Temporary plugging steering and large-particle-size sand fracturing method for deep coal rock reservoir

Abstract

The invention discloses a temporary plugging steering and large-particle-size sand adding fracturing method for a deep coal and rock reservoir. The method comprises the measures of viscosity control, fracture forming and sand increasing, shielding temporary plugging steering, steering sand temporary plugging, large-particle-size filling supporting and the like. Comprising the following steps that high-viscosity liquid is adopted for making a main crack, and cleaving is started; medium-low mucus is switched, 40 / 70-mesh proppant is continuously added, near-wellbore zone filling and cleaving are conducted, and a shielding zone is formed; the first steering of the fracturing crack is realized by stopping and starting the pump; a far-end cleat is opened through high-viscosity liquid, and more main seams are formed; secondary cracks and micro cracks are expanded by adopting medium-high mucilage liquid carrying 40 / 70-mesh proppant; medium mucilage liquid is adopted for carrying steering sand for temporary plugging in the fracture, secondary steering of the fracturing fracture is achieved, and the fracture net is more complicated; middle-high mucus is adopted to carry a 30 / 50-mesh proppant to realize multi-scale effective support of the complex seam net. According to the method, the coal rock fracturing transformation volume and the crack complexity can be remarkably improved, the flow conductivity of the support crack is improved, the measure yield is improved, and the stable production period is prolonged.

Description

Technical Field

[0001] The invention relates to the technical field of fracturing and production enhancement transformation of deep coal rock reservoirs, and in particular to a temporary plugging and diversion and large-grained sand fracturing method for deep coal rock reservoirs. Background Art

[0002] Deep coal-rock gas has become another unconventional gas reservoir with great development potential after shale gas. The large-scale extreme volume fracturing of China's first deep coal-rock gas horizontal well, Jishen 6-7 Ping 01 Well, was successfully implemented and achieved a breakthrough in production of 100,000 cubic meters per day, which opened the prelude to the development of deep coal-rock gas in China. Extreme volume fracturing technology is an effective means to obtain high-yield industrial gas flow in deep coal-rock gas. This technology fully transforms coal and rocks through the combined optimization of "construction process + construction scale, parameters + fracturing fluid, proppant solution" to achieve an increase in coal-rock gas production.

[0003] The displacement of coal-rock gas volume fracturing construction is increasing, from 12 to 16 m 3 / min increased to the current 18 ~ 24m 3 / min, high displacement will inevitably cause high pressure in the fracture, so that the coal rock forms wide fractures, which is more conducive to the entry of proppant, and affected by the softer coal rock, the smaller the proppant particle size is, the easier it is to embed, resulting in reduced conductivity. Therefore, when the construction conditions permit and the coal rock characteristics require it, the use of 200 mesh sand and 100 mesh sand will reduce the fracturing effect. Therefore, large-size filling support measures have more potential, and it is necessary to make targeted optimization of the supporting fracturing fluid system and the measures of controlling viscosity and creating fractures and increasing sand; secondly, similar to shale fracturing transformation, reasonable temporary plugging and diverting measures are an effective means for coal rock to form a uniform and complex fracture network, but the characteristics of coal rock are different from shale. There are many natural cleat fractures and serious filtration loss. The early fractures tend to be in the high permeability layer, which can easily cause uneven development of the fracture network. It is necessary to reasonably optimize the temporary plugging and diverting agent (sand), implementation process, parameters, etc. In short, with the deepening of understanding of coal rock characteristics, fracture network fracturing, and temporary plugging and diversion fracturing technology, it is urgent to carry out targeted research on process conditions, parameters, and measures to optimize and upgrade technology, so as to form unique processes and technologies for coal rock gas fracturing, fully "break up" the coal seam, promote the formation of uniform and ultra-dense volume fracture networks in the entire section of coal rock horizontal wells, and effectively support the saturated sand fracture network to promote the efficient diffusion and seepage of coal rock gas, and achieve another breakthrough in coal rock gas development. Summary of the invention

[0004] In view of the difficulties mentioned above, the present invention proposes a temporary plugging and diversion, large-particle sand fracturing method for deep coal-rock reservoirs. The present invention makes full use of the special advantages of high-efficiency variable viscosity fracturing fluid and upper / lower diversion sand in deep coal-bed methane, controls performance and parameters at different stages of fracturing, and then combines the volume fracturing process to propose a combination of viscosity-controlled fracture sanding, shielding temporary plugging and diversion, diversion sand temporary plugging and large-particle filling support, which can significantly increase the volume of coal-rock fracturing transformation and the complexity of fractures, improve the conductivity of supported fractures, increase the output of measures, and extend the stable production cycle.

[0005] In order to achieve the above object, the technical solution provided by the present invention is as follows:

[0006] A temporary plugging and diversion, large-grain sand fracturing method for deep coal rock reservoirs, comprising the following steps:

[0007] S1, the first pre-fluid to create the main fracture: use high viscosity fracturing fluid at the first displacement to open the coal rock cleat, create the main fracture to connect the near-wellbore zone;

[0008] S2, the first sand-carrying fluid is used to lay the shielding belt: medium-low viscosity fracturing fluid is used to carry 40 / 70 mesh proppant into the formation at the first stage sand ratio at the second displacement, and the stage proppant dosage is W1 square, to grind and fill the cracks, further open the cleats and fissures, and lay proppant in the high permeability dominant fractures near the wellbore to form a shielding belt;

[0009] S3, stop and start the pump midway: stop the pump for 60 minutes to 120 minutes and then start the pump again to complete temporary shielding and the first diversion of the crack;

[0010] S4, second pre-fluid communication with the far end: use high viscosity fracturing fluid to open the coal seam again at the second displacement to form a long main fracture, create new fractures and more branch fractures and communicate with the far end;

