CN113216923A - Shale gas fracturing crack-making and sand-adding alternating process for improving supporting effect of crack net - Google Patents
Shale gas fracturing crack-making and sand-adding alternating process for improving supporting effect of crack net Download PDFInfo
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- 238000000034 method Methods 0.000 title claims abstract description 39
- 230000008569 process Effects 0.000 title claims abstract description 35
- 230000008093 supporting effect Effects 0.000 title claims abstract description 21
- 239000004576 sand Substances 0.000 claims abstract description 30
- 239000000835 fiber Substances 0.000 claims abstract description 29
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 18
- 239000003292 glue Substances 0.000 claims abstract description 16
- 239000002253 acid Substances 0.000 claims abstract description 15
- 238000010276 construction Methods 0.000 claims abstract description 14
- 239000012530 fluid Substances 0.000 claims description 34
- 239000007788 liquid Substances 0.000 claims description 25
- 239000007789 gas Substances 0.000 claims description 23
- 238000002347 injection Methods 0.000 claims description 23
- 239000007924 injection Substances 0.000 claims description 23
- 239000000243 solution Substances 0.000 claims description 19
- 239000003795 chemical substances by application Substances 0.000 claims description 17
- 239000003381 stabilizer Substances 0.000 claims description 13
- 239000002131 composite material Substances 0.000 claims description 12
- 239000002518 antifoaming agent Substances 0.000 claims description 9
- 239000002562 thickening agent Substances 0.000 claims description 6
- -1 flow state improver Substances 0.000 claims description 5
- 238000012360 testing method Methods 0.000 claims description 5
- 238000005260 corrosion Methods 0.000 claims description 4
- 230000007797 corrosion Effects 0.000 claims description 4
- 238000006073 displacement reaction Methods 0.000 claims description 4
- 239000003112 inhibitor Substances 0.000 claims description 4
- VEXZGXHMUGYJMC-UHFFFAOYSA-N Hydrochloric acid Chemical compound Cl VEXZGXHMUGYJMC-UHFFFAOYSA-N 0.000 claims description 3
- 239000000654 additive Substances 0.000 claims description 3
- 230000000996 additive effect Effects 0.000 claims description 3
- 230000000844 anti-bacterial effect Effects 0.000 claims description 3
- 230000002579 anti-swelling effect Effects 0.000 claims description 3
- 239000003899 bactericide agent Substances 0.000 claims description 3
- 238000004364 calculation method Methods 0.000 claims description 3
- 239000003638 chemical reducing agent Substances 0.000 claims description 3
- 239000004927 clay Substances 0.000 claims description 3
- 239000003431 cross linking reagent Substances 0.000 claims description 3
- IXCSERBJSXMMFS-UHFFFAOYSA-N hydrogen chloride Substances Cl.Cl IXCSERBJSXMMFS-UHFFFAOYSA-N 0.000 claims description 3
- 229910000041 hydrogen chloride Inorganic materials 0.000 claims description 3
- XEEYBQQBJWHFJM-UHFFFAOYSA-N iron Substances [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 claims description 3
- 229910052742 iron Inorganic materials 0.000 claims description 3
- 229920000642 polymer Polymers 0.000 claims description 3
- 239000006254 rheological additive Substances 0.000 claims description 3
- 238000009491 slugging Methods 0.000 claims description 3
- 239000000499 gel Substances 0.000 claims description 2
- 230000000694 effects Effects 0.000 claims 4
- 238000005086 pumping Methods 0.000 abstract description 26
- 238000004519 manufacturing process Methods 0.000 abstract description 3
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- 206010017076 Fracture Diseases 0.000 description 49
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- 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
- E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
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- 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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Abstract
The invention discloses a shale gas fracturing fracture-making and sand-adding alternating process for improving a fracture network supporting effect, which comprises the following steps: 1. determining a target reservoir through researching the characteristics of the shale reservoir; 2. pumping a certain amount of acid liquor before fracturing construction; 3. using high-viscosity slick water to make a main seam; 4. manufacturing branch seams by adopting low-viscosity slick water; 5. injecting medium-viscosity active glue solution to carry small-particle-size proppant and fibers to enter a branch seam network and form a proppant cluster column; 6. pumping low-viscosity slick water to continue to expand the branch seam net; 7. pumping the medium-viscosity active glue solution to carry the small-particle-size proppant and the fibers into the branch gap net to form a cluster column, and filling the newly formed branch gap net; 8. repeating 6 and 7; 9. pumping high viscosity active cement to tail-end the large particle size proppant to fill the main fracture. According to the process, seam making and sand adding are alternately combined through a certain time period, so that the seam net area is enlarged, the seam net supporting effect is improved, and the yield of the shale gas horizontal well after fracture net fracturing is further improved.
