A method for improving the complexity of far-well fractures by staged fracturing of horizontal wells and its application

Abstract

The present invention discloses a method for improving the complexity of far-well cracks by staged fracturing of horizontal wells and its application. Aiming at the problem of low complexity of far-well cracks formed by fracturing construction of unconventional oil and gas and dense sandstone oil and gas, the present invention uses different displacements, different viscosity slick water and glue combinations, different densities and different particle sizes of proppants, and adds floating agents and sinking agents, so that the upper part, lower part and end of the cracks can be effectively blocked, the net pressure at the far end of the main crack is increased, more branch cracks are formed at the far end of the main crack, and proppants with different particle sizes and different densities are used to effectively support the main cracks and branch cracks, so as to improve the volume and conductivity of crack transformation as a whole. Construction according to the proposed method can effectively improve the initial production and stable production after fracturing.

Description

Technical Field

[0001] The present invention belongs to the field of fracturing, and in particular to the technical field of fracturing transformation of unconventional oil and gas reservoirs, and more specifically to a new method for improving the complexity of far-well fractures by staged fracturing of horizontal wells in unconventional oil and gas reservoirs. Background Art

[0002] At present, the horizontal well staged fracturing technology has been widely used in sandstone, carbonate rock, shale, coal seam and geothermal fields. The staged fracturing processes include open hole sliding sleeve staged fracturing, casing bridge plug perforation staged fracturing, hydraulic jet staged fracturing, etc. The above three staged fracturing processes are basically mature and have gained rich field construction experience. However, with the development and application of shale gas volume fracturing technology, more attention is paid to how to maximize the complexity of the fractures and, together with the multiple fractures formed by staged fracturing, greatly increase the transformation volume of the fractures.

[0003] At present, the improvement of fracture reconstruction volume has been perfected in terms of increasing the number of single fractures, fracture length and conductivity, but it is still far from enough to improve the complexity of single fractures, especially far-well fractures (near the end of the fracture). The main manifestations are: (1) the branch fractures formed on the flank of the main fracture are not complex enough or even difficult to form, and the final fracture morphology is mainly single fractures; (2) even if branch fractures are formed in the main fracture, due to the extension pressure gradient in the main fracture, the higher the viscosity of the fracturing fluid and the larger the construction displacement, the faster the extension pressure in the far-well fracture decays. In other words, the branch fractures are only formed in the main fracture. (3) Furthermore, even if branch fractures are formed within the entire length of the main fracture, the branch fractures extend longer near the wellbore and are relatively shorter in the far-wellbore area due to the rapid decrease in the extension pressure in the main fracture from the wellbore to the fracture end, which is not conducive to improving the oil and gas supply capacity in the far-wellbore area. Therefore, there is still a lot of room for improvement in the decline rate of production after compression; (4) The migration and distribution characteristics of the proppant determine that the proppant in the branch fracture close to the wellbore is the largest, and the proppant in the branch fracture is less towards the end of the fracture. This unbalanced proppant distribution characteristic is also not conducive to improving the continuous supply capacity of oil and gas in the far-wellbore area.

[0004] The reason is that as the sand-carrying fluid migrates in the main fracture, when it encounters the first branch fracture close to the wellbore, the fracturing fluid can turn and migrate to the branch fracture, while the proppant has a much greater density than the fracturing fluid and a larger inertia, making it difficult to turn and migrate to the first branch fracture. Obviously, as the sand-carrying fluid migrates toward the end of the main fracture, the fracturing fluid filtration becomes larger and larger, and finally the concentration of the sand-carrying fluid becomes higher and higher. The proppant is more likely to migrate only in the main fracture and accumulate and block at the end of the main fracture. At this time, the sand-carrying fluid injected subsequently migrates only in the branch fracture close to the wellbore. The final result is that most of the proppant migrates and is laid in one or more branch fractures close to the wellbore, making the proppant unevenly laid, affecting the overall conductivity and post-fracturing effect. Therefore, it is necessary to study and propose a new method to solve the above limitations.

[0005] Patent CN110344799A discloses a critical sand plugging fracturing method for improving the complexity of fractures. By optimizing the viscosity of the pre-fracture-making fracturing fluid to create fractures of different sizes at different stages, and optimizing the proppant dosage ratio and particle size that match the different fracture scales, a "bench-type" segment plugging sand adding mode is adopted, combined with the critical sand plugging fracturing process, to achieve an effective improvement in the net pressure and induced stress field effect of the whole process of one-time sand adding fracturing, thereby reducing the horizontal stress difference in the two directions of the formation at different positions of the main fracture, making it easier to open natural fractures or micro-cracks filled with calcium, and the main fracture turns to communicate and intersect with them, thereby maximizing the complexity of the entire fracture system and further increasing the fracture transformation volume and single well production.

[0006] Patent CN109958426A discloses a fracturing method for improving the complexity of deep shale gas fractures, which adopts a pre-placed high-viscosity liquid + low-viscosity slippery water + high-viscosity liquid mode, and uses 140-230 mesh and 70-140 mesh proppants to fill and saturate fractures of various scales, thereby achieving the purpose of improving the complexity of deep shale gas fracturing fractures and effectively transforming the volume. The patent uses a pre-placed high-viscosity liquid to promote the rapid and full extension of the main fracture in height and length; then uses low-viscosity slippery water to fully communicate and extend small fractures of various scales connected to the main fracture, and injects 140-230 mesh sand (accounting for 5-10%) with a low sand ratio; after the low-viscosity slippery water reaches the designed amount, the slippery water viscosity is increased and the displacement is gradually increased to increase multi-scale fractures; after the 140-230 mesh proppant is added, 70-140 mesh ceramsite is used until the pumping is completed, and finally the high-viscosity liquid is used to fill and saturate the main fracture with a high sand ratio.

[0007] Patent CN109689836A discloses a method for enhancing fracture complexity using a far-field diversion system, where the flow of a well treatment fluid can be diverted from a high permeability zone in a fracture network in an underground formation to a low permeability zone by using a diversion system comprising soluble diversion agent particles and proppants. At least a portion of the high permeability zone is propped open with the proppant of the diversion system, and at least a portion of the high permeability zone is blocked with the diversion agent particles. The fluid is then pumped into the underground formation and into a lower permeability zone of the formation farther from the wellbore. The diversion agent particles in the high permeability zone can then be dissolved under in-situ reservoir conditions, and hydrocarbons can be produced from the high permeability support area of ​​the fracture network. The diversion system is particularly suitable for enhancing the production of hydrocarbons from a high permeability zone in a fracture network located far from the wellbore.

