CN113530513B - Fracturing method for graded support of proppants with different particle sizes in multi-scale fracture - Google Patents
Fracturing method for graded support of proppants with different particle sizes in multi-scale fracture Download PDFInfo
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- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
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- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
- E21B43/261—Separate steps of (1) cementing, plugging or consolidating and (2) fracturing or attacking the formation
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- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
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Abstract
The invention discloses a fracturing method for graded support of proppants with different particle sizes in multi-scale fractures, which comprises the following steps: 1) Performing perforation operation; 2) Acid pretreatment operation; 3) Injecting fracturing fluid to make a main crack; 4) Injecting a plugging agent to plug the end part of the main crack; 5) Injecting fracturing fluid to make branch seams; 6) Injecting a plugging agent to plug the end part of the branch seam; 7) Injecting fracturing fluid to make micro cracks; 8) Injecting low-viscosity fracturing fluid carrying small-particle size proppant; 9) Injecting medium-viscosity fracturing fluid carrying medium-particle size proppant; 10 Repeating the step 3 to the step 9 for a plurality of times; 11 Injecting a high viscosity fracturing fluid carrying a large particle size proppant; 12 A replacement operation; 13 Loading a bridge plug, and repeating the steps 1 to 11 until all sections are constructed. The invention adopts the strategy of sequentially and temporarily blocking the large-scale main cracks and the medium-scale branch cracks and matching the main cracks, the steering branch cracks and the micro cracks, thereby promoting the full extension of the main cracks, the steering branch cracks and the micro cracks.
Description
Technical Field
The invention relates to a shale gas reservoir yield increase technology, in particular to a fracturing method for graded support of proppants with different particle sizes in multi-scale fractures.
Background
The shale gas resource in China has great potential and the recoverable resource amount is about 26 multiplied by 10 12 m 3 Roughly equivalent to the united states. Only two sets of shales of the Hanwu system and the Zhi mu system in the Sichuan basin have the resource amount which is 1.5 to 2.5 times of the conventional natural gas resource amount of the basin. However, shale gas reservoirs are low pore and low permeability, and industrial gas flow can be obtained only through hydraulic fracturing operation. Therefore, the reasonable and effective hydraulic fracturing operation has great significance for commercial development of shale gas in China.
At present, the main technology adopted by shale gas development is a mixed fracturing idea, namely low-viscosity fracturing fluid and high-viscosity fracturing fluid are sequentially injected or alternately injected, and then small-particle size proppant (generally 70-140 meshes or 80-120 meshes), medium-particle size proppant (generally 40-70 meshes) and large-particle size proppant (generally 30-50 meshes) are sequentially injected. The method aims to generate main cracks through high-viscosity fracturing fluid and generate diverted branch cracks and micro cracks through low-viscosity fracturing fluid, and on the basis, small-particle-size propping agent, medium-particle-size propping agent and large-particle-size propping agent are moved and laid in the micro cracks, the diverted branch cracks and the main cracks in sequence. However, in the actual construction process, the staged saturated filling of the proppants with different particle sizes in the multi-scale fracture is difficult to realize. This is because the branch fractures and the micro-fractures are difficult to extend due to high extension resistance, and the three-particle size proppant is more likely to migrate and settle in the main fractures. Under the condition, the multi-particle-size propping agents are mixed in the main fracture, so that the flow conductivity of the fracture network and the shale gas reservoir transformation efficiency are seriously influenced. In view of this, a new fracturing method is needed to promote full development of fractures of various sizes, fully transport and efficiently lay proppants of various particle sizes in the fractures, so that adverse effects of mixed distribution of the proppants of different particle sizes in the main fractures are reduced to the maximum extent, the diversion capability of a fracture network is finally improved, and the effective reconstruction volume is further increased.