[0011] S5, second sand-carrying fluid extension fracture network: medium viscosity fracturing fluid is used to carry 40 / 70 mesh proppant into the formation at the second displacement with the second stage sand ratio, and the stage proppant dosage is W2 cubic meters, so that the complex fracture network is continuously extended, and the proppant is filled in the micro fractures and secondary fractures;

[0012] S6, the third sand-carrying fluid plus diverting sand: use medium-low viscosity fracturing fluid to carry diverting sand into the formation at the third stage sand ratio at the first displacement, and the amount of diverting sand is W3 cubic meters. The diverting sand expands, self-bridging, and aggregates to change the extension direction of the fracture, thereby achieving secondary diversion of the fracture;

[0013] S7, the fourth sand-carrying fluid fracture network support: use medium-high viscosity fracturing fluid to carry 30 / 50 mesh proppant into the formation at the 4th stage sand ratio at the 2nd displacement, and the stage proppant dosage is W4 square, so that the proppant is gradually supported and filled from the middle end of the fracture to the proximal end, improving the overall filling degree of the fracture network and establishing a complex fracture network of saturated sand that penetrates each other;

[0014] S8, stop sand and replace to end construction: after stopping sand, use medium-high viscosity fracturing fluid + low viscosity fracturing fluid to replace to the designed replacement volume, then stop pumping to end construction;

[0015] The apparent viscosity of the high-viscosity fracturing fluid is 39mPa·s to 48mPa·s, the apparent viscosity of the medium-high-viscosity fracturing fluid is 27mPa·s to 36mPa·s, the apparent viscosity of the medium-viscosity fracturing fluid is 15mPa·s to 24mPa·s, the apparent viscosity of the medium-low-viscosity fracturing fluid is 9mPa·s to 12mPa·s, and the apparent viscosity of the low-viscosity fracturing fluid is 3mPa·s to 6mPa·s.

[0016] As a specific implementation of the present invention, the first displacement value range is 12m 3 / min≤Q1<16m 3 / min; the second displacement range is 16m 3 / min≤Q2≤25m 3 / min.

[0017] As a specific embodiment of the present invention, the sand ratio in the first stage increases in steps from 8% to 16%, with each step being 2%; the sand ratio in the second stage increases in steps from 13% to 22%, with each step being 3%; the sand ratio in the third stage increases in steps from 16% to 18%, with each step being 2%; the sand ratio in the fourth stage increases in steps from 20% to 24%, with each step being 2%.

[0018] As a specific embodiment of the present invention, the W 1、 W 2、 W 3、 The sum of W4 is the total amount of sand added in a single section of a coal-rock gas horizontal well, W, which is determined by the section length D. The control principle is: W = (4-5) * D;

[0019] Taking the total volume of W as 100 parts, W1 accounts for 10 to 12 parts, W2 accounts for 35 to 45 parts, W3 accounts for 10 to 13 parts, and W4 accounts for 35 to 40 parts.

[0020] As a specific implementation of the present invention, in order to ensure the formation of a complex, three-dimensional network seam structure and proppant support, the construction displacement at each stage is increased as much as possible according to the construction pressure while ensuring construction safety.

[0021] As a specific embodiment of the present invention, the turning sand is a micro-expansion coating material, which is prepared by coating a matrix with a mixture of a resin, a hydrophobic modifier, and a Zeta potential regulator, aging, and screening;

[0022] The matrix particle size range is 0.104 mm to 0.425 mm;

[0023] The turning sand includes upper turning sand and lower turning sand in a volume ratio of 1:1. When a low-density matrix is ​​selected, the lower turning sand is obtained, and the density is 0.95-1.05 g / cm 3 During fracturing, the fracturing fluid enters and floats to the top of the crack, forming a low permeability barrier to prevent the crack from extending upward, thus achieving the downward diversion of the crack. When a high-density matrix is ​​selected, the upward diversion sand is obtained, with a density of 1.6 to 1.85 g / cm 3 During fracturing, the fracturing fluid enters and sinks to the bottom of the crack, forming a low-permeability barrier to prevent the crack from extending downward, thereby achieving an upward diversion of the crack.

[0024] As a specific embodiment of the present invention, based on 100 parts by total mass, the combination ratio of the resin, the hydrophobic modifier, and the Zeta potential regulator in the mixture is 97:1:2;

[0025] As a specific embodiment of the present invention, the resin is a combination of any one of diphenylmethane diisocyanate (MDI) and toluene diisocyanate (TDI) and any one of polyacrylic acid resin, polymethyl methacrylate, phenolic resin, polyamide-imide (PAI) resin, and polylactic acid ester, and the combination ratio is 2:1 to 3:1;

[0026] As a specific embodiment of the present invention, the hydrophobic modifier is one of hydrophobic nano-silica, dimethyl polysiloxane, fluorinated polysiloxane, and zinc stearate;

[0027] As a specific embodiment of the present invention, the zeta potential regulator is one of 3-(2-methylpyrimidine)aniline, 5-(4-methoxyphenyl)pyrimidine-2-amine, 5-ethylpyrimidine-2-amine, 2-aminopyrimidine-dodecylmethyldihydroxyethylammonium bromide mixture (the mass ratio of the two is 1:6 to 1:10), and 2-aminopyrimidine-chloroethyltrimethylammonium chloride mixture (the mass ratio of the two is 1:8 to 1:10);

[0028] As a specific embodiment of the present invention, the low-density matrix is ​​one of nut shell particles and high-strength polymer microspheres, the nut shell is one of walnut shell, macadamia shell and almond shell; the high-strength polymer microspheres are one of styrene-N,N'-methylenebisacrylamide-methyl methacrylate-cobalt oxide and p-methylstyrene-diallyl maleate-acrylate-manganese oxide; the high-density matrix is ​​a medium-density or high-density ceramsite proppant.