[0008] Patent CN106382111A discloses a method for increasing the complexity of shale gas fracturing cracks, which reduces the viscosity of the fracturing fluid according to the increase in the formation brittleness index; controls the timing of adding sand according to the range of the length and width of the natural fracture; and increases one or more of the fracturing fluid viscosity, liquid volume, displacement, and construction sand-liquid ratio to promote multiple turns of the main fracture. In this way, the natural fractures are extended longer and wider, the main fractures are turned more times, and in the longitudinal direction, all the bedding fractures / texture fractures are opened as much as possible and extended to the maximum extent. In this way, the transformation volume of the three-dimensional fractures can be maximized in the longitudinal and transverse directions, the fracturing effect can be maximized, and the complexity of the fractures can be increased.

[0009] The document "New Fracture Steering Fracturing Technology for Improving Transformation Volume and Its Application" (Oil and Gas Geology and Recovery, 2012.5) provides a process using forced closure, rapid flowback, and multiple sand addition. That is, during the fracturing process, after adding a certain amount of proppant, the artificial fracture can reach a certain fracture length. After calculating that its stress field reaches a certain condition, stop adding sand, and perform forced closure and rapid blowdown. Due to the first proppant and forced blowdown, stress concentration occurs near the artificial fracture, causing the stress field to be redistributed, resulting in a smaller difference in the two horizontal principal stresses of the formation; during the second construction, the orientation of the artificial fracture can be turned by optimizing the construction parameters, and its turning distance is greater than the turning distance caused by continuous construction using the turning agent. In this way, the new fracture steering fracturing technology for increasing the transformation volume is realized by changing the distribution of the two horizontal stress fields in a short period of time. The core of this technical method is to reduce the difference in the two horizontal principal stresses of the formation by multiple sand additions and forced closure to achieve fracture steering.

[0010] The goal of staged fracturing of unconventional oil and gas horizontal wells is to obtain a larger transformation volume and higher conductivity. At present, the close cutting combined with multi-cluster fracturing method within the horizontal wellbore has reached the limit of the number of main fractures, but the complexity and effective support of the branch fractures in the main fractures, especially at the distal end, are far from enough, and the overall transformation volume of the reservoir needs to be improved. Summary of the invention

[0011] In order to overcome the problems existing in the prior art, the present invention provides a method for improving the complexity of far-well fractures by staged fracturing of horizontal wells, which can effectively slow down the decline rate of fracture conductivity while increasing the overall effective transformation volume of the fractures, thereby improving the initial production and stable production after fracturing.

[0012] One of the purposes of the present invention is to provide a method for improving the complexity of far-well fractures by staged fracturing of horizontal wells, comprising:

[0013] (I) When constructing the pre-fluid fracture, first inject a floating agent and a sinking agent to seal the top and bottom of the fracture, and then inject a low-density and small-particle proppant to sand-plug the ends of the fracture;

[0014] Among them, during the early stage of fracture construction of the pre-fluid, floating agent and sinking agent are first injected to seal the top and bottom of the fracture, and low-density and small-size proppant is injected in the middle and late stages of the pre-fluid to sand-plug the end of the fracture;

[0015] (II) In the sand-carrying fluid stage, ultra-low density small-size proppant is first injected, followed by medium density small-size proppant;

[0016] Among them, ultra-low density and small-size proppant is injected in the early stage of sand-carrying fluid, and medium density and small-size proppant is injected in the middle and late stage of sand-carrying fluid;

[0017] (III) Injecting large-size proppant during sand filling construction in the main fracture.

[0018] In a preferred embodiment, in step (I), low-viscosity slippery water with a viscosity of 1 mPa.s to 3 mPa.s is used for seam construction, and the displacement is first 30% to 40% of the designed maximum displacement, and then gradually increased to the designed maximum displacement.

[0019] In a further preferred embodiment, in step (I), when the amount of the front liquid reaches 10% to 15% of the design, the floating agent and the sinking agent are injected, and the construction sand-liquid ratio is 3% to 5% to 7% to 9%. The sand-liquid ratio of each section is 10m 3 ~15m 3 After injection, the pump can be stopped for 3min to 5min to ensure the effect of controlling the seam height.

[0020] The particle size of the floating agent is 140-210 mesh and the density is less than 1g / cm 3The particle size of the sinking agent is 140 mesh to 210 mesh and the density is greater than 3.2 g / cm 3 Preferably, the ratio of the floating agent to the sinking agent is (1-1.2):1, preferably 1:1.

[0021] In step (I), the viscosity of the pre-liquid is 1 mPa.s to 3 mPa.s.

[0022] In a preferred embodiment, in step (I), the apparent density of the ultra-low density small particle size proppant is 0.85 to 1.1 g / cm 3 (Preferably 1.05 g / cm 3 ), the particle size is 70 mesh to 140 mesh or 40 mesh to 70 mesh or a mixture of the two. The specific mixing ratio can be determined by indoor crack sealing experiments, and the preferred ratio of the two is 1:1.

[0023] In a further preferred embodiment, in step (I), during the late end plugging construction of the prepad, after 50% to 60% of the prepad has been injected, the ultra-low density proppant is injected, and the sand-liquid ratio of the continuous construction is 4% to 6% to 8% to 12%, and the liquid volume of each section is 10m 3 ~15m 3 .

[0024] Among them, the first sand-to-liquid ratio and liquid volume can be slightly higher than the wellbore volume of the current section to observe the pressure response characteristics of the sand-to-liquid ratio after entering the formation. If the wellhead pressure rise rate deviates from 1MPa / min, the sand-to-liquid ratio and liquid volume should be adjusted in time to ensure that the plugging position is at the end of the fracture. Plugging inside the fracture has more disadvantages than advantages. Conversely, if the end of the fracture is not blocked, the goal of generating multiple branch fractures cannot be achieved. After the pressure begins to rise according to the above requirements at this stage, it is necessary to be based on the construction pressure limit requirements and leave a pressure window of 5MPa to 7MPa. In this case, the wellhead pressure should be increased to the expected requirements as much as possible.

[0025] In a preferred embodiment, when performing the sand plugging of the fracture ends in step (I), if the original horizontal stress difference is greater than the sum of the net fracture pressure before the end plugging and the subsequent rise in wellhead pressure, the displacement should be reduced by 30% to 50%.

