A method of fracturing a coalbed gas reservoir and applications thereof

Abstract

The present application relates to a kind of coalbed gas reservoir fracturing method and its application, belong to coalbed gas mining technical field.The fracturing method includes the following steps: sequentially injecting pretreatment fluid, preflush, sand-carrying fluid and displacement fluid;The preflush includes first combination fluid and second combination fluid;The first combination fluid includes high-viscosity fracturing fluid, low-viscosity fracturing fluid sequentially injected in front and back, wherein high-viscosity fracturing fluid creates main fracture, the low-viscosity fracturing fluid segment type sand plug coal rock microcrack and cleat and expands fracture network;The second combination fluid includes high-viscosity fracturing fluid, medium-viscosity fracturing fluid sequentially injected in front and back, wherein high-viscosity fracturing fluid creates long fracture, the medium-viscosity fracturing fluid continuously sand-carrying forms netted support fracture.The method of the present application can form main fracture+complex fracture network by fracturing, improve fracture complexity, increase fracture sweep range, improve fracture conductivity, thereby improve the gas production of coal seam.

Description

Technical Field

[0001] This invention relates to a fracturing method for coalbed methane reservoirs and its application, belonging to the field of coalbed methane extraction technology. Background Technology

[0002] With the dwindling supply of conventional oil and gas resources, coalbed methane (CBM) has gained attention from oil and gas extraction companies as a clean alternative energy source. CBM has a unique formation mechanism: coal is formed from plant remains under specific geological conditions, and CBM is adsorbed into the micropores of the coal under pressure. Before depressurization and desorption, there is no free gas in the micropores. Only when the coal seam pressure drops to a certain level can natural gas such as methane within the coal seam be desorbed, flow through fractures and pores, enter the coal seam pore network, and then flow through the pore network to the wellbore.

[0003] However, sandstone natural gas differs significantly from coalbed methane in several aspects: storage methods, fracture structure, rock physical properties, fracturing difficulty, production curves, and reserve estimation methods. Therefore, methods for developing deep sandstone natural gas are not suitable for coalbed methane extraction. Consequently, developing a method specifically for extracting coalbed methane from its unique characteristics is crucial for improving coalbed methane production.

[0004] Currently, the main methods for fracturing and enhancing production in coalbed methane wells include: gel fracturing fluids, clean fracturing fluids, oil-based fracturing, and CO2 dry fracturing fluids. These methods mainly face the following technical challenges during coalbed methane well fracturing operations:

[0005] In gel fracturing, a large amount of gel residue remains in the reservoir during the fracturing process, leading to severe reservoir contamination. After fracturing, the gel is difficult to break down, blocking the reservoir water flowback channels and significantly reducing the gas production capacity of coalbed methane wells. Oil-based and clean fracturing fluid methods have high construction costs, low safety, and are difficult to control gel breaking down, resulting in their limited application in coalbed methane well fracturing. CO2 dry fracturing requires sophisticated equipment and has poor proppant addition capabilities (CO2 is contained in a sealed tank, making large-scale proppant addition impossible), and cannot effectively control the size and morphology of fractures during fracturing. Summary of the Invention

[0006] The purpose of this invention is to provide a fracturing method for coalbed methane reservoirs, which solves the problems of serious reservoir contamination, low safety, and inability to effectively control the size and morphology of fractures during the fracturing process in the existing technology.

[0007] The second objective of this invention is to provide an application of a fracturing method for coalbed methane reservoirs in coalbed methane extraction, thereby improving the gas production capacity of coalbed methane.

[0008] To achieve the above objectives, the first technical solution of the present invention is as follows:

[0009] A fracturing method for a coalbed methane reservoir includes the following steps: sequentially injecting a pretreatment fluid, a pre-fracturing fluid, a proppant-carrying fluid, and a displacement fluid; the pre-fracturing fluid includes a first combined fluid and a second combined fluid; the first combined fluid includes a high-viscosity fracturing fluid and a low-viscosity fracturing fluid injected sequentially before and after the fracturing fluid, wherein the high-viscosity fracturing fluid creates the main fracture, and the low-viscosity fracturing fluid uses a slug-type proppant injection to plug micro-fractures and cleavages in the coal and rock and expand the fracture network;

[0010] The second combined fluid comprises a high-viscosity fracturing fluid and a medium-viscosity fracturing fluid injected sequentially from the front and back. The high-viscosity fracturing fluid creates long fractures, while the medium-viscosity fracturing fluid is continuously mixed with sand to form a network of supported fractures.