[0029] Compared with the prior art, the present invention has the following benefits:

[0030] The present invention adjusts the viscosity of the fracturing fluid according to the changes in construction parameters and construction requirements at each stage of fracturing to meet the requirements of liquid joint formation and sand carrying at different fracturing stages. Fracturing fluids with different viscosities play corresponding roles, achieving the effect of controlling viscosity, joint formation and sand addition, thereby improving the fracturing joint formation effect and sand addition strength.

[0031] The main body of the present invention adopts large-size proppant to fill and support the main fracture, cleat and secondary fracture, and adopts viscoelastic fracturing fluid and superimposed high-displacement construction to achieve long-distance transportation and effective support of the proppant, thereby improving the conductivity of the supporting filling layer;

[0032] According to the coal seam characteristics and crack opening rules, the present invention optimizes the design of shielding temporary plugging and diverting measures, increases the reservoir stress difference in the early stage of sand addition, prevents the cracks from excessively extending to the dominant seams, and promotes the complexity of crack extension;

[0033] The present invention uses medium-low viscosity fracturing fluid to carry proppant, shortens proppant migration distance and sedimentation time, and after stopping the pump, the proppant settles in the near-well advantage fracture and lays to form a shielding belt. After restarting the pump, the stress difference and pressure release generated are offset, realizing the first diversion of the fracture and promoting the complexity of fracture extension.

[0034] The invention adds diverting sand in the middle of fracturing, which can temporarily block the cracks through expansion, self-bridging, aggregation and other effects under the conditions of formation temperature and pressure, realize the second diversion of the cracks, promote the uniform opening and extension of the cracks, and improve the effect of the crack tip;

[0035] The present invention specifically designs the up / down turning sand, which sinks or floats in the fracture by using the difference in density, temporarily blocks the fracture by expansion, self-bridging and aggregation, realizes the downward or upward turning of the fracture, promotes the uniform opening and extension of the fracture, and improves the effect of the fracture tip; secondly, the turning agent is hydrophobically modified and the aggregation is controlled by Zeta potential instead of cementation, which does not affect the relative permeability of the filling layer;

[0036] The present invention is based on a full understanding of coal and rock characteristics, combined with the technical requirements of volume fracturing process to carry out combined measure selection and performance and parameter control. The proposed measures of controlled adhesion, fracture creation and sand increase, shielding temporary plugging and diversion, diverting sand temporary plugging and large-size filling support all have unique effects, and the combination of measures can achieve the effect of 1+1+1+1>>4. BRIEF DESCRIPTION OF THE DRAWINGS

[0037] Figure 1 A construction flow chart of the temporary plugging and diversion and large-grain sand fracturing method for deep coal rock reservoirs provided by the present invention;

[0038] Figure 2 It is the construction parameter control chart;

[0039] Figure 3A comparison diagram of the effect of microseismic monitoring of rupture points in the temporary plugging construction section during the temporary plugging diversion and large-size sand fracturing of deep coal and rock reservoirs provided by the present invention;

[0040] Figure 4 A microseismic monitoring rupture point response diagram of a deep coal rock reservoir temporary plugging diversion and large-size sand fracturing construction diversion sand temporary plugging before and after provided by the present invention;

[0041] Figure 5 The curve of the flow conductivity of the supporting filling layer with different particle size combinations provided by the present invention changing with the closing pressure;

[0042] Figure 6 This is a construction curve diagram of the temporary plugging and diversion and large-grain sand fracturing method for deep coal rock reservoirs provided by the present invention in a deep coal rock gas well. DETAILED DESCRIPTION

[0043] The present invention will be further described below by specific examples. However, it should be understood that the following examples are only used to further illustrate the present invention, but not to limit the present invention.

[0044] The sand ratios in the following examples are all volume sand ratios.

[0045] A temporary plugging and diversion, large-grain sand fracturing method for deep coal rock reservoirs, comprising the following steps:

[0046] S1, the first pre-fluid to create the main fracture: use high viscosity fracturing fluid at the first displacement to open the coal rock cleat, create the main fracture to connect the near-wellbore zone;

[0047] S2, the first sand-carrying fluid is used to lay the shielding belt: medium-low viscosity fracturing fluid is used to carry 40 / 70 mesh proppant into the formation at the first stage sand ratio at the second displacement, and the stage proppant dosage is W1 square, to grind and fill the cracks, further open the cleats and fissures, and lay proppant in the high permeability dominant fractures near the wellbore to form a shielding belt;

[0048] S3, stop and start the pump midway: stop the pump for 60 minutes to 120 minutes and then start the pump again to complete temporary shielding and the first diversion of the crack;

[0049] S4, second pre-fluid communication with the far end: use high viscosity fracturing fluid to open the coal seam again at the second displacement to form a long main fracture, create new fractures and more branch fractures and communicate with the far end;

[0050] S5, second sand-carrying fluid extension fracture network: medium viscosity fracturing fluid is used to carry 40 / 70 mesh proppant into the formation at the second displacement with the second stage sand ratio, and the stage proppant dosage is W2 cubic meters, so that the complex fracture network is continuously extended, and the proppant is filled in the micro fractures and secondary fractures;

[0051] S6, the third sand-carrying fluid plus diverting sand: use medium-low viscosity fracturing fluid to carry diverting sand into the formation at the third stage sand ratio at the first displacement, and the amount of diverting sand is W3 cubic meters. The diverting sand expands, self-bridging, and aggregates to change the extension direction of the fracture, thereby achieving secondary diversion of the fracture;