[0026] However, if the original horizontal stress difference is greater than the sum of the net pressure of the fracture before the end plugging and the subsequent rise in wellhead pressure, it means that branch fractures are still difficult to form. At this time, the displacement should be reduced by 30% to 50%. After the displacement is reduced, a certain pressure window is left. This pressure window plus the previous net pressure before the end of the fracture is plugged and the rising space of the pressure after plugging should exceed the original horizontal stress difference of the reservoir. Otherwise, the construction displacement should be further reduced. After the displacement is reduced, because the fracture has been completely plugged, even if the displacement is small, as long as the displacement is greater than the displacement of the natural filtration of the reservoir, the net pressure in the fracture will continue to rise. In this process, the width of the fracture will continue to increase, and the friction resistance in the fracture will be further reduced. In other words, the pressure window is increased by reducing the displacement, and the subsequent increase in the width of the fracture will slowly restore the displacement to the previous displacement, while the pressure window is still there.

[0027] In the present invention, in step (I), the main crack end plugging in the crack-making stage forms a branching seam, specifically, once the main crack end has achieved complete plugging from top to bottom, then with the continuous injection of fracturing fluid, the wellhead pressure will continue to rise rapidly, such as rising 10min, then the rising pressure is about 10MPa, at this time, the width of the crack will be increasing, under the same construction displacement, the migration speed of fracturing fluid and proppant in the crack will be decreasing, the motion inertia of proppant is also decreasing, then the possibility of proppant turning to enter the near-well branching seam will be increasing. At this time, proppant, such as still using the above-mentioned ultra-low density proppant, is more conducive to its following the fracturing fluid turning to enter the branching seam near the wellbore. Meanwhile, with the increase of the main crack width, the pressure gradient in the main crack is rapidly reduced, in other words, the extension pressure in the main crack is not much different from the end near the wellbore, therefore, once a branching seam is generated at a certain extension pressure critical point, the parameters such as the branching seam extension length and width at the main crack end should be substantially equivalent to the branching seam near the wellbore or the difference is not obvious.

[0028] The prerequisite for sealing the ends of the above main fractures is that the top and bottom of the fractures must also be completely sealed. Therefore, before injecting ultra-low density proppant to seal the ends, floating agent and sinking agent must be injected continuously.

[0029] Step (I) has ensured the formation of branch fractures. While maximizing the net pressure of the main fracture, the branch fractures should be extended. Due to the low viscosity and the reduced displacement operation, the pressure gradient in the main fracture is small, that is, the branch fractures have a nearly balanced opportunity to extend in the near well, the middle well and the far well, and the extension length and width are as close as possible.

[0030] In a preferred embodiment, in step (II), the apparent density of the ultra-low density small particle size proppant is 0.85 to 1.1 g / cm 3 , (preferably 1.05 g / cm 3 ), the particle size is 70 mesh to 140 mesh.

[0031] In a further preferred embodiment, in step (II), when injecting ultra-low density small-size proppant, in order to appropriately increase the amount of proppant, sand is added in the early stage, the sand-liquid ratio is 3% to 5% to 7%, and the liquid volume of each sand-liquid ratio section is 8 to 10 m 3 The volume ratio of the spacer fluid section to the proppant section is (0.8-1.2):1, preferably 1:1; in the middle and late stages, a continuous sand addition mode is adopted, with a sand-to-liquid ratio of 5%-7%-9%-11%, and a liquid volume of 8m 3 ~10m 3 .

[0032] In a further preferred embodiment, in step (II), when injecting the ultra-low density small-size proppant, the displacement is the optimized maximum displacement, and the viscosity of the fracturing fluid is 1 mPa.s to 3 mPa.s.

[0033] In the present invention, in step (II), proppant is evenly laid in the branch fractures far from the wellbore in the early stage of the sand-carrying fluid. Specifically, ultra-low density small-particle size (particle size 70-140 mesh) proppant is used, and a continuous sand adding mode with a higher sand-to-liquid ratio is adopted, the purpose of which is to promote the sand plugging effect of the branch fractures near the wellbore. Once the sand plugging effect appears again in the branch fractures near the wellbore, the subsequently injected proppant can only migrate and be laid in the branch fractures close to the far end of the main fracture, which is conducive to the uniform distribution of the proppant in each branch fracture.

[0034] Once the sand plugging effect occurs in the branch fracture, the amount of proppant entering the branch fracture is greatly reduced because the length of the branch fracture is smaller than that of the main fracture and the width is relatively narrow. Therefore, the sand plugging time of the branch fracture should not be too fast to allow it to absorb an appropriate amount of proppant and then sand plug. Once the sand plugging occurs, the pressure in the fracture does not rise like the sand plugging of the main fracture, but basically maintains the same pressure in the fracture because the maximum pressure at its entrance is controlled by the main fracture. At this time, with the continuous injection of fracturing fluid, the length and width of the branch fracture near the end of the main fracture will further increase.

[0035] In a preferred embodiment, in step (II), the apparent density of the medium-density small-particle proppant is 2.8 g / cm 3 Above, the particle size is 70 to 140 mesh.

[0036] In a further preferred embodiment, in step (II), when injecting medium-density small-size proppant, in order to appropriately increase the amount of proppant, sand can be added in a plug-like manner in the early stage, with a sand-to-liquid ratio of 3% to 5% to 7%, and a liquid volume of 8 to 10 m3 per sand-to-liquid ratio. 3 The volume ratio of the spacer fluid section to the proppant section is (0.8-1.2):1, preferably 1:1; in the middle and late stages, a continuous sand addition mode is adopted, with a sand-to-liquid ratio of 5%-7%-9%-11%, and a liquid volume of 8m3 ~10m 3 .

[0037] In a further preferred embodiment, in step (II), when injecting medium-density small-particle proppants, the displacement is the optimized maximum displacement, and the fracturing fluid viscosity is 9mPa.s to 12mPa.s, so as to increase the carrying capacity of the fracturing fluid for the medium-density proppants and reduce the possibility of the fracturing fluid entering the branch fractures near the wellbore.

[0038] In the present invention, in step (II), sand is normally added to the main cracks in the middle and late stages of the sand-carrying fluid stage, using a commonly used apparent density of 2.8 g / cm 3 The above small-size proppants are used to increase their flow inertia so as to achieve migration and laying in the branch fractures near the end of the main fracture.

[0039] In a preferred embodiment, in step (III), the fracturing fluid adopts a high viscosity gel of 60mPa.s to 80mPa.s.

[0040] In a further preferred embodiment, in step (III), during the first 10% to 20% of the construction, the displacement is 60% to 80% of the optimized maximum displacement to increase its ability to carry small-size proppants that may be retained in the main fracture, and then the displacement is increased to the designed maximum displacement.