[0011] The pre-fracturing fluid of this invention utilizes a combination of high-viscosity and low-viscosity fracturing fluids, along with a combination of high-viscosity and medium-viscosity fracturing fluids, to form a main fracture plus a complex fracture network. This increases the complexity of the fractures, expands the fracture sweep range, and enhances the fracture conductivity, thereby increasing fracture-controlled reserves and coal seam gas production. Furthermore, the fracturing method of this invention does not cause reservoir contamination and has high safety.

[0012] The pretreatment fluid removes near-wellbore contamination and reduces fracturing pressure. The displacement fluid flushes the pre-fracturing acid from the wellbore into the formation. The proppant-carrying fluid forms the main supporting fractures in the "veins" of a network of fractures. The displacement fluid ensures the fracturing fluid is properly displaced and cleans the wellbore. Preferably, the displacement fluid is a low-viscosity fracturing fluid.

[0013] Preferably, the viscosity of low-viscosity fracturing fluid is <15 mPa.s if 6 mPa.s ≤, the viscosity of medium-viscosity fracturing fluid is <25 mPa.s if 15 mPa.s ≤, and the viscosity of high-viscosity fracturing fluid is <50 mPa.s if 25 mPa.s ≤, and the viscosity of high-viscosity fracturing fluid is <50 mPa.s.

[0014] To better create complex fracture networks, preferably, in low-viscosity fracturing fluid, the sand-to-fluid ratio of the slug-type sand addition is gradually increased; in medium-viscosity fracturing fluid, the sand-to-fluid ratio of the continuous sand addition is gradually increased; the highest sand-to-fluid ratio of the slug-type sand addition is not greater than the lowest sand-to-fluid ratio of the continuous sand addition.

[0015] Preferably, the sand-to-liquid ratio of the slug-type sand addition is 5-11%; the sand-to-liquid ratio of the continuous sand addition is 13-21%. As the number of seam meshes increases, the amount of sand required to support and plug the seam meshes also increases.

[0016] Preferably, the proppant used in the slug-type sand addition and the continuous sand addition has a mesh size of 70 / 140.

[0017] The slug-type proppant addition of this invention aims to use low-viscosity fracturing fluid to carry small-diameter proppant to plug micro-fractures and cleavages within coal and rock, thereby reducing fracturing fluid loss through fractures. The continuous proppant addition aims to use medium-viscosity fracturing fluid to carry small-diameter proppant to support cleavages and micro-fractures within coal and rock, forming a network of supporting fractures in the "network" section. These "network" fractures can connect with fractures at the far end of the coal seam, increasing the influence of fractures on the coal seam plane and thus improving gas production.

[0018] To ensure complete penetration of the pre-flush acid into the formation, the pre-flush fluid preferably includes a low-viscosity fracturing fluid. The low-viscosity fracturing fluid is injected after the pretreatment fluid and before the first combined fluid.

[0019] Preferably, the proppant-carrying fluid includes a first proppant-carrying fluid and a second proppant-carrying fluid injected sequentially. The proppant particle size in the first proppant-carrying fluid is smaller than that in the second proppant-carrying fluid. Medium-diameter sand plugs are first added to fill the plugs, followed by large-diameter sand plugs, ultimately forming the main propped fracture in the "veins" of a network of fractures. This creates a highly permeable artificial main fracture in the coal seam, providing a flow channel for coalbed methane.

[0020] Preferably, the proppant mesh size of the first sand-carrying fluid is 40 / 70 mesh; the proppant mesh size of the second sand-carrying fluid is 30 / 50 mesh. To achieve the concepts of "effective support" and "far-range support," a combination of "40 / 70 mesh proppant + 30 / 50 mesh proppant" is used. The medium-sized proppant supports the main fracture, improving the conductivity of fractures of different sizes, while the 30 / 50 mesh large-sized proppant at the tail improves the support strength in the near-wellbore zone, prevents proppant backflow, enhances fracture conductivity, and controls pulverized coal production.

[0021] To better support the cracks, preferably, the sand-liquid ratio of the first sand-carrying fluid is gradually increased to 10-20%; and the sand-liquid ratio of the second sand-carrying fluid is gradually increased to 15-30%.