[0052] S7, the fourth sand-carrying fluid fracture network support: use medium-high viscosity fracturing fluid to carry 30 / 50 mesh proppant into the formation at the 4th stage sand ratio at the 2nd displacement, and the stage proppant dosage is W4 square, so that the proppant is gradually supported and filled from the middle end of the fracture to the proximal end, improving the overall filling degree of the fracture network and establishing a complex fracture network of saturated sand that penetrates each other;

[0053] S8, stop sand and replace to end construction: after stopping sand, use medium-high viscosity fracturing fluid + low viscosity fracturing fluid to replace to the designed replacement volume, then stop pumping to end construction;

[0054] During the implementation of the above steps, the construction displacement, construction sand ratio, sand addition amount and fracturing fluid performance and other parameters are precisely controlled to achieve the construction effect required at each stage of fracturing construction, bringing about the improvement of the overall effect of fracturing by technology. The fracturing construction parameter control diagram is shown in the figure. Figure 2 The specific instructions are as follows:

[0055] In the S1 stage, high viscosity fracturing fluid (apparent viscosity 39mPa·s~48mPa·s) is used in the first construction displacement (12m 3 / min≤Q1<16m 3 / min) to create the main seam, the design ideas and basis are reflected in three aspects:

[0056] (1) The need for coal seam fracturing to control fracture height and maintain effective fracture length: Different reservoir fracturing transformations have different requirements for fracturing fluid viscosity. Shale volume fracturing focuses on low-viscosity slickwater (apparent viscosity 3mPa·s~5mPa·s) to create long and complex fractures, while tight sandstone volume fracturing focuses on high-viscosity fluid (apparent viscosity above 60mPa·s) to create short and wide fractures. Unlike shale gas reservoirs and tight sandstone gas reservoirs, coal reservoirs have low compressive strength, well-developed cleats, and coal seam thickness. Due to its thinness, only appropriate viscosity of fracturing fluid is needed to open the coal seam cleats and initiate cracking to form a wider seam. The principle of selecting fracturing fluid is low viscosity and high elasticity (the apparent viscosity of high viscosity fracturing fluid is 39mPa·s~48mPa·s to meet the requirements, and the fracture length is moderate). In addition, the fracture height increases with the increase of displacement and the viscosity of fracturing fluid. Therefore, when using high viscosity fracturing fluid, appropriately reducing the construction displacement is conducive to controlling the fracture height and preventing the layer from being channeled during fracturing, which increases the construction difficulty.

[0057] (2) Control the need for large-scale coal powder generation as much as possible and reasonably reduce the construction displacement: Coal rock is very easy to break under high displacement, generating a large amount of coal powder and coal debris of different sizes. During the pre-fluid fracture formation stage, coal powder gathers and blocks the front edge of the fracture, causing the pressure in the fracture to increase instantly and force the fracture extension direction to change. At the same time, the fracture blockage can increase the fracture static pressure (or surface pump pressure);

[0058] (3) The construction displacement should be appropriately controlled to control the need for friction control: Under the same displacement, the friction of high-viscosity fracturing fluid (apparent viscosity 39mPa·s~48mPa·s) is 3~5MPa higher than that of medium-viscosity fracturing fluid (apparent viscosity 15mPa·s~24mPa·s). In this stage, high-viscosity fracturing fluid must be used, and the construction pressure is high when the cracks are not developed and expanded. Therefore, the construction displacement should be appropriately controlled to keep the overall construction pressure within a certain range.

[0059] In the S2 stage, medium-low viscosity fracturing fluid (apparent viscosity 9mPa·s to 12mPa·s) is used in the second displacement (16m 3 / min≤Q2≤25m 3 / min) with the first stage sand ratio (8%-16%) carrying 40 / 70 mesh proppant into the formation, the stage proppant dosage is W1 cubic meter (10-12 parts of 100 parts of total volume of sand), to complete the grinding of cracks, opening of cleats and fissures, and forming a shielding belt for high permeability dominant seams. The design basis and ideas are as follows:

[0060] (1) The purpose of this stage is to open the cleats and fissures, form a complex fracture network, and properly control the excessive extension of the dominant fractures to promote the uniform opening of each cluster. Therefore, a medium-low viscosity fracturing fluid is selected, which has the ability to penetrate deeply to form a complex fracture network and has a certain sand-carrying capacity to ensure the smooth carrying and migration of the proppant. However, if it does not have a good sand-carrying capacity, it will settle rapidly in the near-well zone and form a shielding zone, laying the foundation for shielding temporary plugging and diversion;

[0061] (2) High displacement causes high pressure in the fracture, thus forming wide fractures, which is the key to coal rock sanding. Therefore, when using medium and low viscosity fracturing fluids, the rent reduction performance is guaranteed, and appropriately increasing the construction displacement is more conducive to coal rock gas fracturing.

[0062] During the S3 stage, the pump is stopped for 60 to 120 minutes to allow the pressure to diffuse and the fractures to be basically closed. After the pump is restarted, the shielding belt set in the S2 stage will increase the original stress parameters, prompting the unopened perforation clusters or fractures to open first, achieving the first diversion of the fractures and complicating the fracture extension.

[0063] In the S4 stage, high viscosity fracturing fluid (apparent viscosity 39mPa·s~48mPa·s) is used in the second displacement (16m 3 / min≤Q2≤25m3 / min) to form a long main fracture in the coal seam, create new fractures and more branch fractures and communicate with the far end. The design ideas and basis are as follows: when the complex fracture network has been initially formed by fracturing, the high-viscosity fracturing fluid is used to create fractures again. The construction pressure will be significantly lower than that in the S1 stage, so the construction displacement can be relatively increased to obtain better fracture creation and communication with the far end effect.