[0041] Among them, in the early stage of adding sand to the main fracture, the displacement can be appropriately reduced to facilitate the above-mentioned retained small-grained proppant to be rolled away and transported to the end of the main fracture, thus avoiding its adverse effect on the conductivity of the main fracture.

[0042] In a further preferred embodiment, in step (III), a 30-50 mesh density of 3.2 g / cm 3 The above medium-density large-grained proppants have a sand-to-liquid ratio of 12% to 15% to 18% to 21% to 24%, and the liquid volume of each sand-to-liquid ratio is 15% to 25% of the main fracture volume.

[0043] In the present invention, in step (III), during the sanding stage of the main fracture, due to the high viscosity of the fracturing fluid, the large proppant particle size, and the fact that each branch fracture has basically obtained a saturated filling effect, the main sanding stage has basically no effect or little effect on the fracture support profile of each branch fracture. At the same time, more importantly, once the amount of small-particle proppant is too large during the sanding process of the branch fracture, if too much small-particle proppant is retained in the main fracture, it will greatly damage the flow conductivity of the main fracture. For this reason, in the early stage of sanding the main fracture, the displacement can be appropriately reduced to facilitate the above-mentioned retained small-particle proppant to be rolled away and transported to the end of the main fracture, thereby avoiding its adverse effect on the flow conductivity of the main fracture.

[0044] The second object of the present invention is to provide an application of the method described in the first object of the present invention in unconventional oil and gas and tight sandstone oil and gas fracturing construction.

[0045] The third object of the present invention is to provide a fracturing method for unconventional oil and gas and tight sandstone oil and gas, comprising the following steps:

[0046] 1) Evaluation of key reservoir parameters;

[0047] 2) Evaluation of geological engineering sweet spots and optimization of segment cluster locations;

[0048] 3) Optimization of crack parameters;

[0049] 4) Optimization of fracturing construction parameters;

[0050] 5) Determination of the voltage division method;

[0051] 6) Perforating operations;

[0052] 7) Acid pretreatment operations;

[0053] 8) Adopting the method described in one of the purposes of the present invention to carry out joint construction and sand adding operation;

[0054] 9) Replacement work;

[0055] 10) Fracturing construction of other sections, repeating steps 6) to 9) until all sections are constructed;

[0056] 11) Post-fracturing drilling plug, fracturing fluid flowback, testing and production.

[0057] In a preferred embodiment, in step 1), the vertical and horizontal distribution characteristics of the reservoir, lithology, whole rock minerals and sensitivity, physical properties, rock mechanical parameters and three-dimensional geostress characteristics and the minimum horizontal principal stress distribution characteristics of the reservoir and interlayer, natural fracture characteristics and horizontal bedding fracture characteristics, temperature, pressure and underground fluid properties are included. In particular, the interlayer within 50m above and below the reservoir should also be analyzed for the corresponding parameters, because the fracture height is not limited to the reservoir.

[0058] Methods such as seismic, logging, mud logging, testing and indoor testing and analysis of pilot well cores can be applied. Attention should be paid to converting dynamic parameters into static parameters, because fracturing is mainly a quasi-static process. The dynamic-static conversion relationship of each parameter can be established on the pilot well. The static parameter distribution of the horizontal section should be determined based on the analogy results of the logging parameters of the horizontal section and the logging parameters of the pilot well and the dynamic-static parameter conversion relationship established on the pilot well.

[0059] In a preferred embodiment, in step 2), based on step 1), combined with the data of neighboring wells, the commonly used geological modeling software PETROL is used to establish a fine three-dimensional geological model within the half-length and fracture height range of the horizontal wellbore and the front and back fractures in the vertical direction. Then, the geological sweet spot and the engineering sweet spot are calculated respectively according to the conventional method, and the comprehensive sweet spot index is calculated according to the equal weight method. Then, the distribution of the comprehensive sweet spot is calculated along the horizontal wellbore. A comprehensive sweet spot can be calculated for 1m in the horizontal wellbore direction. The sweet spot is the average of the calculation results of each sweet spot at that point along the entire fracture length.

[0060] Then, based on the optimized seam spacing and horizontal wellbore cementing quality in step 3), as well as the short casing collar position, the position of the segment and the position of each perforation cluster are determined (the difference in the comprehensive sweet spot of each cluster should be less than 20%). If it is an open hole completion, a total comprehensive sweet spot is calculated for each segment.

[0061] In a preferred embodiment, in step 3), the above geological model is imported into the commonly used commercial simulation software ECLIPSE for predicting the production of fractured wells, and the number of fractures, fracture length, conductivity and fracture layout (equal fracture length distribution, U-shaped distribution with long ends and short middle, W-shaped and spindle-shaped with alternating long and short fractures, etc.) are optimized according to the orthogonal design method. The parameters of branch fractures are optimized by referring to the optimization method of the main fractures.

[0062] In a preferred embodiment, in step 4), various commercial simulation software commonly used in various fracturing designs, such as MEYER, STIMPLAN, GOFHER, etc., are used, and the orthogonal design method is also used to simulate different fracturing construction parameters, such as displacement, liquid volume and the ratio of fracturing fluids with different viscosities, viscosity, proppant dosage and the ratio of proppants with different particle sizes, sand-liquid ratio and different pumping program designs, etc. At this time, the dynamic changes of fracture parameters are observed, especially to ensure the distribution of proppant at the end of the fracture, which should have a continuous length of about 10m, the top and bottom proppant concentrations are equal or equivalent, and the proppant width is close to the fracture width, with an error of less than 10%, so as to ensure the effective plugging effect of the fracture.

[0063] In a preferred embodiment, in step 5), the determination of the pressure division method mainly depends on different completion methods. The open hole horizontal well adopts the external packer plus sliding sleeve method, the cased horizontal well adopts the bridge plug and perforation method, and the liner completion adopts the hydraulic jet method.

[0064] In a preferred embodiment, in step 6), under the above three completion methods:

[0065] The open hole sliding sleeve opens the sliding sleeve through the step-by-step ball seat and the ball seat to establish a communication channel between the wellbore and the formation;

[0066] Casing cementing is carried out by lowering bridge plugs and perforating tools. The first section is lowered with coiled tubing carrying perforating guns, but no bridge plugs are lowered. The other sections are pumped to carry bridge plugs and perforating guns. After the bridge plugs reach the predetermined position, they are sealed and released. Then the perforating guns are lifted up step by step, and perforations are performed normally according to conventional perforating parameters.