[0022] More preferably, the sand-carrying fluid is a high-viscosity fracturing fluid.

[0023] Preferably, the pre-flush stage involves variable displacement, with the displacement gradually increasing; the proppant-carrying stage involves constant displacement. A higher displacement allows for farther proppant delivery, while simultaneously hydraulically cutting the coal blocks and releasing their adsorbed gases. This invention employs casing injection fracturing to increase the displacement during construction.

[0024] More preferably, the total discharge volume of the pre-fluidization stage is 250-400 m³. 3 / min. High displacement effectively alters the stress field of the coal seam, improves porosity and permeability, and propels proppant to deeper reservoir layers.

[0025] The total discharge rate of the low-viscosity fracturing fluid is 150–250 m³.3 / min; the total discharge rate of medium-viscosity fracturing fluid is 70–120 m³ / min. 3 / min.

[0026] Preferably, the total discharge rate of the sand-carrying fluid is 200-250 m³. 3 / min.

[0027] The second technical solution of the present invention is:

[0028] Application of a fracturing method for the above-mentioned coalbed methane reservoir in coalbed methane extraction.

[0029] Applying the fracturing method for coalbed methane reservoirs of the present invention to coalbed methane extraction can effectively desorb natural gas from coal seams and improve the gas production capacity of coalbed methane.

[0030] Preferably, it includes the following steps:

[0031] (1) Conduct reservoir evaluation of coal seams and obtain evaluation parameters;

[0032] (2) Based on the analysis results of step (1), carry out hydraulic fracturing of the coalbed methane reservoir;

[0033] (3) After the fracturing operation is completed, coalbed methane is extracted according to the production parameters. Attached Figure Description

[0034] Figure 1 This is a water sensitivity evaluation curve of the core of coal seam #8 in Pengzhen Well No.1 of this invention;

[0035] Figure 2 This is a curve for evaluating the alkali sensitivity of coal seam #8 in Pengzhen Well of this invention.

[0036] Figure 3 This is a logging curve of the Taiyuan Formation in well Pengzhen 1 of this invention;

[0037] Figure 4 This is a coal seam fracturing construction curve diagram of Pengzhen 1 well in Embodiment 1 of the present invention;

[0038] Figure 5 This is a coal seam fracturing construction curve diagram of Pengzhen 1 well in Embodiment 2 of the present invention;

[0039] Figure 6 This is a graph showing the trend of slit length variation under different liquid volumes in Experiment Example 1 of the present invention.

[0040] Figure 7 This illustrates the variation trend of formation conductivity under different sand contents in Experiment Example 1 of this invention.

[0041] Figure 8 The liquid volume for Experimental Example 1 of this invention was 3500m³. 3 Sand volume 300m 3Simulated fracture morphology of the target layer under pressure fracturing;

[0042] Figure 9 The liquid volume for Experimental Example 1 of this invention was 3500m³. 3 Sand volume 350m 3 Simulated fracture morphology of the target layer under pressure fracturing;

[0043] Figure 10 The liquid volume for Experimental Example 1 of this invention was 3500m³. 3 Sand volume 400m 3 Simulated fracture morphology of the target layer under pressure fracturing;

[0044] Figure 11 The slug-type sand addition method (sand addition amount of 350m) in Experimental Example 2 of this invention 3 Simulated fracture morphology diagram;

[0045] Figure 12 The continuous sand addition (sand addition amount is 350m³) is an example of Experimental Example 2 of this invention. 3 Simulated fracture morphology diagram;

[0046] Figure 13 This is a simulated fracture morphology diagram of the pre-fracturing low-viscosity fluid (viscosity of 6 mPa·s) in Experimental Example 3 of the present invention.

[0047] Figure 14 The image shows the simulated morphology of the high-viscosity liquid (viscosity 42 mPa·s) used in Experimental Example 3 of this invention.

[0048] Figure 15 For the rapid increase of discharge rate (discharge rate 6-10-14-16-18-20m) in Experimental Example 4 of this invention 3 Simulated fracture morphology diagram ( / min);

[0049] Figure 16 For Experimental Example 4 of this invention, the slow increase in displacement (displacement 6-8-10-12-14-16-18-20m) 3 ( / min) Simulated fracture morphology diagram. Detailed Implementation

[0050] Coalbed methane has a unique formation mechanism; it is adsorbed into the micropores of coal under pressure, which is very different from natural gas in deep sandstone formations.