[0064] In the S5 stage, medium viscosity fracturing fluid (apparent viscosity 15mPa·s~24mPa·s) is used in the second displacement (16m 3 / min≤Q2≤25m 3 / min) and the second stage sand ratio (13%-22%) is used to carry 40 / 70 mesh proppant into the formation. The stage proppant dosage is W2 cubic meters (35-45 parts of the total volume of sand in 100 parts). The design ideas and basis are as follows: while the complex fracture network is formed, the viscosity is controlled and the sand is increased (it is necessary to ensure the drag reduction performance of the fracturing fluid, the ability to open the cleats and extend the complex fracture network, and the good carrying capacity of the 40 / 70 proppant). Therefore, the medium viscosity fracturing fluid is optimized for continuous sand addition to continuously extend the complex fracture network, and the proppant is filled in the micro fractures and secondary fractures, and then opened and filled again.

[0065] In the S6 stage, medium-low viscosity fracturing fluid (apparent viscosity 9mPa·s to 12mPa·s) is used in the first displacement (12m 3 / min≤Q1<16m 3 / min) and carry the steering sand into the formation at the third stage sand ratio (16%-18%), the amount of steering sand is W3 cubic meters (10-13 parts of the total volume of sand in 100 parts). The design ideas and basis are as follows: appropriately reduce the construction displacement and the steering sand ratio, use medium and low viscosity fracturing fluid to carry the steering sand to the far end of the dominant fracture (limiting the sand carrying capacity of the fracturing fluid, it is difficult for the steering sand to enter the non-dominant fracture), use the different densities of the steering sand to sink or float in the fracture, and temporarily block the fracture end through the expansion, self-bridging and aggregation of the steering sand, so as to achieve downward or upward diversion of the fracture and improve the effect of the fracture tip.

[0066] In the S7 stage, medium-high viscosity fracturing fluid (apparent viscosity 27mPa·s to 36mPa·s) is used in the second displacement (16m 3 / min≤Q2≤25m 3 / min) with a 4th stage sand ratio (20%-24%) carrying 30 / 50 mesh proppant into the formation, the stage proppant dosage is W4 cubic meters (35-40 parts of 100 parts of total volume of sand). The design ideas and basis are as follows:

[0067] (1) In this stage, 30 / 50 proppant is added, and the construction sand ratio is further increased. Therefore, the viscosity of the fracturing fluid is increased, and medium-high viscosity fracturing fluid is used to carry sand, which reduces the proppant sedimentation rate and increases the migration distance. High displacement is superimposed, so that the proppant is gradually supported and filled from the middle end of the fracture to the proximal end, improving the overall filling degree of the fracture network and establishing a complex fracture network of saturated sand that penetrates each other;

[0068] (2) Compared with the early construction parameters of deep shale gas fracturing, the maximum sand ratio of construction sand was increased from 22% to 24% by increasing the displacement and the viscosity of the fracturing fluid, and the main sand ratio was increased from 18%-20% to 20%-22%, thereby improving the conductivity of the propped fracture.

[0069] Example 1

[0070] Preparation of fracturing fluids with different viscosities: The deep coalbed methane high-efficiency variable viscosity fracturing fluid provided by Sichuan Shenhe New Material Technology Co., Ltd. with patent ZL202310189969.7 was used, and the variable viscosity scheme was adjusted, including low viscosity fracturing fluid with an apparent viscosity of 6mPa·s, medium-low viscosity fracturing fluid with an apparent viscosity of 12mPa·s, medium viscosity fracturing fluid with an apparent viscosity of 24mPa·s, medium-high viscosity fracturing fluid with an apparent viscosity of 36mPa·s and high viscosity fracturing fluid with an apparent viscosity of 48mPa·s.

[0071] Preparation of turning sand: Resin (diphenylmethane diisocyanate (MDI) and polymethyl methacrylate in a mass ratio of 2:1), hydrophobic modifier (fluorinated polysiloxane), and Zeta potential regulator (5-(4-methoxyphenyl) pyrimidine-2-amine) were mixed in a mass ratio of 97:1:2, and then coated with styrene-N,N'-methylenebisacrylamide-methyl methacrylate-cobalt oxide polymer microspheres and medium-density ceramsite proppants, and then aged and sieved to prepare upper turning sand and lower turning sand; the density of the upper turning sand is 1.65g / cm 3 , the density of lower turning sand is 1.02g / cm 3 When the steering sand is temporarily blocked, the upper steering sand and the lower steering sand are mixed in a volume ratio of 1:1.

[0072] The specific implementation includes the following steps:

[0073] S1: Use high viscosity fracturing fluid (apparent viscosity 48mPa·s) in the first operation displacement (15m 3 / min) to create the main seam;

[0074] S2: Use medium-low viscosity fracturing fluid (apparent viscosity 12mPa·s) in the second displacement (20m 3 / min) with the first stage sand ratio (8%-16%, step-by-step increase of 2%), carrying 40 / 70 mesh proppant into the formation, the stage proppant dosage is W1 cubic meter (10 parts of the total volume of sand of 100 parts), completing the grinding of cracks, opening cleats and fissures, and forming a shielding belt for high permeability dominant seams;

[0075] S3: Stop the pump for 60 minutes to allow the pressure to diffuse and the fractures to close. After restarting the pump, the unopened perforation clusters or fractures are opened first, achieving the first diversion of the fractures and making the fracture extension more complicated.