Description
Technical Field
The invention relates to a shale gas fracturing, seam making and sand adding alternating process for improving a seam net supporting effect, and belongs to the technical field of unconventional oil and gas yield increasing transformation.
Background
At present, conventional fracturing, steering fracturing, large-scale fracture network fracturing, volume fracturing and other processes are mainly used at home and abroad, and the shale reservoir has small porosity and extremely low permeability; meanwhile, in the large-scale fracture network fracturing construction, the phenomena that a large amount of propping agents are difficult to enter secondary fractures and the like exist, so that the fracture network quality cannot achieve the optimal fracturing benefit, and a novel and efficient fracturing production increasing process needs to be explored urgently.
According to the test results, Luyang (2014) considers that in a stratum with high closure pressure and low Young modulus, a propping agent 'pillar' is easy to collapse, so that the channel is blocked, the crack is closed, and the flow conductivity is reduced, so that the ratio of the Young modulus to the closure pressure can be used as a key geological and construction parameter for judging the high-speed channel fracturing feasibility. The yellow wave (2017) provides a channel fracturing well selection and dynamic parameter optimization design method, and on the basis of the known stratum parameters of a target well; establishing a channel fracturing well selection layer model and establishing a relation among a sand adding liquid column, a middle top liquid column and proppant distribution based on process characteristics; and (4) giving a reasonable proportion of the middle top time and the sand adding time so as to optimize the fracturing process. From the perspective of seepage conditions of fracturing fractures of unconventional reservoirs such as compact sandstone and the like and long-term conductivity after fracturing, Chen Xingyu (2019) introduces a discontinuous multilayer sand paving concept in the fractures, supposes that the geometric relationship between the volume of proppant sand clusters and the volume of fracturing fluid in a unit body meets the volume conservation principle, simplifies the proppant sand clusters in the discontinuous distribution in the fractures into circular columnar uniform distribution on the premise of not considering compressibility of proppant particles and fracturing fluid, and takes the sand clusters in a unit pulse period and surrounding unsupported regions as calculation units.
Disclosure of Invention
In order to overcome the problems in the prior art, the invention provides an alternative process of shale gas fracturing fracture making and sand adding for improving the fracture network supporting effect, aiming at enabling more proppants to enter the fracture network, forming discontinuous proppant clusters with high-efficiency flow guiding capacity in the fracture network, enlarging the fracture network area, improving the fracture network supporting effect, improving the fracture network quality and further improving the yield of the fractured shale gas horizontal well fracture network.
The technical scheme provided by the invention for solving the technical problems is as follows: a shale gas fracturing fracture-making and sand-adding alternating process for improving a fracture network supporting effect comprises the following steps:
s10, determining a reservoir with the Young modulus and the stratum closure stress ratio larger than 350 as a target reservoir according to the geological parameters of the target shale gas well;
step S20, determining the injection time t of the carrier fluid according to the geological parameters and the perforation mode of the target shale gas well1And middle top liquid injection time t2；
Step S30, injecting acid liquor into the target reservoir through the shaft for acid pretreatment;
step S40, injecting a high-viscosity slick water main seam into the target reservoir;
step S50, according to the sand-carrying fluid injection time t1Injecting low-viscosity slick water into the target reservoir stratum to form a branch seam;
step S60, according to the injection time t of the middle top liquid2Injecting medium-viscosity active glue solution carrying small-particle-size proppant and fibers into a target reservoir layer and allowing the medium-viscosity active glue solution and the fibers to enter a branch gap net to form a cluster column;
step S70, according to the sand-carrying fluid injection time t1Injecting low-viscosity slick water into the target reservoir to continuously expand the branch seam network;
s80, repeating S60 and S70 for multiple times to complete the steps of making seams and adding sand;
and S90, injecting a high-viscosity active glue solution into the target reservoir to tail-chase the large-particle-size proppant to fill the main fracture.
