A temporary plugging and diversion, large particle size sand fracturing method for deep coal and rock reservoirs

Abstract

The invention discloses a temporary plugging and diversion, large-particle-size sand fracturing method for deep coal-rock reservoirs, including measures such as viscosity control, fracture creation, sand addition, shielding temporary plugging and diversion, temporary plugging of diversion sand, and large-particle-size filling and support. The method comprises the following steps: using a high-viscosity fluid to create main fractures and open cleats; switching to medium-low viscosity fluids and continuously adding 40 / 70 mesh proppants to fill the near-wellbore cleats and form a shielding zone; achieving the first diversion of the fracture by stopping and restarting the pump; using a high-viscosity fluid to open the distal cleats and form more main fractures; using medium-high viscosity fluids to carry 40 / 70 mesh proppants to expand secondary fractures and microfractures; using medium-viscosity fluids to carry diversion sand for in-fracture temporary plugging to achieve the second diversion of the fracture and facilitate fracture network complexity; and using medium-high viscosity fluids to carry 30 / 50 mesh proppants to achieve multi-scale effective support for the complex fracture network. The invention can significantly increase the fracturing reformed volume and fracture complexity of coal-rock, improve the conductivity of the supported fractures, increase the measured production, and extend the stable production period.

Description

Technical Field

[0001] The present invention relates to the technical field of fracturing stimulation for deep coal-rock reservoirs, and particularly relates to a method for temporary plugging diversion and large-particle-size sand fracturing of deep coal-rock reservoirs. Background Art

[0002] Deep coal-bed methane has become another unconventional gas reservoir with great development potential after shale gas. The large-scale extreme volume fracturing of the first deep coal-bed methane horizontal well Jishen 6-7 Ping 01 in China was successfully implemented and achieved a production breakthrough of 100,000 m³ / day, kicking off the development of deep coal-bed methane in China. The extreme volume fracturing technology is an effective means to obtain high-yield industrial gas flow from deep coal-bed methane. This technology optimizes the combination of "construction technology + construction scale, parameters + fracturing fluid, proppant plan" to fully transform the coal-rock and improve the production of coal-bed methane.

[0003] The displacement of coal-rock gas accumulation fracturing construction is increasing continuously, from the previous 12 - 16 m 3 / min to the current 18 - 24 m 3 / min. The high displacement will inevitably cause high pressure in the fracture, thus making the coal-rock form wider fractures, which is more conducive to the entry of proppants. And affected by the relatively soft coal-rock, the smaller the proppant particle size, the easier it is to embed and cause the reduction of conductivity. Therefore, under the condition that the construction conditions permit and the coal-rock characteristics require, the use of 200-mesh sand and 100-mesh sand will instead reduce the fracturing transformation effect. Therefore, the large-particle-size filling and supporting measures have more potential, and targeted optimization of the fracturing fluid system and measures for viscosity control, fracture creation, and sand addition are required. Secondly, similar to shale fracturing transformation, reasonable temporary plugging diversion measures are an effective means to form a uniform and complex fracture network in coal-rock. However, the coal-rock characteristics are different from shale. There are many natural cleat fractures and serious filtration loss. The initial fracture trend tends to the high-permeability layer, which is extremely easy to cause uneven fracture network development. It is necessary to reasonably optimize the temporary plugging diversion agent (sand), implementation process, parameters, etc. In short, with the in-depth understanding of coal-rock characteristics, fracture network fracturing, and temporary plugging diversion fracturing technology, it is urgent to conduct targeted research on process conditions, parameters, measure optimization, and technology upgrading to form unique processes and technologies for coal-bed methane fracturing, fully "break up" the coal seam, promote the formation of a uniform and super-dense volume fracture network in the entire well section of the coal-bed methane horizontal well, and effectively support the sand-filled fracture network to promote the efficient diffusion-seepage of coal-bed methane and achieve another breakthrough in the development of coal-bed methane. Summary of the Invention

[0004] In view of the above-mentioned difficulties, the present invention proposes a temporary plugging diversion and large particle size sand addition fracturing method for deep coal-rock reservoirs. The present invention makes full use of the special advantages of high-efficiency variable-viscosity fracturing fluid for deep coalbed methane and upper / lower diversion sand, controls the performance and parameters at different fracturing stages, and combines with the volume fracturing process to propose a combined measure of viscosity control for fracture creation and sand addition, shielding temporary plugging diversion, temporary plugging of diversion sand, and large particle size filling and support, which can significantly increase the fracturing transformation volume and fracture complexity of coal-rock, improve the conductivity of the supported fracture, increase the measure production, and extend the stable production period.