[0076] S4: Use high viscosity fracturing fluid (apparent viscosity 42mPa·s) in the second displacement (20m 3 / min) to open the coal seam again to form a long main seam, create new seams and more branch seams and connect the far end;

[0077] S5: Use medium viscosity fracturing fluid (apparent viscosity 24mPa·s) in the second displacement (20m 3 / min) with the second stage sand ratio (13%-22%, step-by-step increase of 3%), carrying 40 / 70 mesh proppant into the formation, the stage proppant dosage is W2 cubic (40 parts of 100 parts of total volume sand), so that the complex fracture network continues to extend, the proppant is filled in the micro fractures and secondary fractures, and then pressed open and filled again;

[0078] S6: Use medium-low viscosity fracturing fluid (apparent viscosity 12mPa·s) in the first displacement (15m 3 / min) with the third stage sand ratio (16%-18%, with a step increase of 2%), the amount of diverting sand is W3 cubic meters (10 parts of the total volume of sand in 100 parts), and the diverting sand sinks or floats in the fracture by using the different densities, and the diverting sand expands, self-bridges and aggregates to temporarily block the fracture ends, thereby achieving downward or upward diversion of the fractures and improving the effect of the fracture tip;

[0079] S7: Use medium-high viscosity fracturing fluid (apparent viscosity 36mPa·s) in the second displacement (20m 3 / min) with the 4th stage sand ratio (20%-24%, stepwise increase of 2%), carrying 30 / 50 mesh proppant into the formation, the stage proppant dosage is W4 cubic (40 parts of 100 parts of total volume of sand), so that the proppant is gradually supported and filled from the middle end of the fracture to the proximal end, improving the overall filling degree of the fracture network, and establishing a complex fracture network of saturated sand that penetrates each other;

[0080] S8: After stopping the sanding, use medium-high viscosity fracturing fluid (apparent viscosity 36mPa·s) + low viscosity fracturing fluid (apparent viscosity 6mPa·s) to replace to the designed displacement volume, then stop the pump and end the construction.

[0081] Example 2

[0082] Optimization design of measures such as controlled adhesion, joint creation and sand addition, shielding temporary plugging and diversion, diversion sand temporary plugging and large-size filling support:

[0083] 1. Matching of performance and process parameters of high-efficiency variable viscosity fracturing fluid for deep coalbed methane:

[0084] In order to better illustrate the technical effect of the present invention, the following will provide the corresponding performance evaluation of the fracturing fluid and the comparison of the construction parameters. The drag reduction performance and sand carrying performance of fracturing fluids with different viscosities were tested, and the results are shown in Table 1.

[0085] Table 1 Performance test results of different types of fracturing fluids

[0086]

[0087] From the data in Table 1, it can be seen that with the increase of apparent viscosity of fracturing fluid, the construction friction resistance increases more and more obviously, and the sand carrying performance of fracturing fluid also increases more obviously. For volume fracturing construction with large displacement and large amount of sand, the friction resistance of fracturing fluid is the focus of attention, followed by the sand carrying performance. The analysis results are as follows:

[0088] (1) To meet the requirements of high-intensity sand addition, medium-viscosity fracturing fluid has a good carrying capacity for 40 / 70 (complete sedimentation for more than 2 minutes), while for 30 / 50 proppant, to meet similar indicators, medium-high viscosity fracturing fluid is required;

[0089] (2) When high viscosity fracturing fluid is used to create fractures in the S1 stage, the 3 / min, the construction friction resistance is also better than that of other fracturing fluids at 20m 3 / min, the construction friction is high, so the construction displacement in the S1 stage should be properly controlled.

[0090] The fracturing of different types of fracturing fluids was simulated, and the results are shown in Table 2.

[0091] Table 2 Fracture simulation results of different types of fracturing fluids (liquid volume 3000m 3 , displacement 20m 3 / min)

[0092]

[0093]

[0094] It can be seen from the simulation results that the lower the viscosity of the fracturing fluid, the more conducive it is to creating long fractures and controlling fracture height. For deep coal rock reservoirs, the thickness of the coal seam is generally less than 20m, and the main reservoir is about 15m. Therefore, the fracturing fluid selected by the process technology provided by the present invention is mainly medium-low viscosity, medium viscosity, medium-high viscosity and high viscosity.

[0095] 2. Monitoring of the effect of shielding temporary blocking and steering measures:

[0096] In the construction of a deep coal-rock gas horizontal well, the method of temporary plugging and diverting of coal-rock gas and adding large-size sand was used. The microseismic technology was used to monitor the rupture point during the fracturing process for two sections where temporary plugging and diverting measures were not implemented and where temporary plugging and diverting measures were implemented. The monitoring results of the first half of the fracturing (half the amount of sand added) were compared. Figure 3 shown.

[0097] From the comparison results, it can be seen that in the construction section where shielding, temporary plugging and diversion measures were not implemented, the cracks started and extended mainly in one direction in the first half of the construction, the dominant fractures in a single direction were too prominent, and the overall fracture network was uneven. In the construction section where shielding, temporary plugging and diversion measures were implemented, the fracture network extension degree on both sides of the well section was similar, and the overall fracture network was uniform.

[0098] 3. Monitoring of the effect of temporary plugging measures of diverting sand:

[0099] The coal-rock gas temporary plugging and diversion and large-size sand fracturing method provided by the present invention was used in the construction of a deep coal-rock gas horizontal well. The microseismic technology was used to monitor the rupture points during the whole fracturing process. The monitoring results are shown in Figure 4 shown.