[0051] (1) Different gas storage methods. Conventional sandstone natural gas exists macroscopically in free and dissolved states within rock traps, while coalbed methane, in addition to being in free and dissolved states, has over 95% of its gas molecules adsorbed on the coal seam surface, forming a monolayer adsorbed on the inner surface of micropores under pressure. Before depressurization and desorption, there is almost no free gas in the micropores; only adsorbed gas. Through adsorption, coal seams have a higher gas storage capacity than sandstone. Compared to sandstone of the same volume, coal seams can store 2-3 times more natural gas.

[0052] (2) Different fracture structures. Compared with sandstone gas in oil fields, coal seams have more developed cleavage and fractures. The fracturing fluid injected from the surface is lost in large quantities, and proppant is easily blocked by sand. The proppant added to the coal seam is easily embedded in the coal seam, which reduces the fracture space formed by the proppant and reduces the coalbed methane production.

[0053] (3) Different physical properties of rocks. Coal seams are rocks formed from organic matter such as plants and trees, while sandstone is composed of minerals such as quartz and mica. Therefore, coal seams are softer than sandstone, and the proppant pumped by fracturing pumps is easily embedded in the coal and rock, which reduces or even eliminates the gas flow channels formed by the proppant, affecting gas production. During the post-fracturing drainage gas production process, due to the loose cementation of the coal, some coal dust will be carried into the wellbore, clogging the wellbore.

[0054] (4) Fracturing is difficult. Both deep coalbed methane and sandstone reservoirs require fracturing to release the gas within the rock formations. However, compared to deep sandstone layers, deep coal seams are softer, more brittle, more easily compressed, and have a lower Young's modulus. During fracturing, the softness of the coal seams results in wider artificial fractures and higher construction pressure, requiring more equipment and chemical preparation, thus increasing the difficulty of the operation.

[0055] (5) The production curves of gas production are different. Coalbed methane wells first increase in gas production, reach a peak, and then slowly decline, maintaining a uniform gas production rate over a long period. Sandstone natural gas, on the other hand, shows a production curve that declines from a peak to depletion.

[0056] (6) Different methods of reserve estimation. Natural gas reserves in sandstone are estimated using the pore volume method, since the gas is stored in the pores and fractures of the rock, and the reserves can be measured by porosity volume. Coalbed methane reserves cannot be calculated using the pore volume method because coalbed methane content is divided into desorbed gas, escaped gas, and residual gas. The conventional approach is to extract the coal core to the wellhead, seal it in a sealed container, and use a desorption instrument in the laboratory to determine the change in methane content in the coal over time, thus calculating the desorbed gas. The escaped gas is calculated based on the exposure time of the coal sample during the drilling and sampling process. Then, the coal in the laboratory is crushed, and its residual gas is measured. The sum of the desorbed gas, residual gas, and escaped gas is the total coalbed methane reserves.

[0057] (7) The adsorption of methane by coal relies on van der Waals forces, which is a physical adsorption process and is 100% reversible. Under certain pressure conditions, the adsorbed methane will detach from the inner surface of the coal and enter the free phase, which is the desorption of coalbed methane. The production of coalbed methane has gone through three stages. Fundamentally, the pressure difference between the matrix inside the coal seam and the wellbore controls the desorption and diffusion of coalbed methane.

[0058] (8) Unreasonable work systems affect stable coalbed methane production. During the drainage process, underground solid particles (proppant, pulverized coal) enter the tubing from the coal seam but are not carried to the surface. Instead, they settle, accumulate, and clog the pump casing, causing pump leakage and pump jamming, among other downhole malfunctions. Once pump leakage or pulverized coal jamming occurs, production efficiency decreases. Furthermore, restoring production through pump inspection increases the operating costs of the drainage well and may even cause irreversible damage during the inspection process.

[0059] Because the conventional methods for extracting natural gas from sandstone and shale differ from those for extracting coalbed methane, a production method tailored to the specific characteristics of coal seams is needed to increase coalbed methane production.

[0060] Overview of Pengzhen 1 well in the following examples: This exploration well is located in Xunyi area. The vitrinite reflectance of the coal seam is 1.5% to 2.0%. The composition is mainly lean coal and some anthracite. The structure is mainly primary + fractured structure. The specific parameters are shown in Table 1.