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

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

[0007] S1. Creating the main fracture with the first preflush fluid: Using high-viscosity fracturing fluid to open the coal-rock cleats at the first displacement to create the main fracture and communicate with the near-wellbore zone;

[0008] S2. Laying the shielding zone with the first sand-carrying fluid: Using medium-low viscosity fracturing fluid to carry 40 / 70 mesh proppant into the formation at the second displacement with the first stage sand ratio, the stage proppant volume is W1 cubic meters, grinding and filling the fracture, further opening the cleats and fissures, and laying proppant in the high-permeability dominant fracture in the near-wellbore zone to form a shielding zone;

[0009] S3. Stopping and restarting the pump in the middle: Stopping the pump for 60 min to 120 min and then restarting the pump to complete the shielding temporary plugging and the first fracture diversion;

[0010] S4. Communicating with the distal end with the second preflush fluid: Using high-viscosity fracturing fluid to re-fracture the coal seam at the second displacement to create a long main fracture, creating new fractures and more branch fractures and communicating with the distal end;

[0011] S5. Extending the fracture network with the second sand-carrying fluid: Using medium-viscosity fracturing fluid to carry 40 / 70 mesh proppant into the formation at the second displacement with the second stage sand ratio, the stage proppant volume is W2 cubic meters, making the complex fracture network continue to extend, and the proppant fills in the microfractures and secondary fractures;

[0012] S6. Adding diversion sand with the third sand-carrying fluid: Using medium-low viscosity fracturing fluid to carry diversion sand into the formation at the first displacement with the third stage sand ratio, the diversion sand volume is W3 cubic meters, and promoting the change of the fracture extension direction through the expansion, self-bridging, aggregation, etc. of the diversion sand to achieve the secondary fracture diversion;

[0013] S7. Supporting the fracture network with the fourth sand-carrying fluid: Using medium-high viscosity fracturing fluid to carry 30 / 50 mesh proppant into the formation at the second displacement with the fourth stage sand ratio, the stage proppant volume is W4 cubic meters, making the proppant gradually support and fill from the middle end to the proximal end of the fracture, improving the overall filling degree of the fracture network, and establishing an interconnected and fully filled sand complex fracture network;

[0014] S8. Stop sand injection and displacement to end the construction: After stopping sand injection, use medium-high viscosity fracturing fluid + low viscosity fracturing fluid to displace until the designed displacement volume is reached, and then stop the pump to end the construction;

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

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

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

[0018] As a specific embodiment of the present invention, the sum of W 1、 W 2、 W 3、 The sum of W4 is the total sand addition volume W for a single stage of a coalbed methane horizontal well, which is determined by the section length D. The control principle is: W = (4 - 5) * D;

[0019] Based on the total volume fraction of W being 100 parts, the proportion of W1 is 10 - 12 parts, the proportion of W2 is 35 - 45 parts, the proportion of W3 is 10 - 13 parts, and the proportion of W4 is 35 - 40 parts.

[0020] As a specific embodiment of the present invention, to ensure the formation of a complex and three-dimensional network fracture network structure and the support of proppants, under the condition of ensuring construction safety, the construction displacement of each stage should be increased as much as possible according to the construction pressure.

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

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

[0023] The steering sand includes upper steering sand and lower steering sand with a volume ratio of 1:1. When a low-density matrix is selected, the lower steering sand is obtained, with a density of 0.95 - 1.05 g / cm 3 , which floats to the top of the fracture with the fracturing fluid during fracturing and forms a low-permeability interlayer to block the upward extension of the fracture, achieving downward fracture steering; when a high-density matrix is selected, the upper steering sand is obtained, with a density of 1.6 - 1.85 g / cm 3 , which sinks to the bottom of the fracture with the fracturing fluid during fracturing and forms a low-permeability interlayer to block the downward extension of the fracture, achieving upward fracture steering.

[0024] As a specific embodiment of the present invention, based on 100 parts by total mass, the combined ratio of resin, hydrophobic modifier, and 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), toluene diisocyanate (TDI) and any one of polyacrylic resin, polymethyl methacrylate, phenolic resin, polyamide-imide (PAI) resin, polylactate, and the combined ratio is 2:1 - 3:1;

[0026] As a specific embodiment of the present invention, the hydrophobic modifier is one of hydrophobic nano-silica, dimethyl polysiloxane, fluorinated polysiloxane, 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)pyrimidin-2-amine, 5-ethylpyrimidin-2-amine, a mixture of 2-aminopyrimidine-dodecylmethyldihydroxyethylammonium bromide (the mass ratio of the two is 1:6 - 1:10), a mixture of 2-aminopyrimidine-chloroethyltrimethylammonium chloride (the mass ratio of the two is 1:8 - 1:10);

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

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

[0030] In view of the changes in construction parameters and requirements at different stages of fracturing, the present invention adjusts the viscosity of the fracturing fluid to meet the requirements of liquid fracture formation and sand carrying in different fracturing stages. Fracturing fluids with different viscosities play corresponding roles, achieving the effects of viscosity control, fracture formation, and sand increase, and improving the fracturing fracture formation effect and sand addition strength.

[0031] The main body of the present invention uses large - particle - size proppants to fill and support the main fractures, cleats, and secondary fractures in fracturing. By using viscoelastic fracturing fluid and superimposing high - displacement construction, long - distance transportation and effective support of proppants are realized, improving the conductivity of the support - filled layer.