Chinese patent CN107481158A discloses a method for calculating the effective reservoir transformation volume of shale gas, which comprises the steps of calculating the effective support volume of three fractures, namely a main fracturing fracture, a branch fracture and a micro fracture communicated with the branch fracture according to shale stratum key parameters; and multiplying the respective retention rates of the three fractures by the corresponding effective support volumes respectively and adding the retention rates to obtain the effective reservoir reconstruction volume of the shale gas. The method has the advantages of reasonable design, simple method and convenient operation, can accurately calculate the effective reconstruction volume of the artificial fracture, and can accurately determine the actual post-compression reconstruction effect of the shale reservoir. However, it is not concerned with how to achieve graded propping of different particle size proppants in a multi-scale fracture.
Chinese patent CN107545088A discloses a volume fracturing method for an atmospheric pressure shale gas horizontal well, which comprises the following steps: a compressibility evaluation step; optimizing crack parameters; optimizing perforation parameters; a crack communication optimization step; optimizing fracturing construction parameters; optimizing parameters of the proppant; and optimizing the back-flow parameters after pressing. The invention can improve the development technical level and economic benefit of the normal pressure shale gas reservoir. However, the method is mainly suitable for normal-pressure shale gas reservoirs, does not consider the graded filling of the proppants with different particle sizes in the multi-scale fractures, and has certain technical limitations.
Chinese patent CN106567702A relates to a method for improving deep shale gas crack complexity index. According to the method, when the deep shale gas well is fractured, the fracturing fluid selection and injection mode, the proppant selection, the cluster perforation number and other technological methods are optimally designed and controlled, so that the artificial main fractures are opened as much as possible in the extending process and communicate with natural fractures in the stratum; the single fracture is extended longer and expanded more widely, and finally the purpose of improving the complexity of the fracturing fracture of the shale gas well to the maximum extent is achieved. The method mainly aims at a deep shale gas reservoir which has a burial depth of more than 3500m, is distributed with natural cracks filled with carbonate minerals in an artificial main crack modification range, and has a certain included angle between a fracturing main crack and the natural cracks. The method has the advantages of reasonable design, simple process, convenient operation and high fracturing construction success rate, can effectively increase the volume of the deep shale gas staged fracturing crack, and obviously improves the fracturing construction effect, thereby obtaining greater economic benefit. The invention provides an analysis method for shale reservoir compressibility, but the invention does not relate to graded filling of proppants with different particle sizes in multi-scale fractures, and also has certain technical limitations.
Disclosure of Invention
In order to solve the problem that the existing proppants with different particle sizes are not uniformly laid in the multi-scale fractures, the invention provides a novel fracturing method for realizing graded support of the proppants with different particle sizes in the multi-scale fractures.
The technical idea of the invention is as follows:
(1) When the horizontal main stress difference is large, the extension resistance of the main crack is greatly lower than that of the branch crack, so that a large amount of fracturing fluid flows into the main crack, and the natural crack is difficult to fully open. Aiming at the problem, the invention adopts a fracturing process of multiple grading temporary plugging, improves the complexity of the fracture and specifically comprises the following steps: after the main crack extends for a certain distance, injecting a large-particle-size soluble temporary plugging agent to block the end part of the main crack, so that the fluid is forced to turn to generate a new branch crack system; after the branch seams extend for a certain distance, injecting a plugging agent to block the branch seams, and fully activating the microcracks by adopting low-viscosity slick water and promoting the extension of the microcracks. The method can realize the sequential opening of the main crack-branch crack-micro crack three-level crack system, reduce and even avoid the conditions that multiple cracks compete and branch cracks are difficult to fully extend during the fracturing of the conventional shale gas well, and further greatly improve the complexity of the cracks;