The further technical solution is that the calculation formula in step S20 is:
in the formula: rhosIs proppant volume density, kg/m3；ViIs the volume of the trench in a single stage time, m3；ρcIn terms of proppant concentration, kg/m3；QiIs the construction displacement m in stage time3/min；HfM for supporting the seam height; t is tiIs the stage time; eta is the effective rate of perforation, which is obtained by the test before fracturing, omega is the average fracture width of the supporting fracture, m; t is t1The time for slugging the sand-carrying fluid; t is t2The middle top liquid injection time; n iseThe effective number of the holes, N the number of the perforation holes, d the sand cluster spacing, mm; h is the initial height of the sand ball, mm.
The further technical scheme is that the acid solution in the step S30 includes hydrogen chloride, a high-temperature corrosion inhibitor, and an iron ion stabilizer.
Further technical solution is that the high-viscosity slick water in step S40 includes: high-efficiency drag reducer, composite anti-swelling agent, composite synergist and defoaming agent.
Further technical solution is that the low viscosity slick water in step S50 includes: high-molecular thickening agent, flow state improver, composite synergist, viscosity regulator, defoaming agent, temperature stabilizer, cleanup additive, clay stabilizer, bactericide, cross-linking agent and gel breaker.
The further technical scheme is that the medium viscosity active glue solution in the step S60 comprises a low molecular thickening agent, a rheological additive, a composite synergist, a viscosity regulator, a defoaming agent and a temperature stabilizer.
The further technical scheme is that the fiber in the step S60 is degradable fiber.
The further technical scheme is that the fiber in the step S60 is an organic acid ester polymer.
The invention has the following beneficial effects: the invention refers to the concept of channel fracturing, the process is based on the idea of fracturing while making cracks and adding sand, the staged multi-cluster fracturing is carried out on the horizontal well of the shale reservoir, and whether the construction quality of the fracturing network can be improved by the alternative process of making cracks and adding sand is judged by researching the characteristics of the shale reservoir. Considering that the construction pressure is high due to the influence factors such as local accumulated pollution of a horizontal section, near well friction resistance and the like, a certain amount of acid liquor is pumped for unblocking; secondly, pumping a certain amount of high-viscosity slickwater to generate artificial main cracks; then activating natural fractures to form a complex branched fracture network in a shearing failure mode by adopting low-viscosity slick water; then pumping in medium mucus to carry small-particle-size propping agent and fibers to enter the branch gap net to form a cluster column, pumping in low mucus within a certain time to continue expanding the branch gap net, pumping in medium mucus to carry small-particle-size propping agent and fibers to enter the branch gap net within a certain time interval to form a cluster column, filling the newly formed branch gap net, and finally pumping in high mucus to carry out tracing on the large-particle-size propping agent to fill the main crack. In a certain time period, the area of the fracture net is enlarged, the supporting effect of the fracture net is improved, the yield of the shale gas horizontal well fracture net after fracturing is further improved, and a new thought and a new direction are provided for improvement and development of fracturing technology in future through an alternate pumping and injecting process of forming the fracture net by low-viscosity liquid and filling fractures by medium-high-viscosity liquid carrying sand.
Drawings
FIG. 1 is a block diagram of the process flow of the present invention;
FIG. 2 is a time interval diagram of seam making and sanding;
FIG. 3 is a simulation diagram of the conductivity under the process;
FIG. 4 is a simulated plot of the proppant concentration under the process;
FIG. 5 is a simulation of the width of a crack under the process;
FIG. 6 is a simulation of the fracture network under this process.
Detailed Description
The technical solutions of the present invention will be described clearly and completely with reference to the accompanying drawings, and it should be understood that the described embodiments are some, but not all embodiments of the present invention. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
The invention relates to a shale gas fracturing fracture-making and sand-adding alternating process for improving the supporting effect of a fracture network, which comprises the following steps of:
s10, determining a reservoir with the Young modulus and the stratum closure stress ratio larger than 350 as a target reservoir according to the geological parameters of the target shale gas well;
step S20, determining the injection time t of the carrier fluid according to the geological parameters and the perforation mode of the target shale gas well1And middle top liquid injection time t2；
It is assumed that,
the compound is obtained by the formula as above,
suppose, ati＝λ(λ＞0) (7)
The compound is obtained by the formula as above,
order to
Derivative the function to obtain
Get the minimum point
The function image presents a trend of descending first and then ascending, and simultaneously considers the actual construction condition, so that a minimum point is taken,
then the process of the first step is carried out,
the formula is as follows: tau iscA proppant plunger nuclear zone center safety factor; mu.sσvIs the original stress mean value, MPa; mu.sσp1The strength average value of the proppant sand column is MPa; rhosIs proppant volume density, kg/m3；ViIs the volume of the trench in a single stage time, m3；ρcIn terms of proppant concentration, kg/m3；QiIs the construction displacement m in stage time3/min；HfM for supporting the seam height; t is tiIs the stage time; eta is the effective rate of perforation, which is obtained by the test before fracturing, omega is the average fracture width of the supporting fracture, m; mu is the viscosity of the fracturing fluid, mPa & s; l is the crack length, m; upsilon is Poisson's ratio and has no dimension; e is Young's modulus, MPa.
