39-51 mPa.s; the injection concentration of the high-viscosity emulsion is 1.8% -2.4%, and the viscosity is 60-90 mPa.s;
The front-end fluid stage and the sand-carrying fluid stage are also accompanied by nano synergistic agent ME-50, the front-end fluid stage is accompanied by nano synergistic agent ME-50 accounting for 0.3-0.5% of the volume of fracturing fluid, and the sand-carrying fluid stage is accompanied by nano synergistic agent ME-50 accounting for 0.1-0.3% of the volume of fracturing fluid.
3. The tight gas reservoir fracturing method according to claim 2, wherein the injection speed of the low viscosity emulsion of step S1 is 0.5-1.5 m 3/min.
4. The tight gas reservoir fracturing method according to claim 2, wherein the injection speed of the low-viscosity emulsion, the low-viscosity emulsion added with the propping agent and the high-viscosity emulsion in the step S2 is 5-6 m 3/min independently.
5. The tight gas reservoir fracturing method according to claim 2, wherein the proppant addition concentration in the proppant-added low-viscosity emulsion of step S2 is 50-120 kg/m 3.
6. The tight gas reservoir fracturing method of claim 5, wherein the proppant is a combination particle size ceramsite comprising a combination of 40-70 mesh, 30-50 mesh and 20-40 mesh ceramsite.
7. The tight gas reservoir fracturing method according to claim 2, wherein the injection speed of the high-viscosity emulsion added with the propping agent in the step S3 is 5-6 m 3/min.
8. The tight gas reservoir fracturing method according to claim 2, wherein the proppant addition concentration in the proppant-added high-viscosity emulsion of step S3 is 50-600 kg/m 3.
9. The tight gas reservoir fracturing method according to claim 2, wherein the injection speed of the low viscosity emulsion of step S4 is 5-6 m 3/min.
10. The tight gas reservoir fracturing method according to claim 2, wherein the injection speed of the low viscosity emulsion of step S5 is 0.5-1.0 m 3/min.
11. The tight gas reservoir fracturing method according to claim 2, wherein the injection speed of the breaker in step S5 is 2-3 kg/min.
12. The tight gas reservoir fracturing method according to claim 2, wherein liquid nitrogen is added in the whole process of the pad-in stage and the sand-carrying stage, and the liquid nitrogen discharge amount is 0.1-0.4m 3/min.
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