[0032] According to the coal seam characteristics and fracture opening laws, the present invention optimizes the design of the shielding temporary plugging and diversion measures. In the early stage of sand addition, the reservoir stress difference is increased to prevent fractures from extending excessively towards the dominant fractures, promoting the complexity of fracture extension.

[0033] The present invention uses medium - and low - viscosity fracturing fluid to carry proppants, shortening the migration distance and settlement time of proppants. After the pump is stopped, the proppants settle and form a shielding zone in the near - well dominant fractures. When the pump is restarted, the stress difference and pressure release occur offset, realizing the first fracture diversion and promoting the complexity of fracture extension.

[0034] The present invention adds diversion sand during the half - way of fracturing, which can temporarily plug the fractures through expansion, self - bridging, aggregation, etc. under the formation temperature and pressure conditions, realizing the second fracture diversion, promoting the uniform opening and extension of fractures, and improving the fracture tip effect.

[0035] The present invention specifically designs upper / lower diversion sand, which floats or sinks in the fracture according to different densities, and temporarily plugs the fractures through expansion, self - bridging, and aggregation, realizing the lower or upper fracture diversion, promoting the uniform opening and extension of fractures, and improving the fracture tip effect. Secondly, the diversion agent is hydrophobically modified and the aggregation is controlled by Zeta potential without cementation, which does not affect the relative permeability of the filled layer.

[0036] Based on a full understanding of the coal - rock characteristics, the present invention selects combined measures and controls their performance and parameters in combination with the technical requirements of volume fracturing technology. The measures of viscosity control, fracture formation, sand increase, shielding temporary plugging and diversion, diversion sand temporary plugging, and large - particle - size filling and support all have unique functions, and the combination of measures can achieve the effect of 1 + 1+1 + 1 >>> 4. Brief Description of the Drawings

[0037] Figure 1 It is the construction flow chart of the temporary plugging and diversion, large - particle - size sand - adding fracturing method for deep coal - rock reservoirs provided by the present invention;

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

[0039] Figure 3It is a comparison diagram of the microseismic monitoring rupture point effect during the temporary plugging diversion and large particle size sand fracturing process of deep coal rock reservoirs provided by the present invention;

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

[0041] Figure 5 It is a curve of the conductivity of different particle size combination support filling layers varying with the closing pressure provided by the present invention;

[0042] Figure 6 It is a construction curve diagram of the temporary plugging diversion and large particle size sand fracturing method for deep coal rock reservoirs provided by the present invention in a certain deep coal rock gas well. Specific embodiments

[0043] The present invention will be further described below through specific embodiments. It should be understood, however, that the following embodiments are only used to further illustrate the present invention and do not limit the present invention.

[0044] The sand ratio in the following embodiments is the volume sand ratio.

[0045] A temporary plugging diversion and large particle size sand fracturing method for deep coal rock reservoirs includes the following steps:

[0046] S1. Creating the main fracture with the first preflush fluid: Using a high-viscosity fracturing fluid to open the coal rock cleats at the first displacement to create a main fracture to communicate with the near-wellbore zone;

[0047] S2. Laying the shielding zone with the first sand-carrying fluid: Using a medium-low viscosity fracturing fluid to carry 40 / 70 mesh proppant into the formation at the second displacement with the first stage sand ratio, the stage proppant volume is W1 cubic meters, to polish and fill the fracture, further open the cleats and fissures, and lay proppant in the high-permeability dominant fracture in the near-wellbore zone to form a shielding zone;

[0048] S3. Stopping and restarting the pump in the middle: Stopping the pump for 60 min to 120 min and then restarting the pump to complete the temporary plugging shielding and the first fracture diversion;

[0049] S4. Communicating with the distal end with the second preflush fluid: Using a high-viscosity fracturing fluid to re-fracture the coal seam at the second displacement to create a long main fracture, create new fractures and more branch fractures to communicate with the distal end;

[0050] S5. Extending the fracture network with the second sand-carrying fluid: Using a medium-viscosity fracturing fluid to carry 40 / 70 mesh proppant into the formation at the second displacement with the second stage sand ratio, the stage proppant volume is W2 cubic meters, to continuously extend the complex fracture network and fill the proppant in the microfractures and secondary fractures;

[0051] S6. Third proppant-carrying fluid plus diversion sand: Use medium- and low-viscosity fracturing fluid to carry diversion sand into the formation at the first displacement rate and the third-stage sand ratio. The volume of diversion sand is W3 cubic meters. Through the expansion, self-bridging, and aggregation of the diversion sand, the direction of fracture extension is changed to achieve secondary fracture diversion.

[0052] S7. Fourth proppant-carrying fluid for fracture network support: Use medium- and high-viscosity fracturing fluid to carry 30 / 50-mesh proppant into the formation at the second displacement rate and the fourth-stage sand ratio. The volume of proppant for this stage is W4 cubic meters. The proppant gradually supports and fills the fracture from the middle to the proximal end, improving the overall filling degree of the fracture network and establishing an interconnected and fully filled complex fracture network.