(2) The temporary plugging agent for plugging the end part of the branch crack is a soluble temporary plugging agent, the dissolving time is controllable within 3-30min (preferably 20-25 min), and the temporary plugging agent is required to be dissolved after sand is added to the micro crack for filling and completely dissolved within 3-30min, so that on one hand, after the natural crack is fully activated by adopting low-viscosity slickwater, the branch crack and the main crack are blocked, the flow channel is mainly the micro crack, and fracturing fluid carrying the small-particle-size propping agent can flow into the micro crack under the condition, thereby being beneficial to realizing saturated filling of the micro crack; on the other hand, the soluble temporary plugging agent is adopted, so that the phenomenon that the construction pressure is too high due to the fact that the main cracks and the branch cracks are completely plugged when the temporary plugging agent is excessively added can be avoided, and the construction risk is greatly reduced;
(3) The designed dissolution time of the temporary plugging agent at the end part of the main crack is controllable within 3-40min (preferably 30-40 min), and the temporary plugging agent is required to be completely dissolved after sand filling is carried out on the branch crack. Therefore, on one hand, after the temporary plugging agent at the end of the branch crack is dissolved, the large-particle-size temporary plugging agent is not completely dissolved in the main crack, the flow resistance is higher, and the small-particle-size proppant is filled in the micro crack, and the flow channel is mainly the branch crack with the dissolved temporary plugging agent at the end of the crack, so that the effective filling of the branch crack can be realized by injecting fracturing fluid carrying the small-particle-size proppant, and meanwhile, the small-particle-size proppant injected previously can be replaced into the micro crack; on the other hand, after the graded temporary plugging fracturing process is adopted for multiple times, the temporary plugging agent in the main fracture is fully dissolved, the branch fractures and the micro fractures are filled with the propping agents with different particle sizes, the flowing resistance is large, and at the moment, fracturing fluid with the propping agents can be injected to carry out sand fracturing operation on the main fracture.
The invention aims to provide a fracturing method for graded propping of proppants with different particle sizes in a multi-scale fracture, which comprises the following steps:
and step 1, perforating operation.
In a preferred embodiment, in step 1, the perforating gun is carried by the first length of coiled tubing. And the rest sections adopt a pumping mode, carry a bridge plug and a perforating gun combined tool string, after the bridge plug is lowered to a preset position, seat sealing, releasing, gradually lifting the perforating gun to a preset perforation position, after perforation is finished, lifting the perforating gun, and pouring acid.
In a preferred embodiment, step 1 is preceded by the following steps:
step 1-1, analyzing compressibility, mechanical property and fracturing quality of the shale.
According to the invention, the step 1-1 comprises lithology, physical property, gas content, rock mechanics and three-dimensional ground stress parameters, horizontal bedding and high-angle natural fracture characteristics, temperature, pressure and other data within the range of 50m above and below the target layer. The calculation method mainly comprises the steps of carrying out physical and mechanical experiments on the core of the target layer of the pilot hole well under the conditions of simulated actual pressure and temperature and the logging result of a horizontal section, wherein the analogy of the logging parameters of the horizontal section can refer to the conversion relation between the logging dynamic parameters and the core testing static parameters established on the pilot hole well.
And 1-2, optimizing the positions of the engineering dessert and the segment clusters.
According to the invention, in the step 1-2, on the basis of the step 1-1, a conventional geological dessert and engineering dessert calculating method is applied, and the comprehensive dessert index is calculated according to an equal weight method. The section length is 50-90 m, the section spacing is 20-30 m, 2-4 clusters are arranged in the section, and the comprehensive dessert index difference of each cluster in the section is less than 20%, and the positions of the cluster in the section are comprehensively balanced by combining the well cementation quality, the coupling position and the like.
And 1-3, optimizing crack parameters.
According to the invention, in the step 1-3, on the basis of the step 1-1 and the step 1-2, a fine geological model is established by combining adjacent well data and using PETREL commercial software, model parameters are led into commercial simulation software ECLIPSE commonly used for fracturing well yield prediction, hydraulic support fractures are arranged according to an equivalent flow conductivity method, the post-pressing production dynamics under different fracture lengths, fracture intervals and flow conductivity are simulated according to an orthogonal design method, and the fracture parameter system corresponding to the relatively highest post-pressing yield or the largest economic net present value is the optimal fracture parameters. The simulation difficulty of the steering branch seam and the micro-crack is considered to be high, and the calculation can be simplified.
And 1-4, optimizing fracturing construction parameters.