From the formulas (1) to (9), it can be seen that the minimum point t is takeniAnd in combination with the formula,
t1+t2＝ti (11)
ne＝Nη (12)
it is assumed that,
then obtain t1(1+k)+t2＝D (15)
Obtained from the formulae (9) to (15),
t1the time for slugging the sand-carrying fluid; t is t2The middle top liquid injection time; n iseThe effective number of the holes, N the number of the perforation holes, d the sand cluster spacing, mm; h is the initial height of the sand ball, mm;
step S30, injecting acid liquor into the target reservoir through the shaft for acid pretreatment;
step S40, according to the injection time t of the pad liquid0Injecting a high-viscosity slick water main seam into the target reservoir stratum;
step S50, according to the sand-carrying fluid injection time t1Injecting low-viscosity slick water into the target reservoir stratum to form a branch seam;
step S60, according to the injection time t of the middle top liquid2Injecting medium-viscosity active glue solution carrying small-particle-size proppant and fibers into a target reservoir layer and allowing the medium-viscosity active glue solution and the fibers to enter a branch gap net to form a cluster column;
step S70, according to the sand-carrying fluid injection time t1Injecting low-viscosity slick water into the target reservoir to continuously expand the branch seam network;
s80, repeating S60 and S70 for multiple times to complete the steps of making seams and adding sand;
and S90, injecting a high-viscosity active glue solution into the target reservoir to tail-chase the large-particle-size proppant to fill the main fracture.
Therefore, by a certain time period, the seam forming process and the sand adding process are alternately combined, so that the seam net area is enlarged, the seam net supporting effect is improved, and the yield of the shale gas horizontal well after the seam net is fractured is further improved.
Specifically, the invention is mainly applied to rigid strata, the ratio of the Young modulus to the stratum closure stress is required to be reasonable, and generally, in high-stratum closure stress and low-Young modulus strata, the implementation of staged sand addition easily causes collapse of proppant sand clusters, channel blockage, fracture closure and reduction of flow conductivity. The field test shows that the ratio of the Young modulus to the stratum closing stress is less than 350, and the fracture stability is poor; the ratio of the number of the channels is 350-500, and the channels belong to stable intra-seam network channels; and if the ratio is more than 500, judging the stratum with better implementation conditions, and judging whether the shale reservoir stratum can improve the quality of the fracture network through an alternate fracture-making and sand-adding fracturing process.
Specifically, the method is mainly realized by adopting a casing injection mode, and the proppant 'pillars' are discontinuously dispersed and laid in the cracks while the slickwater is pumped for forming the cracks.
Specifically, the joint-making and sand-adding alternating process in the steps of the invention is to inject the pad fluid, the sand-carrying fluid and the middle top fluid alternately at intervals of minutes, and form 'pillar-shaped' support in the fracture while making the joint. After a period of pumping acid into the formation, pumping a certain amount of high-viscosity slickwater to generate artificial main fractures, and pumping low-viscosity slickwater to activate more natural fractures and manufacture more branch fracture networks so that the propping agent enters more fractures as much as possible; then, pumping in medium-viscosity liquid carrying small-particle-size propping agent and fiber into a branch gap net to form a cluster column, pumping in low-viscosity liquid within a certain time to continue expanding the branch gap net, then pumping in high-viscosity liquid within a certain time interval to carry small-particle-size propping agent and fiber into the branch gap net to form a cluster column, filling the newly formed branch gap net, and discontinuously laying the propping agent in the fracturing crack in a cluster column form by alternately filling the sand-mixed liquid carrying propping agent and medium-top liquid, thereby being more beneficial to forming a channel network with high-speed flow guiding capacity around the cluster column, enabling the crack to have higher flow guiding capacity, further improving the quality of the gap net and achieving the purpose of increasing the yield.
Examples
In the embodiment, the relevant data refers to relevant empirical construction data of a certain well area in the east of Chuandong, referring to table 1, combining formula (1) to formula (17), and synthesizing relevant factors to finally obtain t1＝t23.5. The staged joint-making and sand-adding process is mainly characterized in that pad fluid, propping agent and middle top fluid are alternately injected at intervals of 3.5 minutes, and the construction pumping procedure shown in the table 2 is obtained.