[0053] S8. Stop adding sand and displace to end the construction: After stopping adding sand, use medium- and high-viscosity fracturing fluid + low-viscosity fracturing fluid to displace until the designed displacement volume is reached, then stop the pump to end the construction.

[0054] During the implementation of the above steps, parameters such as construction displacement rate, construction sand ratio, sand addition volume, and fracturing fluid performance were precisely controlled to achieve the construction effects required for each stage of the fracturing construction, bringing about an improvement in the overall fracturing effect by technology. The fracturing construction parameter control diagram is as Figure 2 shown and is specifically described as follows:

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

[0056] (1) The need for controlling fracture height and maintaining effective fracture length in coal seam fracturing: Different reservoir fracturing treatments have different requirements for the viscosity of fracturing fluid. Shale volume fracturing focuses on creating long and complex fractures with low-viscosity slickwater (apparent viscosity 3 mPa·s to 5 mPa·s), while tight sandstone volume fracturing mainly creates short and wide fractures with high-viscosity fluid (apparent viscosity above 60 mPa·s). Different from shale gas reservoirs and tight sandstone gas reservoirs, coal reservoirs have the characteristics of low compressive strength, well-developed cleats, and relatively thin coal seams. Only fracturing fluid with appropriate viscosity can open the coal cleats and initiate fractures to form relatively wide fracture openings. The selection of fracturing fluid follows the principle of low viscosity and high elasticity (an apparent viscosity of 39 mPa·s to 48 mPa·s for high-viscosity fracturing fluid can meet the requirements, and the fracture length is moderate). Moreover, the fracture height increases with the increase in displacement rate and the increase in fracturing fluid viscosity. Therefore, when using high-viscosity fracturing fluid, appropriately reducing the construction displacement rate is beneficial for controlling fracture height and preventing cross-layer fracturing, which increases the construction difficulty.

[0057] (2) Try to control the need for a large amount of pulverized coal generation and reasonably reduce the construction displacement: Under high displacement, the coal and rock are extremely easy to break, generating a large amount of pulverized coal and coal debris of different sizes. During the stage of creating fractures with the preflush fluid, the accumulated pulverized coal will block the front edge of the fracturing fracture, causing the pressure inside the fracture to increase instantaneously, forcing the fracture extension direction to change. At the same time, the fracture blockage can increase the static pressure of the fracture (or the surface pump pressure).

[0058] (3) Due to the need for friction control, the construction displacement should be appropriately controlled: At the same displacement, the high-viscosity fracturing fluid (apparent viscosity 39 mPa·s - 48 mPa·s) has a friction resistance 3 - 5 MPa higher than that of the medium-viscosity fracturing fluid (apparent viscosity 15 mPa·s - 24 mPa·s). Under the condition that high-viscosity fracturing fluid must be used in this stage and the fracture has not developed or extended, the construction pressure is relatively high. Therefore, the construction displacement should be appropriately controlled to keep the overall construction pressure change small.

[0059] In the S2 stage, a medium-low viscosity fracturing fluid (apparent viscosity 9 mPa·s - 12 mPa·s) is used to carry 40 / 70 mesh proppant into the formation at the second displacement (16 m 3 / min ≤ Q2 ≤ 25 m 3 / min) at the sand ratio of the first stage (8% - 16%). The stage proppant volume is W1 cubic meters (10 - 12 parts out of 100 parts of the total volume of sand). The functions of grinding the fracture, opening the cleats and fissures, and forming a shielding zone for the high-permeability dominant fracture are completed. 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 appropriately control the excessive extension of the dominant fracture to promote the uniform opening of each cluster. Therefore, a medium-low viscosity fracturing fluid is selected, which has the ability to deeply penetrate and create a complex fracture network and certain sand-carrying ability to ensure the smooth transportation of the proppant. However, since it does not have excellent sand-carrying ability, it will quickly settle near the wellbore to form a shielding zone, laying the foundation for shielding and temporary plugging and diversion.

[0061] (2) High displacement is the key to causing high pressure inside the fracture and thus forming a wide fracture for coal and rock sand fracturing. Therefore, when using medium-low viscosity fracturing fluid, with guaranteed reduction performance, appropriately increasing the construction displacement is more conducive to coal and rock gas fracturing.

[0062] In the S3 stage, the pump is stopped for 60 min - 120 min to allow the pressure to diffuse and the fracture to basically close. After restarting the pump, the shielding zone set in the S2 stage will increase the original stress parameters, prompting the unopened perforation clusters or fractures to open preferentially, achieving the first fracture diversion and making the fracture extension more complex.

[0063] In the S4 stage, a high-viscosity fracturing fluid (apparent viscosity 39 mPa·s - 48 mPa·s) is used at the second displacement (16 m 3 / min ≤ Q2 ≤ 25 m3 At a pumping rate lower than the first stage (Q2 < Q1), the coal seam is fractured again to form a long main fracture, creating new fractures and more branched fractures and connecting to the far end. The design concept and basis are as follows: When the complex fracture network has been initially formed, high-viscosity fracturing fluid is used to create fractures again. The construction pressure will be significantly reduced compared to the S1 stage. Therefore, the pumping rate can be relatively increased to obtain better fracture creation and far-end connection effects.