[0067] There are two types of hydraulic jetting: dragging type and fixed pipe string. Both require opening the annulus spray gate to allow the jetting liquid to flow out of the annulus after perforating.

[0068] Among them, the principle of the fixed pipe string type is equivalent to the principle of the open hole sliding sleeve, except that after the sliding sleeve is opened, the open hole is the open hole section, and the fixed pipe string is only the exposed injection hole. After the jet perforation operation is completed, the sand addition operation continues, and after completion, the pipe string is dragged to the previous section for re-perforation and fracturing operations. Generally, the perforation speed required for jetting is above 130m / s, the jet sand-liquid ratio is generally 5% to 7%, and the amount of sand required for perforation is generally 1m 3 ~2m 3 .

[0069] In a preferred embodiment, in step 7), for the casing, bridge plug and perforation combination method, the acid type is generally based on the core of the direct-guide well in step 1), and different formulas are changed to experimentally study the acid-rock reaction law and optimize the acid type and formula with the highest acid dissolution rate.

[0070] Among them, step 7) is generally applied in cased wells, and other completion methods can ignore this step.

[0071] In a preferred embodiment, in step 7), the acid dosage is 10m per section. 3 ~20m 3 , the acid injection displacement is 1m 3 / min~1.5m 3 / min, after acid injection, the acid displacement is 3~6m 3 / min, and when the acid reaches the first cluster perforation position near the heel, the acid replacement displacement is reduced to the acid injection displacement to increase the acid-rock reaction time and the acid pressure drop effect.

[0072] In a further preferred embodiment, to increase the probability of uniform acid injection in multi-cluster perforations, when the acid enters 30% to 40% of the formation, the displacement is increased 1 to 2 times, each time by 30% to 40%, and the timing of increasing the displacement is allocated in proportion to the remaining acid amount.

[0073] In a preferred embodiment, in step 9), the displacement fluid volume is designed to be 105% to 110% of the wellbore volume at the current section.

[0074] In a further preferred embodiment, a high-viscosity glue with a viscosity of 60mPa.s to 80mPa.s is used in the initial 30% to 40% of the volume to reduce the sand settling effect of the horizontal wellbore and facilitate the subsequent bridge plug operation.

[0075] In a further preferred embodiment, a low-viscosity slippery water system with a viscosity of 1 mPa.s to 3 mPa.s is used later, and the displacement is the highest displacement optimized in step 4).

[0076] In view of the problem of low complexity of far-well cracks formed by unconventional oil and gas and tight sandstone oil and gas fracturing construction, the present invention uses different displacements, different viscosity slick water and glue combinations, different densities and different particle sizes of proppants, and the addition of floating agents and sinking agents, so that the upper, lower and ends of the cracks can be effectively blocked, thereby promoting the increase of the net pressure at the far end of the main crack, forming more branch cracks at the far end of the main crack, and using proppants with different particle sizes and densities to effectively support the main cracks and branch cracks, thereby improving the fracture transformation volume and conductivity as a whole. Construction according to the proposed method can effectively improve the initial production and stable production after fracturing.

[0077] The endpoints and any values ​​of the scope disclosed in the present invention are not limited to the precise scope or value, and these scopes or values ​​should be understood to include values ​​close to these scopes or values. For numerical ranges, the endpoint values ​​of each scope, the endpoint values ​​of each scope and the individual point values, and the individual point values ​​can be combined with each other to obtain one or more new numerical ranges, which should be regarded as specifically disclosed in this article. Hereinafter, in principle, each technical solution can be combined with each other to obtain a new technical solution, which should also be regarded as specifically disclosed in this article.

[0078] Compared with the prior art, the present invention has the following beneficial effects: the present invention proposes a method for improving the complexity of far-well fractures by staged fracturing of horizontal wells, which can not only form branch fractures at the proximal end of the main fracture, but also effectively form branch fractures at the distal end of the main fracture (i.e., far-well fracture), and effectively support the formed branch fractures, while increasing the overall effective transformation volume of the fracture, and effectively slowing down the rate of decrease of the fracture conductivity. Fracturing construction according to this method can achieve an increase in the fracturing transformation volume and conductivity, providing a powerful means for achieving increased and stable production of unconventional and tight oil and gas reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0079] Figure 1 A schematic diagram showing the method for increasing the complexity of far-well fractures by staged fracturing of horizontal wells according to the present invention. DETAILED DESCRIPTION

[0080] The present invention is described in detail below in conjunction with the accompanying drawings and specific embodiments. It is necessary to point out that the following embodiments are only used to further illustrate the present invention and cannot be understood as limiting the scope of protection of the present invention. Some non-essential improvements and adjustments made to the present invention by those skilled in the art based on the content of the present invention still fall within the scope of protection of the present invention.

[0081] It should also be noted that the various specific technical features described in the following specific embodiments can be combined in any suitable manner without contradiction. To avoid unnecessary repetition, the present invention will not further describe various possible combinations.

[0082] In addition, the various embodiments of the present invention may be arbitrarily combined as long as they do not violate the concept of the present invention. The technical solutions thus formed belong to part of the original disclosure of this specification and also fall within the protection scope of the present invention.

[0083] The raw materials used in the examples and comparative examples, unless otherwise specified, are disclosed in the prior art, for example, they can be directly purchased or prepared according to the preparation methods disclosed in the prior art.

[0084] [Example 1]

[0085] Well X is a sidetracked horizontal well for shale gas exploration in the Dingshan structure in the Lintanchang-Dingshan northeast structural belt in southeastern Sichuan. It has an inclined depth of 3336m, a vertical depth of 2233.68m, and a horizontal section length of 966.32m. The casing with a wall thickness of 12.34mm was completed, and the casing had an internal pressure resistance of 117.3MPa. The well encountered 301m / 22 layers of oil and gas shows of different levels. The comprehensive prediction of the pressure coefficient of the Silurian Longmaxi Formation-Upper Ordovician Wufeng Formation is 1.25-1.40, and the formation temperature in the middle of the reservoir is around 81℃. The reservoir porosity of the well is 1.22% at the minimum, 4.15% at the maximum, and 2.83% on average; the permeability is 0.004md at the minimum, 309.93md at the maximum, and 16.139md on average. The clay mineral content is 15% at the minimum, 70% at the maximum, and 45.1% on average. The brittle mineral content is 21% at the minimum, 81% at the maximum, and 48.7% on average, mainly quartz, accounting for 32.7%, followed by feldspar 5.9% and calcite 5.9%.