The method comprises the following specific steps:
step 3, at t0Pumping slickwater for making seams within a time period;
step 4, at t1Pumping sand carrying liquid accompanied with fiber,
step 5, at t2Pumping middle top liquid to prevent the backflow of the propping agent;
step 6, at t01Pumping slick water into the cavity to continue to form seams;
7, repeating the steps 4 to 6, and alternately and circularly adding sand;
and 8, finally, in order to form effective communication between the fracture and the shaft, performing a continuous proppant pumping stage of tracing back for a relatively long time so as to avoid narrow spots or proppant-free areas in the near-wellbore area, wherein the tracing back stage is continuous sand adding.
In the embodiment, the main formula of the pretreatment acid is 15% of HCl + 2.0% of high-temperature corrosion inhibitor + 1.5% of iron ion stabilizer; meanwhile, the high-temperature corrosion inhibitor meets the temperature requirement of more than 140 ℃.
In the embodiment, 100-mesh proppant is usually selected for shale reservoir fracturing to be used as a slug in a pad fluid stage, so that natural fractures are plugged, the filtration loss is reduced, and in order to increase the fracture conductivity and reduce the sand plugging risk, 40/70-mesh proppant and 30/50-mesh larger particle size are selected as sand-carrying fluids in the middle and later stages. Generally, the target layer of the deep shale fracturing well is over four thousand meters deep, the closing stress is measured and calculated according to the minimum horizontal main stress, generally about 65-80MPa, and in order to avoid sand blocking in construction and improve the flow conductivity of cracks, the construction of 100-mesh + 40/70-mesh + 30/50-mesh low-density coated ceramsite proppant is recommended. The ceramsite has the characteristics of low density, high strength and high short-term flow conductivity.
In the embodiment, the pad fluid is slick water, the main formula of the pad fluid is clear water, 0.2 percent of high-efficiency drag reducer, 0.3 percent of composite anti-swelling agent, 0.1 percent of composite synergist and 0.02 percent of defoaming agent, and the pad fluid is mainly used for pressing stratum to open and form seams; the sand-carrying fluid is a high-viscosity fluid, the main formula of the sand-carrying fluid is 0.5 percent of a high-molecular thickening agent, 0.3 percent of a flow state improver, 0.1 percent of a composite synergist, 0.05 percent of a viscosity regulator, 0.02 percent of a defoaming agent, 0.1 to 0.3 percent of a temperature stabilizer, a cleanup additive, a clay stabilizer, a bactericide, a crosslinking agent, a gel breaker and the like, and the sand-carrying fluid is mainly used for carrying a propping agent to enter a crack; the middle top liquid is a low-viscosity liquid, and the main formula of the middle top liquid is 0.2% of low-molecular thickening agent, 0.3% of rheological additive, 0.1% of composite synergist, 0.05% of viscosity regulator, 0.02% of defoaming agent and 0.1-0.3% of temperature stabilizer; the primary purpose is to further drive the proppant clusters into the fractured fractures. Considering that the formation temperature is high, the injection process needs to ensure the rheological property and sand carrying property of the glue solution, and simultaneously ensures that the glue solution breaks and hydrates section by section in the cracks in the closed stage after the displacement is finished, and finally realizes synchronous glue breaking after the full well is pressed. Wherein the viscosity regulator and the temperature stabilizer are prepared according to the specific situation on site, and are generally linear preparation proportions.
In the embodiment, when the sand-carrying fluid is added, the fibers are added, and the fibers wind and bind the proppant by utilizing the molecular characteristics of the fibers, so that the proppant can be stably collected and can be kept in a columnar shape within two hours after entering the fracture, and the proppant is not dispersed and settled within the time period. The whole sand-carrying liquid pumping stage adopts the periodic pumping repeatedly, the concentration of the propping agent is gradually increased, and the concentration of the fiber is gradually increased in proportion; thereby being beneficial to the proppant clusters entering the fracture to present a discontinuous distribution state. And finally, a proppant slug is added before the injection is finished, and a uniform supporting layer is formed between the channel of the fracture port and the well hole, so that the high flow guide is realized, and the proppant can be prevented from flowing back. In this embodiment, the degradable fiber is an organic acid ester polymer, which can be degraded at high temperature to release acid, and has the functions of reducing resistance, preventing proppant from flowing back and settling, etc. in the fracturing fluid.