[0061] Table 1. Overview parameters of coalbed methane wells in Pengzhen 1 well area

[0062]

[0063]

[0064] The rock mechanical characteristics test results of Pengzhen 1 well are shown in Table 2. Among them, the elastic modulus of the coal seam is 1.32-3.2 GPa and the Poisson's ratio is 0.232-0.258, which shows the plastic characteristics of low elastic modulus and high Poisson's ratio, and is prone to forming short and wide fractures.

[0065] Table 2 Results of rock mechanical characteristic tests at Pengzhen 1 well

[0066]

[0067] The reservoir temperature in the middle of the fracturing layer of Pengzhen 1 well is 65.9℃. The pressure gradient is 0.67-0.98MPa / 100m, and the pressure coefficient is relatively low.

[0068] The water sensitivity evaluation results of the Pengzhen 1 coal seam are as follows: Figure 1 As shown. By Figure 1It can be seen that the core water-sensitive damage rate of the Pengzhen 1 coal seam is 10%, which is classified as weak water-sensitive damage.

[0069] The water sensitivity evaluation results of the Pengzhen 1 coal seam are as follows: Figure 2 As shown. By Figure 2 It is known that the coal seam in Pengzhen 1 well has a medium to strong alkalinity sensitivity. Therefore, the anti-swelling performance of the fracturing fluid should be optimized, and the pH value of the fracturing fluid should be controlled below 7.

[0070] Table 3 shows the oil and gas display table of the Taiyuan Formation in Pengzhen 1 well.

[0071] Table 3. Oil and gas display table of Taiyuan Formation in Pengzhen 1 well.

[0072] well section / m Thickness / m Lithology Total hydrocarbons / % 2196.83-2197.38 0.55 Black coal seam 0.577↑1.416 2207.0-2209.0 2 Black coal seam 0.672↑23.367 2220.0-2225.0 5 Black coal seam 1.227↑47.053 2239.94-2240.4 0.46 Black coal seam 1.905↑4.762 2243.24-2243.7 0.46 Black coal seam 1.905↑3.680 2245.99-2247.83 1.84 Black coal seam 1.905↑10.063 2259.1-2259.66 0.56 Light gray coal seams containing sandstone 0.979↑2.128

[0073] The logging interpretation results of the Taiyuan Formation in Well Pengzhen 1 are shown in Table 4, and the logging curves are as follows: Figure 3 As shown.

[0074] Table 4. Well logging interpretation results of Pengzhen-1 well in the Taiyuan Formation.

[0075]

[0076]

[0077] The metrics involved in the following examples are:

[0078] Sand-to-liquid ratio % = Sand quantity (m) 3 / Net liquid volume (m) 3

[0079] Sand concentration kg / m 3 = Sand-liquid ratio % * Sand density (1.45-1.6 kg / m³) 3 )*10

[0080] The materials involved in the following embodiments:

[0081] Pre-acid solution formulation: 12% hydrochloric acid + 3% hydrofluoric acid + 2.0% corrosion inhibitor + 2% iron ion stabilizer + 0.5% drainage aid;

[0082] Hydrochloric acid and hydrofluoric acid are both commercially available products.

[0083] The corrosion inhibitor is a commercially available product, preferably an acid corrosion inhibitor sold by Beijing Baofengchun Petroleum Technology Co., Ltd.

[0084] The iron ion stabilizer is a commercially available product, preferably the iron ion stabilizer sold by Beijing Baofengchun Petroleum Technology Co., Ltd.

[0085] The drainage aid is a commercially available product, preferably the acidification drainage aid sold by Beijing Baofengchun Petroleum Technology Co., Ltd.

[0086] Low-viscosity fracturing fluids generally have a viscosity greater than or equal to 6 mPa·s and less than 15 mPa·s. They are composed of the following components by mass percentage: 0.1%–0.15% thickener, 0.2%–0.3% clay stabilizer, 0.2%–0.3% flow aid, and 0.005%–0.03% breaker; the solvent is water; and its relevant properties are shown in Table 7.

[0087] Medium-viscosity fracturing fluids generally have a viscosity greater than or equal to 15 mPa·s and less than 25 mPa·s. They are composed of the following components by mass percentage: 0.2%–0.25% thickener, 0.2%–0.3% clay stabilizer, 0.2%–0.3% flow aid, and 0.005%–0.03% breaker; the solvent is water; and its relevant properties are shown in Table 6.