[0086] The specific implementation process of the well is as follows:

[0087] 1) Evaluation of key reservoir parameters

[0088] Through rock mechanics experiments, well logging interpretation, pilot well core experiments and other tests and calculations, we obtained information including lithology and rock and mineral characteristics, physical properties, sensitivity, rock mechanics parameters and three-dimensional geostress parameters, development of horizontal bedding fractures and high-angle natural fractures, and temperature, pressure and underground oil, gas and water characteristics.

[0089] 2) Calculation of geological sweet spots and engineering sweet spots and determination of segment cluster locations

[0090] According to the conventional method, the geological sweet spot and engineering sweet spot are calculated separately, and then the comprehensive sweet spot index is calculated according to the equal weight method. Avoid the layer with poor gas content, and the effective shale horizontal well section is divided into 12 sections for fracturing construction. Each section has 2 to 3 clusters of perforations, each cluster is about 1.5m, and the perforation uses 89mm gun 102 bullets, the hole density is 16 holes / m, the phase is 60°, and the perforation aperture is more than 12mm. The perforation location is selected in the middle of each stage, where TOC is high, fractures are developed, porosity and permeability are high, stress difference is small, and gas logging shows good.

[0091] 3) Optimization of crack parameters

[0092] Based on step 1), PETREL geological modeling software was used, and then the model result parameters were imported into ECLIPSE, a commercial simulation software commonly used for post-fracture production prediction of fractured wells. The optimized fracture support half-fracture length was about 280m, which would achieve better production results.

[0093] 4) Optimization of fracturing construction parameters

[0094] MEYER software was used to simulate the dynamic change of fractures under different fracturing construction parameters, and the W-type fracture layout method was optimized for this well, with an average liquid volume of 1600m per section. 3 ~1800m 3 , sand adding scale 60m 3 ~80m 3 , construction displacement 12m 3 / min~16m 3 / min.

[0095] 5) Bridge plug lowering and cluster perforation operations

[0096] Based on the segment cluster position optimized in step 2), no bridge plug is placed in the first segment, and the perforating gun is carried out by the tubing or coiled tubing to perform the perforating operation.

[0097] 6) Acid pretreatment

[0098] Based on the core of the pilot well in step 1), compatibility and acid dissolution rate experiments were carried out indoors under different acid types and formulations, and the acid type and formulation with the best compatibility and the highest acid dissolution rate were selected.

[0099] The first stage of fracturing is to inject 20m of acid3 , acid injection displacement 1.5m 3 / min, after the acid injection, the acid displacement is increased to 3m 3 When the acid enters 40% of the first cluster of cracks near the heel, increase the displacement to 6m 3 / min until all the acid has been injected.

[0100] 7) Pre-liquid seam creation and plugging construction

[0101] Low-viscosity slippery water with a viscosity of 3mPa.s is used for joint construction, and the construction displacement is 8m 3 / min. Waiting to inject 120m 3 When injecting the required floating agent and sinking agent, the construction displacement is increased to 15m 3 / min, the construction sand-liquid ratio is 3%~5%~7%~9%, and the amount of slick water in each section is 15m 3 . A total of 180m of slippery water was added during this stage. 3 .

[0102] After injecting slippery water 200m 3 After that, inject 70-140 mesh with a density of 1.05 g / cm 3 Ultra-low density proppant. Construction displacement 15m 3 / min, the construction sand-liquid ratio is 4%~6%~8%~12%, and the liquid volume per section is 15m 3 , closely observe the pressure changes during construction.

[0103] 8) Construction of branch joints supported by sand-carrying fluid

[0104] Step 7) Ensure the formation of the support seam, using a displacement of 15m 3 / min, slippery water with a viscosity of 3mPa.s carries 70-140 mesh and a density of 1.05g / cm 3 Ultra-low density proppant, added in segment plug mode, sand-liquid ratio is 3%~5%~7%, and the liquid volume of each sand-liquid ratio segment is 10m 3 , isolation fluid section 10m 3 In the middle and late stages, continuous sand addition is adopted, with a sand-to-liquid ratio of 5% to 7% to 9% to 11%, and a liquid volume of 10m 3 .

[0105] Continue to add low viscosity glue with a viscosity of 10mPa.s and carry 70-140 meshes with a density of 2.8g / cm 3 Medium density proppant, using plug-type sanding, sand-liquid ratio 3%~5%~7%, each sand-liquid ratio section liquid volume 10m 3 , isolation fluid section 10m 3In the middle and late stages, continuous sand addition is adopted, with a sand-to-liquid ratio of 5% to 7% to 9% to 11%, and a liquid volume of 10m 3 .

[0106] 9) Main crack sanding construction

[0107] Displacement: 10~12~15m 3 / min gradually increase the displacement method, using a high viscosity glue with a viscosity of 75mPa.s to carry 30-50 meshes with a density of 3.2g / cm 3 For the above medium-density proppant construction, the sand-liquid ratio is 12%~15%~18%~21%~24%. In this stage, 150m high-viscosity glue is used. 3 .

[0108] 10) Replacement work

[0109] According to the displacement viscosity of 110% of the first section of the wellbore volume, the high viscosity glue is 75mPa.s 10m 3 After that, low-viscosity slippery water with a viscosity of 3mPa.s was used to continue displacement until the construction was completed. The displacement volume of the displacement construction was 15m 3 / min

[0110] 11) For the fracturing construction of other sections, repeat steps 6) to 10) until all sections are constructed.

[0111] 12) The steps of post-fracturing drilling plug, fracturing fluid flowback, testing and production shall be carried out in accordance with conventional processes and standards and will not be repeated here.

[0112] Compared with adjacent wells, through comparative analysis of microseismic fracture monitoring results, the volume of fracture transformation increased by 27% and the post-fracturing production increased by 17% compared with adjacent wells.

[0113] [Example 2]

[0114] Well Y is another horizontal well in the Dingshan structure of the Lintanchang-Dingshan northeast structural zone in southeastern Sichuan. It has an inclined depth of 3189m, a vertical depth of 2127m, and a horizontal section length of 1255.43m. The casing with a wall thickness of 12.34mm was completed, and the casing had an internal pressure resistance of 117.3MPa. The well encountered 279m / 17 layers of oil and gas shows of different levels. The comprehensive prediction of the pressure coefficient of the Silurian Longmaxi Formation-Upper Ordovician Wufeng Formation is 1.25-1.40, and the formation temperature in the middle of the reservoir is around 78℃. The reservoir porosity of the well is 1.02% at the minimum, 3.87% at the maximum, and 2.63% on average; the permeability is 0.003md at the minimum, 279.93md at the maximum, and 14.22md on average. The average clay mineral content is 47.3%. The average brittle mineral content is 45.7%, mainly quartz, accounting for 30.4%, followed by feldspar 7.6% and calcite 8.8%.