[0064] In the S5 stage, medium-viscosity fracturing fluid (apparent viscosity 15 mPa·s - 24 mPa·s) is used to carry 40 / 70 mesh proppant into the formation at the second pumping rate (16 m 3 / min ≤ Q2 ≤ 25 m 3 / min) with the second-stage sand ratio (13% - 22%). The stage proppant volume is W2 cubic meters (35 - 45 parts out of 100 parts of the total sand volume). The design concept and basis are as follows: While the complex fracture network is being formed, viscosity control and sand addition are carried out (ensuring both the drag reduction performance of the fracturing fluid, the ability to open cleats and extend the complex fracture network, and good carrying capacity for 40 / 70 proppant). Therefore, medium-viscosity fracturing fluid is optimized for continuous sand addition to continuously extend the complex fracture network. The proppant fills the microfractures and secondary fractures, and is fractured and filled again.

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

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

[0067] (1) In this stage, 30 / 50 proppants are added, and the construction sand ratio is further increased. Therefore, the viscosity of the fracturing fluid is increased, medium-high viscosity fracturing fluid is used to carry the proppants, the settlement rate of the proppants is reduced, the migration distance is increased, and high displacement is superimposed, so that the proppants gradually support and fill from the middle end to the proximal end of the fracture, improving the overall filling degree of the fracture network and establishing an interconnected and fully filled complex fracture network with sand;

[0068] (2) Compared with the construction parameters in the early stage of deep shale gas fracturing, through the increase of displacement and the increase of the viscosity of the fracturing fluid, the highest sand ratio in construction sand addition is increased from 22% to 24%, and the main sand addition ratio is increased from 18%-20% to 20%-22%, and the conductivity of the supported fracture is improved.

[0069] Example 1

[0070] Prepare fracturing fluids with different viscosities: Use the high-efficiency variable-viscosity fracturing fluid for deep coalbed methane provided by the patent ZL202310189969.7 of Sichuan Shenhe New Material Technology Co., Ltd., and adjust the variable-viscosity plan, including the apparent viscosity of the low-viscosity fracturing fluid being 6 mPa·s, the apparent viscosity of the medium-low-viscosity fracturing fluid being 12 mPa·s, the apparent viscosity of the medium-viscosity fracturing fluid being 24 mPa·s, the apparent viscosity of the medium-high-viscosity fracturing fluid being 36 mPa·s, and the apparent viscosity of the high-viscosity fracturing fluid being 48 mPa·s.

[0071] Prepare diversion sands: Mix resin (a mixture of diphenylmethane diisocyanate (MDI) and polymethyl methacrylate in a mass ratio of 2:1), hydrophobic modifier (fluorinated polysiloxane), and Zeta potential regulator (5-(4-methoxyphenyl)pyrimidin-2-amine) in a mass ratio of 97:1:2, and then coat styrene-N,N'-methylenebisacrylamide-methyl methacrylate-cobalt oxide polymer microspheres and medium-density ceramic proppants respectively. After aging and screening, upper diversion sand and lower diversion sand are prepared; the density of the upper diversion sand is 1.65 g / cm 3 , and the density of the lower diversion sand is 1.02 g / cm 3 , and when the diversion sands are used for temporary plugging, the upper diversion sand and the lower diversion sand are used in a volume mixing ratio of 1:1.

[0072] During the specific construction, it includes the following steps:

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

[0074] S2: Use medium-low-viscosity fracturing fluid (apparent viscosity 12 mPa·s) at the second displacement (20 m 3Carry 40 / 70 mesh proppant into the formation at the first-stage sand ratio (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, 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(8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (8%-16%, increasing step by step by 2%) at a rate of (for 10 minutes) to complete the functions of grinding the fracture, opening the cleats and fissures, and forming a shielding zone for the high-permeability dominant fractures;

[0075] S3: Stop the pump for 60 minutes to allow the pressure to diffuse and the fracture to basically close. After restarting the pump, promote the preferential opening of the unopened perforation clusters or fractures to achieve the first fracture diversion and make the fracture extension more complex;

[0076] S4: Use a high-viscosity fracturing fluid (apparent viscosity 42 mPa·s) to re-fracture the coal seam at the second displacement (20 m 3 / min) to form a long main fracture, create new fractures and more branch fractures and connect to the distal end;

[0077] S5: Use a medium-viscosity fracturing fluid (apparent viscosity 24 mPa·s) to carry 40 / 70 mesh proppant into the formation at the second displacement (20 m 3 / min) at the second-stage sand ratio (13%-22%, increasing step by step by 3%) to continuously extend the complex fracture network, fill the proppant in the micro-fractures and secondary fractures, and re-fracture and re-fill;