[0088] High-viscosity fracturing fluids generally have a viscosity greater than or equal to 25 mPa·s and less than 50 mPa·s. They are composed of the following components by mass percentage: 0.3%–0.45% thickener, 0.2%–0.3% clay stabilizer, 0.2%–0.3% flow aid, and 0.005%–0.03% breaker; the solvent is water; and its relevant properties are shown in Table 5.

[0089] Table 5 Performance of High Viscosity Integrated Fracturing Fluid

[0090]

[0091] Table 6 Performance of Medium-Viscous Fracturing Fluid

[0092]

[0093] Table 7 Performance of Low-Viscosity Integrated Fracturing Fluid

[0094]

[0095] The preparation methods for low, medium, and high viscosity fracturing fluids are as follows: At the construction site, a pump is used to draw the emulsion into the mixing tank of a pump truck, where it is mixed with water, clay stabilizer, and drainage aid. Compared to conventional guar gum fracturing fluid systems, this fracturing fluid system has the advantages of rapid dissolution, viscosity that can be varied by changing the thickener ratio, and a neutral pH after mixing.

[0096] Specifically, the thickener is a commercially available product, a white polyacrylamide emulsion. The preferred thickener is a fast-dissolving emulsion drag reducer sold by Beijing Baofengchun Petroleum Technology Co., Ltd.

[0097] The clay stabilizer is a commercially available product, preferably the fracturing clay stabilizer sold by Beijing Baofengchun Petroleum Technology Co., Ltd.

[0098] The drainage aid is a commercially available product, preferably the acidification drainage aid sold by Beijing Baofengchun Petroleum Technology Co., Ltd.

[0099] The de-glue agent is ammonium persulfate, an industrial commercial product.

[0100] The technical solution of the present invention will be further described below with reference to specific embodiments.

[0101] I. Specific embodiments of the fracturing method for coalbed methane reservoirs of the present invention are as follows:

[0102] Example 1

[0103] The fracturing method for coalbed methane reservoirs in this embodiment is specifically applied to the perforated section of the Taiyuan Formation: 2207.0-2209.0m. The fracturing pumping procedure is shown in Table 8, and the construction parameters are as follows: Figure 4 As shown, the specific steps are as follows:

[0104] Table 8. Coalbed Fracturing Pumping Procedure for Pengzhen 1 Well

[0105]

[0106]

[0107]

[0108] Example 2

[0109] The fracturing method for coalbed methane reservoirs in this embodiment mainly targets the perforated section of the Taiyuan Formation: 2220.0-2225.0m. The fracturing pumping procedure is shown in Table 9, and the construction parameters are as follows: Figure 5 As shown.

[0110] Table 9. Coalbed Fracturing Pumping Procedure for Pengzhen-1 Well

[0111]

[0112]

[0113] Example 3

[0114] The fracturing method for coalbed methane reservoirs in this embodiment is mainly applied to the perforated section of the Taiyuan Formation: 2259.1-2259.66m. The fracturing pumping procedure is shown in Table 10.

[0115] Table 10. Coalbed Fracturing Pumping Procedure for Pengzhen 1 Well

[0116]

[0117]

[0118] II. The specific implementation method of the fracturing method for coalbed methane reservoirs of the present invention in the extraction of coalbed methane is as follows:

[0119] Example 4

[0120] The specific operational method of the fracturing method for coalbed methane reservoirs in this embodiment for coalbed methane extraction is as follows:

[0121] (1) Conduct reservoir evaluation of coal seams and obtain evaluation parameters, including reservoir sensitivity analysis, rock mechanical properties, and well logging interpretation results;

[0122] Sensitivity analysis results are as follows: water-sensitive critical mineralization is 4000-5000 ppm; no acid sensitivity; alkali-sensitive critical pH is 8.5-10.

[0123] The rock's mechanical properties are as follows: Poisson's ratio is 0.20–0.26, and its density is 1.2–1.4 g / cm³. 3 ;

[0124] Well logging interpretation results: formation resistivity 800-2000 Ω·m, porosity 10-30%, sonic transit time 200-500 μs / m.

[0125] (2) Based on the analysis results of step (1), the coalbed methane reservoir is subjected to hydraulic fracturing. The specific operation adopts the method of Example 1-3.

[0126] (3) After the fracturing operation is completed, coalbed methane is extracted according to the production parameters.