[0100] The figure clearly shows that before the temporary plugging by the steering sand, the fracture point response was less close to the wellbore and more far from the wellbore, the crack expansion trend was more obvious, but the density of the fracture network was very low; after the temporary plugging by the steering sand, after the steering sand blocked the dominant fracture, there was basically no response of the fracture point farther away, the trend of the fracture expansion stopped, the fracture points increased on the original basis, and the fracture network continued to be denser, indicating that temporary plugging and diversion have been achieved, opening new fluid inlet channels and new fractures. Therefore, it can intuitively reflect the effect of the temporary plugging measure of the steering sand, which not only promotes the complexity of the fracture network, but also inhibits the occurrence of the fracture tip effect.

[0101] 4. Fracture simulation and conductivity test of large-size filling support

[0102] According to the high-viscosity fracturing fluid and medium-viscosity fracturing fluid used in the present invention, the following proppant combinations were simulated using FracPT to test the average crack width of the fracturing cracks, and the fracturing acidification fracture conductivity tester was used to test different combinations (sand concentration 20 kg / m 2 )Flow conductivity at different closing pressures (results see Figure 5 The effect comparison is shown in Table 3:

[0103] Table 3 Comparison of the effects of different proppant combinations

[0104]

[0105] From Table 2, it can be seen that the average width of the fracture simulated by the sand addition combination scheme 5 is 0.42 cm, and the fracture conductivity can reach 223 μm under the closing pressure of 40 MPa (the fitting closing pressure of the deep 8# coal at 2300 m is about 40 MPa). 2 cm, compared with the proppant combination used in the early stage, the fracture width and conductivity have been improved to a certain extent. However, if the proportion of large-size proppant is further increased, the conductivity will not be improved much, and the difficulty of adding sand will increase. Therefore, the large-size filling support measures of combination scheme 5 are determined, and can be optimized and adjusted within a certain range.

[0106] Application Examples

[0107] In the eastern structure of the Yishan slope in the Ordos Basin, the Jishen 13-*A Ping 02 well entered the 8# coal seam at a top depth of 2,330m, the drilling depth was 3,631m, the horizontal section footage was 1,301m, the coal seam cumulatively was 1,301m, and the coal seam drilling rate was 100%. Combined with the understanding of seismic structure, the horizontal section of the Jishen 13-*A Ping 02 well is located above the north-south positive microstructure, the overall thickness of the 8# coal seam is 8.6-12.7m, and it is divided into 8-1# coal seam, 8-2# coal seam, and 8-3# coal seam, among which 8-2# coal seam and 8-3# coal seam are mostly bright coal and semi-bright coal. The main difficulties in the early stage of fracturing transformation are: the complexity of the fracturing crack network is not enough, and the transformation volume is limited; the coal seam is relatively thin, and the crack height is easy to get out of control and penetrate the top and bottom layers, causing construction abnormalities and difficulty in adding sand; in the early stage, a combination of 200 mesh, 100 mesh, 40 / 70 mesh, and 30 / 50 mesh proppants were used to add sand. After fracturing, the conductivity of the propped cracks was insufficient and the gas production was low.

[0108] In order to realize the efficient utilization of coal-rock gas energy storage in this well, the well was divided into 16 sections with an average section length of 81m. φ114 casing was used for extreme volume fracturing transformation, and the designed construction displacement was 14m 3 / min~20m 3 / min, sand adding strength 4.5m 3 / m~5.0m 3 / m, liquid strength 30m 3 / m~35m 3 / m. The technology provided by the present invention was applied to carry out deep coal-rock gas temporary plugging and diversion, large-size sand fracturing tests. No 100-mesh sand was used. The main body adopted shielding temporary plugging and diversion, diversion sand temporary plugging, controlled adhesion and seam-making and sand-increasing measures, and superimposed high displacement to achieve large-size filling support effect, promote uniform extension of the seam network, increase the complexity of the fractures, and enhance the conductivity of the support filling layer, thereby increasing the coal-rock gas production. The design of the first stage of the well construction pumping program is shown in Table 4.

[0109] Table 4 Pumping procedure for the first stage of fracturing construction in Jishen 13-*A Ping 02

[0110]

[0111]

[0112] The construction is carried out according to the above pumping procedure. The fracturing construction curve is shown in Figure 6 As shown, it can be seen that the maximum construction displacement reaches 20m 3 / min, the sand-sand ratio is up to 24%, the overall construction pressure is stable, the construction is smooth, and the fracturing construction is not difficult through the matching of the technology and process of the present invention. It can be seen from the curve that after the shielding temporary plugging and diversion measures, under the same displacement, the construction pressure after the second pump start-up is 4.8MPa higher than that before the pump is stopped. The increase in construction pressure is more conducive to the initiation and expansion of perforation clusters or cracks with larger stress differences, and realizes crack diversion; similarly, during the implementation of diversion sand temporary plugging, the construction pressure continues to rise, and when the displacement is restored to the same as before the diversion sand temporary plugging, the construction pressure rises by 2MPa, which is conducive to the opening of new cracks and promotes the complexity of cracks.

[0113] The above description is only a preferred embodiment of the present invention and does not limit the present invention in any form. Although the present invention has been disclosed as a preferred embodiment as above, it is not used to limit the present invention. Any technician familiar with this profession can make some changes or modify the technical contents disclosed above into equivalent embodiments without departing from the scope of the technical solution of the present invention. However, any simple modification, equivalent change and modification made to the above embodiments according to the technical essence of the present invention without departing from the content of the technical solution of the present invention still fall within the scope of the technical solution of the present invention.