Specifically, the fiber fracturing fluid sand-carrying is that degradable fibers can be degraded within 30 hours at the formation temperature of 65-80 ℃ and are discharged back to the ground, so that the pollution of the degradable fibers to the formation is reduced, and the formed 'pillar' has flow conductivity without affecting the formation yield; the adding mode is that according to different pump injection stages, 0.18-0.24% of the mixture is evenly added into fracturing fluid to form fiber fracturing, and the fiber fracturing fluid is used for carrying sand.
TABLE 1 ratio of Young's modulus to closure stress
TABLE 2 Pump priming Programme
Although the present invention has been described with reference to the above embodiments, it should be understood that the present invention is not limited to the above embodiments, and those skilled in the art can make various changes and modifications without departing from the scope of the present invention.
Claims (8)
1. The utility model provides an improve shale gas fracturing of seam net support effect and make seam and add sand process in turn which characterized in that includes:
s10, determining a reservoir with the Young modulus and the stratum closure stress ratio larger than 350 as a target reservoir according to the geological parameters of the target shale gas well;
step S20, determining the injection time t of the carrier fluid according to the geological parameters and the perforation mode of the target shale gas well1And middle top liquid injection time t2；
Step S30, injecting acid liquor into the target reservoir through the shaft for acid pretreatment;
step S40, injecting a high-viscosity slick water main seam into the target reservoir;
step S50, according to the sand-carrying fluid injection time t1Injecting low-viscosity slick water into the target reservoir stratum to form a branch seam;
step S60, according to the injection time t of the middle top liquid2Injecting medium-viscosity active glue solution carrying small-particle-size proppant and fibers into a target reservoir layer and allowing the medium-viscosity active glue solution and the fibers to enter a branch gap net to form a cluster column;
step S70, according to the sand-carrying fluid injection time t1Injecting low-viscosity slick water into the target reservoir to continuously expand the branch seam network;
s80, repeating S60 and S70 for multiple times to complete the steps of making seams and adding sand;
and S90, injecting a high-viscosity active glue solution into the target reservoir to tail-chase the large-particle-size proppant to fill the main fracture.
2. The shale gas fracturing fracture-making and sand-adding alternating process for improving the fracture-network supporting effect as claimed in claim 1, wherein the calculation formula in the step S20 is as follows:
in the formula: rhosIs proppant volume density, kg/m3；ViIs the volume of the trench in a single stage time, m3；ρcIn terms of proppant concentration, kg/m3；QiIs the construction displacement m in stage time3/min；HfM for supporting the seam height; t is tiIs the stage time; eta is the effective rate of perforation, which is obtained by the test before fracturing, omega is the average fracture width of the supporting fracture, m; t is t1The time for slugging the sand-carrying fluid; t is t2The middle top liquid injection time; n iseThe effective number of the holes, N the number of the perforation holes, d the sand cluster spacing, mm; h is the initial height of the sand ball, mm.
3. The shale gas fracturing and sand adding alternating process for improving the supporting effect of the fracture network as claimed in claim 1, wherein the acid solution in the step S30 comprises hydrogen chloride, high temperature corrosion inhibitor and iron ion stabilizer.
4. The shale gas fracturing fracking and sanding alternating process for improving the fracture-network support effect as claimed in claim 1, wherein said high-viscosity slickwater of step S40 comprises: high-efficiency drag reducer, composite anti-swelling agent, composite synergist and defoaming agent.
5. The shale gas fracturing frac and sanding alternating process for improving the support effect of the fracture network as claimed in claim 1, wherein the low viscosity slickwater of step S50 comprises: high-molecular thickening agent, flow state improver, composite synergist, viscosity regulator, defoaming agent, temperature stabilizer, cleanup additive, clay stabilizer, bactericide, cross-linking agent and gel breaker.
6. The shale gas fracturing fracture-making and sand-adding alternating process for improving the fracture-network supporting effect as claimed in claim 1, wherein the medium-viscosity active glue solution in the step S60 comprises a low-molecular thickening agent, a rheological additive, a composite synergist, a viscosity regulator, a defoaming agent and a temperature stabilizer.
7. The shale gas fracturing fracking and sanding alternating process of claim 6 for improving the support effect of the fracture network, wherein the fibers in step S60 are degradable fibers.
8. The alternating shale gas fracturing fracking and sanding process of claim 7 wherein the fibers of step S60 are an organic acid ester polymer.
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