[0127] The specific operational steps for extracting coalbed methane are as follows:

[0128] (1) Raise the pump hanger: The pump depth is raised from 2100m to 1400m to provide settling space for pulverized coal and fracturing sand, and avoid blockage of the tubing to affect the liquid output;

[0129] (2) Long stroke and low stroke rate: The initial liquid production of 30 cubic meters / day is adjusted to about 20 cubic meters / day. The stroke rate is adjusted by the auxiliary frequency conversion process to avoid exciting the formation to produce sand and coal.

[0130] (3) Add sand prevention function: Perforated screen tube + wire-wound screen tube are installed at the inlet of gas-liquid separator. The wire-wound screen tube is 20m long and has an accuracy of 0.3mm. The perforated screen tube has 350 holes of 2mm to assist in exhaust.

[0131] (4) Real-time downhole pressure monitoring: Add an electronic pressure gauge to measure the liquid level, transmit signals via steel pipe and cable, control the initial daily pressure drop to 0.5-0.6MPa, and after gas breakthrough, the daily pressure drop to <0.05MPa, providing a basis for determining the coalbed methane drainage system;

[0132] (5) Optimization of casing venting system: Vent when casing pressure is 0.5-1MPa, relying on nozzle and needle valve control, gradually increasing production, and ensuring that bottom hole pressure decreases slowly (<0.1MPa).

[0133] III. Experimental Examples

[0134] Explanation of the simulation process in Experimental Example 1 and Example 1

[0135] (1) Optimization of injection and sand addition scale

[0136] This experimental example is based on the geological parameters of Pengzhen-1 well. Using Fraps fracturing simulation software, the variation trends of fracture length and height under different fluid volumes were simulated. The results are as follows: Figure 6 As shown.

[0137] Depend on Figure 6 It can be seen that the injection volume is 3500m³. 3 The seam length basically reaches a maximum of 220m. With the increase of liquid volume, the seam length changes little. This liquid volume refers to the total liquid volume of pretreatment + pre-treatment liquid + sand-carrying liquid + displacement liquid.

[0138] This experimental example, based on the geological parameters of Pengzhen-1 well, also simulated the variation trend of formation conductivity under different sand contents. The results are as follows: Figure 7 As shown in Table 11, the simulation parameters of cracks under different sand addition scales are presented.

[0139] Depend on Figure 7 As shown, when the sand volume is 350-400m³ 3 At this point, the flow guiding capacity reaches its optimal level, and increasing the amount of sand does not significantly alter the flow guiding capacity.

[0140] Table 11 Simulation parameters of cracks under different sand addition scales

[0141]

[0142] This experimental example also simulated the crack variation trend under different liquid and sand volumes, and the results are as follows: Figure 8-10 As shown.

[0143] from Figure 8-10 Based on the simulation results, the sand addition scale is 350m 3 When the flow guiding capacity is at its maximum, adding more sand will not improve the flow guiding capacity and will also increase construction costs. Therefore, this invention adopts a sand addition scale of 350m. 3 The scale of sand addition is specifically the total amount of sand added during the pre-treatment and sand-carrying stages.

[0144] (2) Pumping mode optimization

[0145] This experimental example simulates hydraulic fracturing fractures by changing the sand addition method, and the results are as follows: Figure 11, 12 As shown.

[0146] Will Figure 11 , 12 Comparison shows that continuous sand addition has significantly better fracture conductivity than slug sand addition. However, in order to improve the success rate of construction and create complex fracture networks, slug sand addition is used in the early stage to hydraulically cut the coal seam, followed by continuous sand addition in the middle and later stages to increase the concentration of proppant and improve fracture conductivity.

[0147] (3) Optimization of pre-fluid viscosity

[0148] This experimental example simulates hydraulic fracturing fractures by changing the viscosity of the pre-flush fluid, and the results are as follows: Figure 13 , 14 As shown.

[0149] Will Figure 13 , 14 Comparison shows that pre-fracturing with high-viscosity fracturing fluid in coal seams can effectively increase fracture length. However, due to well-developed cleavage in coal seams, low-viscosity fracturing fluid leaches significantly, preventing it from effectively penetrating the far end of the reservoir. This differs from conventional tight sandstone, where pre-fracturing with high-viscosity fracturing fluid results in larger fracture heights and shorter fracture lengths.