Claims

1. A temporary plugging and diversion, large-grained sand fracturing method for deep coal reservoirs, characterized in that: The volume fracturing of coal-rock gas is completed by a combination of measures including controlled adhesion, fracture creation and sand enhancement, shielding temporary plugging and diversion, diversion sand temporary plugging and large-size filling support, including the following steps: S1, using high viscosity fracturing fluid at the first displacement to open the coal rock cleat and create the main fracture to connect the near-wellbore zone; S2, using medium-low viscosity fracturing fluid at the second displacement with the first stage sand ratio to carry 40 / 70 mesh proppant into the formation, the stage proppant dosage is W1 square, grinding and filling the cracks, further opening the cleats and fissures, and laying proppant in the high permeability dominant fractures near the wellbore to form a shielding belt; S3, stop the pump for 60 minutes to 120 minutes and then restart the pump to complete temporary shielding and the first diversion of the crack; S4, use high viscosity fracturing fluid to open the coal seam again at the second displacement to form a long main fracture, create new fractures and more branch fractures and connect the far end; S5. Use medium viscosity fracturing fluid to carry 40 / 70 mesh proppant into the formation at the second displacement with the second stage sand ratio, and the stage proppant dosage is W2 square, so that the complex fracture network continues to extend, and the proppant is filled in the micro fractures and secondary fractures; S6. Use medium-low viscosity fracturing fluid to carry diverting sand into the formation at the third stage sand ratio at the first displacement, and the amount of diverting sand is W3 cubic meters. The diverting sand expands, self-bridging, and aggregates to change the extension direction of the fracture, thereby achieving secondary diversion of the fracture; S7, using medium-high viscosity fracturing fluid at the second displacement with the fourth stage sand ratio to carry 30 / 50 mesh proppant into the formation, the stage proppant dosage is W4 square, so that the proppant is gradually supported and filled from the middle end of the fracture to the proximal end, improving the overall filling degree of the fracture network, and establishing a complex fracture network of saturated sand that penetrates each other; S8. After stopping the sand pumping, use medium-high viscosity fracturing fluid + low viscosity fracturing fluid to replace the designed displacement volume, then stop the pump and end the construction; The apparent viscosities of the high-viscosity fracturing fluid, medium-high-viscosity fracturing fluid, medium-viscosity fracturing fluid, medium- and low-viscosity fracturing fluid are 39-48 mPa·s, 27-36 mPa·s, 15-24 mPa·s, 9-12 mPa·s and 3-6 mPa·s respectively.

2. A temporary plugging and diversion, large-grain sand fracturing method for deep coal reservoirs as claimed in claim 1, characterized in that: The first displacement range is 12 to 16 m 3 / min; the second displacement value range is 16~25m 3 / min.

3. A temporary plugging and diversion, large-grain sand fracturing method for deep coal reservoirs as claimed in claim 1, characterized in that: In the first stage, the sand ratio increases in steps from 8% to 16%, with each step being 2%; in the second stage, the sand ratio increases in steps from 13% to 22%, with each step being 3%; in the third stage, the sand ratio increases in steps from 16% to 18%, with each step being 2%; in the fourth stage, the sand ratio increases in steps from 20% to 24%, with each step being 2%.

4. A temporary plugging and diversion, large-grain sand fracturing method for deep coal reservoirs as claimed in claim 1, characterized in that: The control principle of the total amount of sand added W in a single stage during fracturing is: W = (4-5) * D, where D is the segment length; Taking the total amount of sand added in a single stage as 100 parts, W1 accounts for 10 to 12 parts, W2 accounts for 35 to 45 parts, W3 accounts for 10 to 13 parts, and W4 accounts for 35 to 40 parts.

5. A temporary plugging and diversion, large-grain sand fracturing method for deep coal rock reservoirs as claimed in claim 1, characterized in that: The turning sand is a micro-expansion coating material, which is prepared by coating a matrix with a mixture of resin, hydrophobic modifier, and Zeta potential regulator, aging, and screening; the matrix particle size range is 0.104mm-0.425mm; the turning sand includes upper turning sand and lower turning sand with a volume ratio of 1:

1. When a low-density matrix is ​​selected, the lower turning sand is obtained, and the density is 0.95-1.05g / cm 3 When a high-density matrix is ​​selected, the upper turning sand is obtained, with a density of 1.6 to 1.85 g / cm 3 .

6. A temporary plugging and diversion, large-grain sand fracturing method for deep coal reservoirs as claimed in claim 5, characterized in that: The mass ratio of resin, hydrophobic modifier and Zeta potential regulator is 97:1:

2.

7. A temporary plugging and diversion, large-grain sand fracturing method for deep coal reservoirs as claimed in claim 5, characterized in that: The resin is a combination of any one of diphenylmethane diisocyanate and toluene diisocyanate and any one of polyacrylic resin, polymethyl methacrylate, phenolic resin, polyamide-imide resin and polylactic acid ester in a mass ratio of 2:1 to 3:

1.

8. A temporary plugging and diversion, large-grain sand fracturing method for deep coal reservoirs as claimed in claim 5, characterized in that: The hydrophobic modifier is one of hydrophobic nano-silica, dimethylpolysiloxane, fluorinated polysiloxane and zinc stearate.

9. A temporary plugging and diversion, large-grain sand fracturing method for deep coal reservoirs as claimed in claim 5, characterized in that: The zeta potential regulator is one of 3-(2-methylpyrimidine)aniline, 5-(4-methoxyphenyl)pyrimidine-2-amine, 5-ethylpyrimidine-2-amine, a 2-aminopyrimidine-dodecylmethyldihydroxyethylammonium bromide mixture with a mass ratio of 1:6 to 1:10, and a 2-aminopyrimidine-chloroethyltrimethylammonium chloride mixture with a mass ratio of 1:8 to 1:

10.

10. A temporary plugging and diversion, large-grain sand fracturing method for deep coal reservoirs as claimed in claim 5, characterized in that: The low-density matrix is ​​one of nut shell particles and high-strength polymer microspheres; the high-density matrix is ​​a medium-density or high-density ceramsite proppant.

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