[0078] S6: Use a medium-low-viscosity fracturing fluid (apparent viscosity 12 mPa·s) to carry diversion sand into the formation at the first displacement (15 m 3 / min) at the third-stage sand ratio (16%-18%, increasing step by step by 2%). The amount of diversion sand is W3 cubic meters (10 parts out of 100 parts of the total volume of sand). Utilize the different densities of the diversion sand to float or sink in the fracture, and temporarily block the fracture tip through the swelling, self-bridging and aggregation of the diversion sand to achieve the downward or upward diversion of the fracture and improve the fracture tip effect;

[0079] S7: Use a medium-high-viscosity fracturing fluid (apparent viscosity 36 mPa·s) to carry 30 / 50 mesh proppant into the formation at the second displacement (20 m 3 / min) at the fourth-stage sand ratio (20%-24%, increasing step by step by 2%) to make the proppant gradually support and fill from the middle end to the proximal end of the fracture, improve the overall filling degree of the fracture network, and establish an interconnected complex fracture network filled with sand;

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

[0081] Example 2

[0082] Optimized design of measures such as controlling adhesion, creating fractures and adding sand, shielding and temporarily plugging for diversion, diversion sand temporary plugging, and large particle size filling and supporting:

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

[0084] To better illustrate the technical effects of the present invention, the corresponding performance evaluation of the fracturing fluid and the comparison of construction parameters will be given below. 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 of different types of fracturing fluids

[0086]

[0087] It can be seen from the data in Table 1 that as the apparent viscosity of the fracturing fluid increases, the construction friction increases more and more significantly, and the sand-carrying performance of the fracturing fluid also increases more significantly. For the volume fracturing construction with large displacement and large sand volume, the friction performance of the fracturing fluid is the key concern, 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 good carrying capacity for 40 / 70 (complete settlement for more than 2 minutes). For 30 / 50 proppant, to meet similar indicators, medium-high viscosity fracturing fluid needs to be used;

[0089] (2) When using high-viscosity fracturing fluid to create fractures in the S1 stage, its construction friction at 16 m 3 / min is also higher than that of other fracturing fluids at 20 m 3 / min. Therefore, the construction displacement in the S1 stage should be appropriately controlled.

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

[0091] Table 2 Fracture simulation results of different types of fracturing fluids (liquid volume 3000 m 3 , displacement 20 m 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 coal seam thickness is generally less than 20 m, and the main reservoir is about 15 m. 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 the Effect of the Shielding and Temporary Plugging and Diversion Measure:

[0096] During the construction of a deep coalbed methane horizontal well using the coalbed methane temporary plugging and diversion and large - particle - size sand - added fracturing method provided by the present invention, for two sections where the shielding and temporary plugging and diversion measure was not implemented and implemented respectively, the micro - seismic technology was used to monitor the fracture initiation points during the fracturing process. The comparison of the monitoring results in the first half of the fracturing (half of the sand - adding volume) is shown in Figure 3 the following figure.

[0097] From the comparison results, it can be seen that in the construction section where the shielding and temporary plugging and diversion measure was not implemented, during the first half of the construction, the fracture initiation and extension mainly occurred in one direction, the dominant fracture in a single direction developed too prominently, and the overall fracture network was uneven. While in the construction section where the shielding and temporary plugging and diversion measure was implemented, the fracture network extension degrees on both sides of the well section were similar, and the overall fracture network was uniform.

[0098] 3. Monitoring the Effect of the Diversion Sand Temporary Plugging Measure:

[0099] During the construction of a deep coalbed methane horizontal well using the coalbed methane temporary plugging and diversion and large - particle - size sand - added fracturing method provided by the present invention, the micro - seismic technology was used to monitor the fracture initiation points throughout the fracturing process. The monitoring results are shown in Figure 4 the following figure.

[0100] It is clearly shown in the figure that before the diversion sand temporary plugging, there were fewer fracture initiation points close to the wellbore and more far from the wellbore, the fracture propagation trend was obvious, but the fracture network density was very low; after the diversion sand temporary plugging, after the diversion sand plugged the dominant fractures, basically no fracture initiation points were found to respond further away, the fracture outward propagation trend stopped, the fracture initiation points increased on the original basis, and the fracture network was continuously densified, indicating that the temporary plugging and diversion had been achieved, new liquid - intake channels and new fractures were opened. Therefore, it can intuitively reflect the effect of the diversion sand temporary plugging measure, 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 - Particle - Size Filling Support

[0102] During the construction using the high - viscosity fracturing fluid and medium - viscosity fracturing fluid adopted by the present invention, FracPT was used to simulate the average width of the fracturing fractures for the following several proppant combination schemes, and a fracturing acidizing fracture conductivity tester was used to test the conductivity of different combination schemes (sand - laying concentration 20 kg / m 2 ) under different closure pressures (the results are shown in Figure 5 the following figure), and the effect comparison is shown in Table 3 as follows:

[0103] Table 3 Effect Comparison Obtained from Different Proppant Combination Schemes

[0104]