According to the invention, in the steps 1-4, the change of the fracture geometric size and the flow conductivity under different fracture construction parameter conditions (discharge capacity, liquid amount, fracturing fluid occupation ratio with different viscosities, proppant amount, proppant occupation ratio with different particle sizes, sand-liquid ratio, injection program and the like) is simulated by using commercial simulation software commonly used for fracture optimization design, such as FracPro PT, stimplan, gohfer and the like, according to an orthogonal design method, and the fracture construction parameter combination corresponding to the optimal fracture parameter in the step (3) can be preferably obtained, namely the optimal fracture construction parameter.
And 1-5, preparing blocking agents with different particle sizes and soluble time.
According to the invention, in the steps 1-5, temporary plugging materials with different particle sizes and soluble time are prepared to ensure that the subsequent fracturing construction is not influenced while the plugging operation is finished. The blocking agent can be prepared by itself according to the methods of the prior art or can be purchased directly.
And 2, performing acid pretreatment operation.
In the step 2, the acid type and the formula can be determined according to the experimental result of the pilot hole core in the step 1-1.
In a preferred embodiment, in step 2, the amount of acid is from 10 to 20m 3 The discharge capacity of the acid injection is 1 to 1.5m 3 /min。
In a further preferred embodiment, after the acid injection is finished, the acid is replaced by low-viscosity slickwater with the viscosity of 1-3 mPa.s, and the displacement of the acid is 3-6 m 3 /min。
In a further preferred embodiment, after the acid enters the first blasthole close to the target point A, the displacement of the acid substitute is reduced to the displacement of the acid injection (1-1.5 m) 3 /min) to increase the acid rock reaction time; preferably, after 30-40% of acid enters the stratum, the acid displacement is increased for 1-2 times, and the amplification is increased by 50-100% each time.
And 3, injecting fracturing fluid to make a main crack.
In a preferred embodiment, in step 3, a low viscosity slickwater with a viscosity of 1 to 3mpa.s is used to initiate the fracture.
Wherein, the low-viscosity slick water is easier to permeate into the branch seams and the micro cracks, which is beneficial to communicating and activating the branch seams. The invention is characterized in that a main seam communicated with a multi-branch seam is required to be established, and therefore, the main seam is made by adopting low-viscosity slick water. At the same time. The low-viscosity slick water seam forming has narrower seam width, and can also reduce the difficulty of temporary plugging of the main seam. Therefore, the low-viscosity slickwater has technical advantages on opening the branch seams and the micro cracks, and the low-viscosity slickwater is required to be adopted when the branch seams and the micro cracks are manufactured.
In a further preferred embodiment, in step 3, the volume of the low-viscosity slickwater is obtained by averaging the volumes of the fracturing fluid optimized in the steps 1-4 and the times of graded temporary plugging, and the displacement is the highest value under construction pressure limit, such as 14-18 m 3 /min。
And 4, injecting a plugging agent to plug the end part of the main crack.
Wherein, the average particle size and the particle size range of the plugging agent can be determined on the basis of an indoor plugging experiment.
In a preferred embodiment, in step 4, the particle size of the blocking agent is 60-80 mesh, and the dissolution time is preferably 3-40min, more preferably 30-40 min.
Meanwhile, the dissolving time of the plugging agent depends on the particle size of the plugging agent, the dissolving time is longer when the particle size is large, and the dissolving time is shorter when the particle size is small.
In a preferred embodiment, in step 4, injecting a high-viscosity glue solution carrying a plugging agent, wherein the viscosity of the high-viscosity glue solution is 40-50mPa.s, so as to plug the end part of the main crack.
Wherein, in order to increase the suspending and plugging effect of the plugging agent in the longitudinal direction, the viscosity of the carrier fluid carrying the plugging agent is 40-50mPa.s.
In a further preferred embodiment, in the step 4, the sand-liquid ratio of the blocking agent is 30-40%, and the volume of the high-viscosity glue liquid is 1-3 m 3 。
According to the invention, in the step 4, the construction pressure response characteristic is observed, if the pressure amplitude is less than 1MPa/min, the concentration of the carried plugging agent is increased until the plugging requirement is met.