[0115] The specific implementation process of the well is as follows:

[0116] 1) Evaluation of key reservoir parameters

[0117] Through rock mechanics experiments, well logging interpretation, pilot well core experiments and other tests and calculations, we obtained information including lithology and rock and mineral characteristics, physical properties, sensitivity, rock mechanics parameters and three-dimensional geostress parameters, development of horizontal bedding fractures and high-angle natural fractures, and temperature, pressure and underground oil, gas and water characteristics.

[0118] 2) Calculation of geological sweet spots and engineering sweet spots and determination of segment cluster locations

[0119] According to the conventional method, the geological sweet spot and engineering sweet spot are calculated separately, and then the comprehensive sweet spot index is calculated according to the equal weight method. Avoid the layer with poor gas content, and the effective shale horizontal well section is divided into 15 sections for fracturing. Each section has 2 to 3 clusters of perforations, each cluster is about 1.5m, and the perforation uses 89mm gun 102 bullets, the hole density is 16 holes / m, the phase is 60°, and the perforation aperture is more than 12mm. The perforation position is selected in the middle of each stage, where TOC is high, fractures are developed, porosity and permeability are high, stress difference is small, and gas logging shows good.

[0120] 3) Optimization of crack parameters

[0121] Based on step 1), PETREL geological modeling software was used, and then the model result parameters were imported into ECLIPSE, a commercial simulation software commonly used for post-fracture production prediction of fractured wells. The optimized fracture support half-fracture length was about 280m, which would achieve better production results.

[0122] 4) Optimization of fracturing construction parameters

[0123] MEYER software was used to simulate the dynamic changes of fractures under different fracturing construction parameters, and the W-type fracture layout method was optimized for this well, with an average liquid volume of 1800m per section. 3 ~2000m 3 , sand adding scale 70m 3 ~80m 3 , construction displacement 15m 3 / min~18m 3 / min.

[0124] 5) Bridge plug lowering and cluster perforation operations

[0125] Based on the segment cluster position optimized in step 2), no bridge plug is placed in the first segment, and the perforating gun is carried out by the tubing or coiled tubing to perform the perforating operation.

[0126] 6) Acid pretreatment

[0127] Based on the core of the pilot well in step 1), compatibility and acid dissolution rate experiments were carried out indoors under different acid types and formulations, and the acid type and formulation with the best compatibility and the highest acid dissolution rate were selected.

[0128] The first stage of fracturing is to inject 25m of acid 3 , acid injection displacement 1.2m 3 / min, after the acid injection, the acid displacement increased to 3.6m 3 When the acid enters 40% of the first cluster of cracks near the heel, increase the displacement to 6m 3 / min until all the acid has been injected.

[0129] 7) Pre-liquid seam creation and plugging construction

[0130] Low-viscosity slippery water with a viscosity of 2mPa.s is used for joint construction, and the construction displacement is 12m 3 / min. 135m to be injected 3 When injecting the required floating agent and sinking agent, the construction displacement is increased to 18m 3 / min, the construction sand-liquid ratio is 3%~5%~7%~9%, and the amount of slick water in each section is 20m 3 . A total of 220m3 of slippery water was added during this stage. 3 .

[0131] Injecting slippery water 220m 3 After that, start injecting 70-140 mesh with a density of 1.05g / cm 3 Ultra-low density proppant. Construction displacement 16m 3 / min, the construction sand-liquid ratio is 5%~7%~9%~11%, and the liquid volume per section is 20m 3 , closely observe the pressure changes during construction.

[0132] 8) Construction of branch joints supported by sand-carrying fluid

[0133] Step 7) has ensured the formation of the support seam, using a displacement of 18m 3 / min, slippery water with a viscosity of 2mPa.s carries 70-140 mesh and a density of 1.05g / cm 3 Ultra-low density proppant, added in segment plug mode, sand-liquid ratio is 3%~5%~7%, and the liquid volume of each sand-liquid ratio segment is 20m 3 , isolation fluid section 20m 3 In the middle and late stages, continuous sand addition is adopted, with a sand-to-liquid ratio of 5% to 7% to 9% to 11%, and a liquid volume of 20m 3 .

[0134] Continue to add low viscosity glue with a viscosity of 12mPa.s and carry 70-140 meshes with a density of 2.8g / cm3 Medium density proppant, using plug-type sanding, sand-liquid ratio 3%~5%~7%, each sand-liquid ratio section liquid volume 20m 3 , isolation fluid section 20m 3 In the middle and late stages, continuous sand addition is adopted, with a sand-to-liquid ratio of 5% to 7% to 9% to 11%, and a liquid volume of 20m 3 .

[0135] 9) Main crack sanding construction

[0136] Displacement: 12~15~18m 3 / min gradually increase the displacement method, using a high viscosity glue with a viscosity of 62mPa.s to carry 30-50 meshes with a density of 3.2g / cm 3 For the above medium-density proppant construction, the sand-liquid ratio is 10%~12%~15%~18%~21%. In this stage, 200m high-viscosity glue is used. 3 .

[0137] 10) Replacement work

[0138] According to the displacement viscosity of 108% of the first section of the wellbore volume, the high viscosity glue is 62mPa.s 15m 3 After that, low-viscosity slippery water with a viscosity of 2mPa.s was used to continue displacement until the construction was completed. The displacement volume of the displacement construction was 18m 3 / min

[0139] 11) For the fracturing construction of other sections, repeat steps 6) to 10) until all sections are constructed.

[0140] 12) The steps of post-fracturing drilling plug, fracturing fluid flowback, testing and production shall be carried out in accordance with conventional processes and standards and will not be repeated here.

[0141] Compared with adjacent wells, through comparative analysis of microseismic fracture monitoring results, the volume of fracture stimulation increased by 23% and the post-fracturing production increased by 11% compared with adjacent wells.

[0142] The present invention has been described in detail above in conjunction with specific implementations and exemplary examples, but these descriptions cannot be understood as limiting the present invention. Those skilled in the art understand that, without departing from the spirit and scope of the present invention, a variety of equivalent substitutions, modifications or improvements may be made to the technical solution of the present invention and its implementation methods, all of which fall within the scope of the present invention. The scope of protection of the present invention shall be subject to the attached claims.