[0105] As can be seen from Table 2, the average width of the fractures obtained by simulating the proppant combination scheme 5 is 0.42 cm, and the fracture conductivity can reach 223 μm·cm under the closure pressure of 40 MPa (the fitting closure pressure of the deep No. 8 coal seam at 2300 m is about 40 MPa). Compared with the proppant combinations used in the early stage, both the fracture width and conductivity have been improved to a certain extent. However, further increasing the proportion of large-size proppants will not lead to a significant increase in conductivity, but will increase the difficulty of sand addition. Therefore, the large-size filling and propping measures of combination scheme 5 are determined and can be optimized and adjusted within a certain range. 2 ·cm, compared with the proppant combinations used in the early stage, both the fracture width and conductivity have been improved to a certain extent. However, further increasing the proportion of large-size proppants will not lead to a significant increase in conductivity, but will increase the difficulty of sand addition. Therefore, the large-size filling and propping measures of combination scheme 5 are determined and can be optimized and adjusted within a certain range.

[0106] Application Example

[0107] Well Jishen 13-*A Ping 02 is located in the eastern part of the Yishan Slope in the Ordos Basin. The top depth of the No. 8 coal seam is 2330 m, the completion depth is 3631 m, the horizontal section footage is 1301 m, the cumulative coal seam length is 1301 m, and the coal seam encounter rate is 100%. Combining with the seismic structure understanding, the horizontal section of Well Jishen 13-*A Ping 02 is located on the positive micro-structure in the north-south direction. The total thickness of the No. 8 coal seam is 8.6 - 12.7 m, which is divided into No. 8-1 coal seam, No. 8-2 coal seam, and No. 8-3 coal seam. Among them, the No. 8-2 coal seam and No. 8-3 coal seam are mainly bright coal and semi-bright coal. The main difficulties in the previous fracturing transformation are as follows: the complexity of the fracture network is insufficient, and the transformation volume is limited; the coal seam is relatively thin, and the fracture height is prone to uncontrollable breakthrough to the top and bottom plates, resulting in abnormal construction and great difficulty in sand addition; the proppant combinations of 200 mesh, 100 mesh, 40 / 70 mesh, and 30 / 50 mesh were used for sand addition in the early stage, and the conductivity of the supported fractures after fracturing was insufficient, resulting in low gas production.

[0108] To achieve the efficient production of coalbed methane storage in this well, the well was segmented into 16 sections with an average section length of 81 m, and extreme volume fracturing transformation was carried out using φ114 casing. The designed construction displacement was 14 m 3 / min - 20 m 3 / min, the sand addition intensity was 4.5 m 3 / m - 5.0 m 3 / m, and the fluid consumption intensity was 30 m 3 / m - 35 m 3 / m. Applying the technology provided by the present invention, temporary plugging and diversion and large-size sand addition fracturing tests were carried out for deep coalbed methane. Without using 100-mesh sand, measures such as shielding temporary plugging and diversion, diversion sand temporary plugging, viscosity control, fracture formation, and sand increase were mainly adopted, and high displacement was superimposed to achieve the effect of large-size filling and propping, promoting the uniform extension of the fracture network, increasing the fracture complexity, and enhancing the conductivity of the supported filling layer, thereby increasing the coalbed methane production. The pump injection procedure for the first section of this well is shown in Table 4.

[0109] Table 4 Pump Injection Procedure for the First Section of Fracturing Construction of Well Jishen 13-*A Ping 02

[0110]

[0111]

[0112] The construction is carried out according to the above-mentioned pumping program, and the fracturing construction curve is shown in Figure 6 as follows. It can be seen that the maximum construction displacement reaches 20 m 3 / min, the maximum sand addition ratio reaches 24%, the overall construction pressure is stable, and the construction is smooth. With the matching of the technologies and processes of the present invention, the difficulty of the fracturing construction is not great. It can be seen from the curve that after the shielding temporary plugging diversion measure, at the same displacement, the construction pressure after the second pump start-up increases by 4.8 MPa compared with that before the pump stop. The increase in the construction pressure is more conducive to the initiation and propagation of the perforation clusters or fractures with a larger stress difference, realizing fracture diversion; similarly, during the implementation of the diversion sand temporary plugging process, the construction pressure continues to rise, and when the displacement returns to the same as before the diversion sand temporary plugging, the construction pressure rises by 2 MPa, which is conducive to the opening of new fractures and promoting fracture complexity.