According to the invention, in the step 4, the volume of the fracturing fluid before the plugging agent is added is calculated according to the volume balance method and the design length of the crack of 20-30% and the efficiency of the fracturing fluid of 20-30% according to the steps 1-3.
And 5, injecting fracturing fluid to make branch seams.
In a preferred embodiment, in step 5, a low viscosity slickwater with a viscosity of 1 to 3mpa.s is used to make the diversion branch seam.
In a further preferred embodiment, in step 5, the injection volume is 5 branch cracks, the length of each branch crack is 10% of the length of the optimized main crack in steps 1-3, the crack height is the height of the main crack or the top and bottom thickness of a fracturing target stratum, and the fracturing fluid efficiency is calculated to be 20-30%. The displacement is taken to be the highest value under limited pressure.
And 6, injecting a plugging agent to plug the end part of the branch seam.
In a preferred embodiment, in step 6, the particle size of the blocking agent is 100-200 mesh, and the dissolution time is preferably 3-30min, preferably 20-25 min.
In a preferred embodiment, in step 6, a high-viscosity slickwater carrying a blocking agent is injected to block the branch seam end part, and the viscosity of the high-viscosity slickwater is 10-15mpa.s.
In step 6, the average particle size and the range of the particle size of the temporary plugging agent for temporary plugging at the end part of the branch seam mainly refer to the main crack, the width difference of the branch seam and the indoor temporary plugging experimental result.
In a further preferred embodiment, in step 6, the sand-liquid ratio of the blocking agent is 30-40%, and the volume of the high-viscosity slickwater is 1-3 m 3 。
In a preferred embodiment, in step 6, the construction pressure response characteristic is observed, for example, the pressure rise is less than 0.2-0.3 MPa/min, and the concentration of the carried plugging agent is increased until the plugging requirement is met.
And 7, injecting fracturing fluid to make micro cracks.
In a preferred embodiment, in step 7, microcracking is created using low viscosity slickwater having a viscosity of 1 to 3mpa.s.
In a preferred embodiment, in step 7, the volume of fracturing fluid is the volume of fracturing fluid that created the diverting branch seam calculated in step 5.
In a further preferred embodiment, in step 7, the displacement is taken to be 40% to 60% of the optimized displacement in step 5 to ensure adequate communication with the microfracture system.
And 8, injecting a low-viscosity fracturing fluid carrying a small-particle-size propping agent, wherein the particle size of the small-particle-size propping agent is 140-210 meshes or 70-140 meshes, and the viscosity of the low-viscosity fracturing fluid is 2-3 mPa.s.
In a preferred embodiment, in step 8, the maximum displacement is taken under the construction pressure limit.
When the particle size of the propping agent is 140-210 meshes, sand is added in a continuous sand adding mode, the sand carrying liquid volume is 5-7 times of the volume of a shaft, the sand-liquid ratio is 1-2% of the initial sand-liquid ratio, then the sand-liquid ratio of each section is sequentially increased by 1-2%, and the volume of the sand carrying liquid under each sand-liquid ratio is 0.7-1.2 shaft volumes;
in a further preferred embodiment, when the particle size of the proppant is 70-140 meshes, 5-7 sections of slug type sand adding are adopted, the initial sand-liquid ratio is 1-2%, then the sand-liquid ratio of each section is sequentially increased by 1-2%, and the volume of the sand-carrying liquid at each sand-liquid ratio is 0.7-1.2 wellbore volumes. Preferably, 2 consecutive sand-liquid ratios are combined into one long slug.
In a further preferred embodiment, when the particle size of the proppant is 70-140 mesh, the sand-to-fluid ratio is 1% -2% -3% -5% -7% -9%, and the volume of the sand-carrying fluid at each sand-to-fluid ratio is generally the volume of the wellbore.
According to the invention, in the step 8, if the pressure response characteristic is not obvious after each sand-liquid ratio enters the stratum, the sand-liquid ratio can be properly increased so as to realize the full filling of the propping agent in the microcracks and the propping agent sealing effect at the seam openings, thereby avoiding the adverse effect of subsequent construction on the propping agent.