[0150] (4) Displacement-increased speed optimization

[0151] This experimental example simulates hydraulic fracturing fractures by changing the acceleration rate of the displacement. The results are as follows: Figure 15 , 16 As shown.

[0152] Depend on Figure 15 , 16 It is evident that the flow rate of fast and slow lifting has little impact on the crack height and length. Considering the adequacy of crack formation, this invention selects the fast lifting flow rate method.

[0153] Application instructions for Experiment Example 2

[0154] The results of implementing the fracturing method of the present invention and the commonly used fracturing gas production method in Pengzhen 1 well are shown in Table 12.

[0155] Table 12 Comparison of the effects of the present invention and commonly used fracturing gas recovery methods

[0156]

[0157] As shown in Table 12, compared with commonly used fracturing gas production methods, the fracturing method of this invention significantly increases the gas production, reaching 21052 m³ / h. 3The continuous gas production time is 359 days; the water breakthrough time is 121 days, which is about twice that of KCl solution and guar gum fracturing fluid. Furthermore, after fracturing, KCl solution and guar gum fracturing fluid are easily clogged by formation coal and proppant in the wellbore, while the method of this invention is less prone to clogging and achieves better results.

Claims

1. A fracturing method for a coalbed methane reservoir, characterized in that, The process includes the following steps: sequentially injecting pretreatment fluid, pre-fracturing fluid, proppant-carrying fluid, and displacement fluid; the pre-fracturing fluid includes a first combination fluid and a second combination fluid; the first combination fluid includes high-viscosity fracturing fluid and low-viscosity fracturing fluid injected sequentially before and after, wherein the high-viscosity fracturing fluid creates the main fracture, and the low-viscosity fracturing fluid is used to plug micro-fractures and cleavages in the coal and rock and expand the fracture network. The second combination fluid includes a high-viscosity fracturing fluid and a medium-viscosity fracturing fluid injected sequentially from the front and back. The high-viscosity fracturing fluid creates long fractures, while the medium-viscosity fracturing fluid is continuously mixed with sand to form a network of supported fractures. The viscosity of low-viscosity fracturing fluid is 6 mPa·s or less than 15 mPa·s; the viscosity of medium-viscosity fracturing fluid is 15 mPa·s or less than 25 mPa·s; and the viscosity of high-viscosity fracturing fluid is 25 mPa·s or less than 50 mPa·s.

2. The fracturing method for coalbed methane reservoirs according to claim 1, characterized in that, In low-viscosity fracturing fluid, the sand-to-fluid ratio of the slug-type sand addition gradually increases; in medium-viscosity fracturing fluid, the sand-to-fluid ratio of the continuous sand addition gradually increases; the highest sand-to-fluid ratio of the slug-type sand addition is not greater than the lowest sand-to-fluid ratio of the continuous sand addition.

3. The fracturing method for coalbed methane reservoirs according to claim 1 or 2, characterized in that, The sand-to-liquid ratio for the slug-type sand addition is 5-11%; the sand-to-liquid ratio for the continuous sand addition is 13-21%.

4. The fracturing method for coalbed methane reservoirs according to claim 1 or 2, characterized in that, The proppant used in the slug-type sand addition and the continuous sand addition is 70 mesh or 140 mesh.

5. The fracturing method for coalbed methane reservoirs according to claim 1, characterized in that, The sand-carrying fluid includes a first sand-carrying fluid and a second sand-carrying fluid injected sequentially from front to back. The particle size of the proppant in the first sand-carrying fluid is smaller than that in the second sand-carrying fluid.

6. The fracturing method for coalbed methane reservoirs according to claim 5, characterized in that, The proppant in the first sand-carrying liquid has a mesh size of 40 or 70; the proppant in the second sand-carrying liquid has a mesh size of 30 or 50.

7. The fracturing method for coalbed methane reservoirs according to claim 5 or 6, characterized in that, The sand-liquid ratio of the first sand-carrying liquid gradually increases to 10-20%; the sand-liquid ratio of the second sand-carrying liquid gradually increases to 15-30%.

8. The fracturing method for coalbed methane reservoirs according to claim 1, characterized in that, The pre-fluid stage involves variable discharge, with the discharge gradually increasing; the sand-carrying fluid stage involves constant discharge.

9. The application of a fracturing method for a coalbed methane reservoir as described in any one of claims 1-8 in the extraction of coalbed methane.

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