[0113] The above are only the preferred embodiments of the present invention, and do not impose any form of limitation on the present invention. Although the present invention has been disclosed above with the preferred embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some changes or modifications to the above-disclosed technical content to obtain equivalent embodiments with equivalent changes. However, as long as the content does not depart from the technical solution of the present invention, any simple modification, equivalent change and modification made to the above embodiments based on the technical essence 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 particle size sand fracturing method for deep coal-rock reservoirs, characterized in that, The coal-rock gas accumulation fracturing is completed by a combination of measures including viscosity-controlled fracture creation and sand addition, shielding temporary plugging and diversion, diversion sand temporary plugging, and large particle size filling and support, and includes the following steps: S1. Use a high-viscosity fracturing fluid to open the coal-rock cleats at the first displacement rate to create a main fracture to communicate with the near-wellbore zone; S2. Use a medium-low viscosity fracturing fluid to carry 40 / 70 mesh proppant into the formation at the second displacement rate with the first-stage sand ratio, and the stage proppant volume is W1 cubic meters, to polish and fill the fracture, further open the cleats and fissures, and place proppant in the high-permeability dominant fracture in the near-wellbore zone to form a shielding zone; S3. After stopping the pump for 60 min to 120 min, start the pump again to complete the shielding temporary plugging and the first fracture diversion; S4. Use a high-viscosity fracturing fluid to re-fracture the coal seam at the second displacement rate to create a long main fracture, create new fractures and more branch fractures and communicate with the distal end; S5. Use a medium-viscosity fracturing fluid to carry 40 / 70 mesh proppant into the formation at the second displacement rate with the second-stage sand ratio, and the stage proppant volume is W2 cubic meters, to continuously extend the complex fracture network, and the proppant is filled in the micro-fractures and secondary fractures; S6. Use a medium-low viscosity fracturing fluid to carry diversion sand into the formation at the first displacement rate with the third-stage sand ratio, and the diversion sand volume is W3 cubic meters. Through the actions of diversion sand swelling, self-bridging, aggregation, etc., promote the change of the fracture extension direction to achieve the secondary fracture diversion; S7. Use a medium-high viscosity fracturing fluid to carry 30 / 50 mesh proppant into the formation at the second displacement rate with the fourth-stage sand ratio, and the stage proppant volume is W4 cubic meters, so that the proppant gradually supports and fills from the middle end to the proximal end of the fracture, improve the overall filling degree of the fracture network, and establish an interconnected complex fracture network filled with sand; S8. After stopping adding sand, use a medium-high viscosity fracturing fluid + low-viscosity fracturing fluid to displace until the designed displacement volume is reached, and then stop the pump to 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. The temporary plugging and diversion and large particle size sand fracturing method for deep coal rock reservoir according to claim 1, characterized in that, The range of the first displacement value is 12 to 16 m 3 / min; the range of the second displacement value is 16 to 25 m 3 / min.

3. A temporary plugging and diversion, large particle size sand fracturing method for deep coal rock reservoirs according to claim 1, characterized in that, The first-stage sand ratio is increased stepwise from 8% to 16%, with each step being 2%; the second-stage sand ratio is increased stepwise from 13% to 22%, with each step being 3%; the third-stage sand ratio is increased stepwise from 16% to 18%, with each step being 2%; the fourth-stage sand ratio is increased stepwise from 20% to 24%, with each step being 2%.

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

5. The temporary plugging and diversion, large particle size sand addition fracturing method for deep coal and rock reservoirs according to claim 1, characterized in that The steering sand is a slightly expandable coated film material, which is prepared by coating a matrix with a mixture of resin, hydrophobic modifier, and Zeta potential regulator, aging, and screening; the particle size range of the matrix is 0.104 mm to 0.425 mm; the steering sand includes upper steering sand and lower steering sand with a volume ratio of 1:

1. When a low-density matrix is selected, the lower steering sand is obtained, and its density is 0.95 to 1.05 g / cm 3 ; when a high-density matrix is selected, the upper steering sand is obtained, and its density is 1.6 to 1.85 g / cm 3 .

6. The temporary plugging and diversion and large particle size sand fracturing method for deep coal-rock reservoir according to claim 5, characterized in that, The mass ratio of the resin, hydrophobic modifier and Zeta potential regulator is 97:1:

2.

7. A temporary plugging and diversion, large particle size sand fracturing method for deep coal rock reservoirs according to claim 5, characterized in that, The resin is composed of any one of diphenylmethane diisocyanate, toluene diisocyanate and any one of polyacrylic resin, polymethyl methacrylate, phenolic resin, polyamide-imide resin, polylactate in a mass ratio of 2:1 - 3:

1.

8. The temporary plugging diversion and large - particle - size sand - added fracturing method for deep coal - rock reservoirs according to claim 5, characterized in that, The hydrophobic modifier is one of hydrophobic nano-silica, dimethyl polysiloxane, fluorinated polysiloxane, and zinc stearate.

9. The temporary plugging and diversion, large particle size sand fracturing method for deep coal-rock reservoir according to claim 5, characterized in that, The Zeta potential regulator is one of 3-(2-methylpyrimidine)aniline, 5-(4-methoxyphenyl)pyrimidin-2-amine, 5-ethylpyrimidin-2-amine, a 2-aminopyrimidine-dodecylmethyldihydroxyethyl ammonium bromide mixture with a mass ratio of 1:6 to 1:10, and a 2-aminopyrimidine-chloroethyltrimethyl ammonium chloride mixture with a mass ratio of 1:8 to 1:

10.

10. A temporary plugging and diversion and large particle size sand fracturing method for deep coal and rock reservoirs according to 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 medium-density or high-density ceramsite proppants.

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