Claims

1. A method for increasing the complexity of far-well fractures by staged fracturing of horizontal wells, comprising: (I) During the pre-fluid fracture construction, a floating agent and a sinking agent are first injected to seal the top and bottom of the fracture, and then an ultra-low density small-particle proppant is injected to sand-plug the end of the fracture; in step (I), the apparent density of the ultra-low density small-particle proppant is 0.85-1.1 g / cm 3 , the particle size is 70 mesh to 140 mesh or 40 mesh to 70 mesh or a mixture of the two; (II) In the sand-carrying fluid stage, an ultra-low density small-particle proppant is first injected, and then a medium-density small-particle proppant is injected; in step (II), the apparent density of the ultra-low density small-particle proppant is 0.85 to 1.1 g / cm 3 , the particle size is 70 mesh to 140 mesh; in step (II), the apparent density of the medium-density small-particle proppant is 2.8 g / cm 3 Above, the particle size is 70-140 mesh; (III) injecting large-size proppant during sanding construction in the main fracture; in step (III), a 30-50 mesh density of 3.2 g / cm 3 The above medium density large particle size proppants.

2. The method according to claim 1, characterized in that In step (I), the particle size of the floating agent is 140 mesh to 210 mesh and the density is less than 1g / cm 3 The particle size of the sinking agent is 140 mesh to 210 mesh and the density is greater than 3.2 g / cm 3 .

3. The method according to claim 1, characterized in that In step (I), the ratio of the floating agent to the sinking agent is (1-1.2):

1.

4. The method according to claim 2, characterized in that: In step (I), low-viscosity slippery water with a viscosity of 1 mPa.s to 3 mPa.s is used for joint construction, and the displacement is first 30% to 40% of the designed maximum displacement, and then gradually increased to the designed maximum displacement.

5. The method according to claim 2, characterized in that: In step (I), when the amount of the front liquid reaches 10% to 15% of the design, the floating agent and the sinking agent are injected, and the construction sand-liquid ratio is 3% to 5% to 7% to 9%. The sand-liquid ratio of each section is 10m 3 ~15m 3 After injection, the pump can be stopped for 3min to 5min to ensure the effect of controlling the seam height.

6. The method according to claim 1, characterized in that In step (I), after 50% to 60% of the pre-fluid volume is injected, the ultra-low density small-size proppant is injected, and the sand-liquid ratio of continuous construction is 4% to 6% to 8% to 12%, and the liquid volume of each section is 10m 3 ~15m 3 .

7. The method according to claim 1, characterized in that In step (II), when injecting ultra-low density small-size proppant, sand is added in the early stage by plugging, the sand-liquid ratio is 3% to 5% to 7%, and the liquid volume of each sand-liquid ratio section is 8 to 10m 3 The volume ratio of the spacer fluid section to the proppant section is (0.8-1.2):1; in the middle and late stages, a continuous sand addition mode is adopted, with a sand-to-liquid ratio of 5%-7%-9%-11%, and a liquid volume of 8m 3 ~10m 3 .

8. The method according to claim 1, characterized in that In step (II), when injecting medium-density small-size proppant, in order to appropriately increase the amount of proppant, sand is added in the early stage, the sand-liquid ratio is 3% to 5% to 7%, and the liquid volume of each sand-liquid ratio section is 8 to 10m 3 The volume ratio of the spacer fluid section to the proppant section is (0.8-1.2):1; in the middle and late stages, a continuous sand addition mode is adopted, with a sand-to-liquid ratio of 5%-7%-9%-11%, and a liquid volume of 8m 3 ~10m 3 .

9. The method according to any one of claims 1 to 8, characterized in that: In step (II), when injecting ultra-low density small-size proppant, the displacement is the optimized maximum displacement, and the fracturing fluid viscosity is 1 mPa.s to 3 mPa.s; and / or In step (II), when injecting medium-density small-size proppant, the displacement is the optimized maximum displacement, and the viscosity of the fracturing fluid is 9 mPa.s to 12 mPa.s.

10. The method according to claim 9, characterized in that In step (III), the fracturing fluid uses a high viscosity gel of 60mPa.s to 80mPa.s.

11. The method according to claim 9, characterized in that In step (III), during the first 10% to 20% of the construction period, the displacement is 60% to 80% of the optimized maximum displacement.

12. The method according to claim 9, characterized in that In step (III), the sand-to-liquid ratio is 12% to 15% to 18% to 21% to 24%, and the amount of liquid in each sand-to-liquid ratio is 15% to 25% of the volume of the main fracture.

13. Application of the method for increasing the complexity of far-well fractures by staged horizontal well fracturing as claimed in any one of claims 1 to 12 in unconventional oil and gas and tight sandstone oil and gas fracturing construction.

14. A fracturing method for unconventional oil and gas and tight sandstone oil and gas, comprising the following steps: 1) Evaluation of key reservoir parameters; 2) Evaluation of geological engineering sweet spots and optimization of segment cluster locations; 3) Optimization of crack parameters; 4) Optimization of fracturing construction parameters; 5) Determination of the voltage division method; 6) Perforating operations; 7) Acid pretreatment operations; 8) Using the method of increasing the complexity of far-well fractures by staged fracturing of horizontal wells as described in any one of claims 1 to 12 to perform fracture construction and sand addition operations; 9) Replacement work; 10) Fracturing construction of other sections, repeating steps 6) to 9) until all sections are constructed; 11) Post-fracturing drilling plug, fracturing fluid flowback, testing and production.

15. The fracturing method according to claim 14, characterized in that: In step 7), the acid dosage is 10m per section. 3 ~20m 3 , the acid injection displacement is 1m 3 / min~1.5m 3 / min, after acid injection, the acid displacement is 3~6m 3 / min, and when the acid reaches the first cluster of perforations near the heel, the acid replacement displacement is reduced to the acid injection displacement.

16. The fracturing method according to claim 14, characterized in that: When the acid has entered the formation by 30% to 40%, increase the displacement in 1 to 2 times, each time by 30% to 40%.

17. The fracturing method according to any one of claims 14 to 16, characterized in that: In step 9), the displacement fluid volume is designed to be 105% to 110% of the wellbore volume at that section.

18. The fracturing method according to claim 17, characterized in that: In the early stage, 30% to 40% of the volume uses a high-viscosity glue with a viscosity of 60mPa.s to 80mPa.s, and in the later stage, it is replaced with a low-viscosity slippery water system with a viscosity of 1mPa.s to 3mPa.s. The displacement takes the highest displacement optimized in step 4).

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