According to the invention, in the step 8, after the small-particle size proppant enters the stratum, the temporary plugging agent turned to the end part of the branch seam is completely dissolved within 1-2 min.
Wherein, the 1-2 min means that the temporary plugging agent at the end part of the branch seam is completely dissolved after the small-particle size proppant enters the stratum in the step 8 within 1-2 min, and the overall dissolving time is 3-30min, preferably 20-25 min.
And 9, injecting medium-viscosity fracturing fluid carrying medium-particle size proppant, wherein the particle size of the medium-particle size proppant is 40-70 meshes, and the viscosity of the low-viscosity fracturing fluid is 5-7 mPa.s.
In a preferred embodiment, in step 9, the displacement is taken to be the highest value under construction pressure limit.
In a preferred embodiment, in step 9, 5 to 7 sections of slug-type sand feeding are adopted, the initial sand-liquid ratio is 4 to 6 percent, then the sand-liquid ratio of each section is sequentially increased by 1 to 3 percent, and the volume of the sand-carrying liquid at each sand-liquid ratio is 0.2 to 0.5 shaft volume.
In a further preferred embodiment, in step 9, the sand adding mode is a slug type sand adding mode, the sand-liquid ratio is 5% -7% -9% -11% -13% -15%, and the volume of the sand-carrying liquid corresponding to each sand-liquid ratio is 0.25-0.4 shaft volume.
In a further preferred embodiment, in step 9, the construction is performed according to long section plugs, the section plug corresponding to the first 3 sand-liquid ratios is the 1 st section plug, the section plug corresponding to the last 3 sand-liquid ratios is the 2 nd section plug, and the middle spacer fluid takes 0.8 to 1.2 current section well bore volumes.
According to the invention, in the step 9, if the pressure response characteristic is not obvious after each sand-liquid ratio enters the stratum, the sand-liquid ratio can be properly increased so as to realize the full filling of the propping agent in the microcracks and the propping agent sealing effect at the seam openings and avoid the adverse effect of subsequent construction on the propping agent.
According to the invention, in the step 9, the temporary plugging agent in the main crack is required to be dissolved immediately after the construction is finished.
And 10, repeating the steps 3 to 9 for multiple times, preferably twice.
And 11, injecting a high-viscosity fracturing fluid carrying a large-particle-size propping agent, wherein the particle size of the large-particle-size propping agent is 30-50 meshes or 20-40 meshes, and the viscosity of the high-viscosity fracturing fluid is 40-50mPa.s.
According to the invention, in step 11, before the construction of the section, it is ensured that the temporary plugging agent is completely dissolved in the last main fracture.
In a preferred embodiment, in step 11, the maximum displacement is taken under construction pressure limits.
In a preferred embodiment, in step 11, continuous sand addition is performed for 5 to 7 times, the sand-to-liquid ratio of the first sand addition is 14 to 16%, and then each time the sand addition is increased by 2 to 4%.
In a more preferred embodiment, continuous addition of sand is used in step 11, with a sand to liquid ratio of 15 to 18 to 21 to 24 to 27 to 30%.
In order to ensure the full filling of the propping agent in the main fracture and avoid the scouring effect of the follow-up fracturing fluid on the flow conductivity of the fracture, the sand can be continuously added, the sand-liquid ratio is generally 15-18-21-24-27-30%, the viscosity of the fracturing fluid is 40-50mPa.s, and the discharge capacity is the highest value under construction pressure limitation.
And step 12, replacing operation.
In a preferred embodiment, in step 12, a high viscosity fracturing fluid and a low viscosity slickwater are used for displacement, wherein the viscosity of the high viscosity fracturing fluid is 40-50mpa.s, and the viscosity of the low viscosity slickwater is 1-2mpa.s.
In a further preferred embodiment, in step 12, the volume of displacement fluid is taken to be 110-130% of the volume of the current wellbore.
In a further preferred embodiment, in step 12, the first 30-40% of the displacement fluid is a high-viscosity fracturing fluid, which mainly functions to clean the settled sand in the horizontal wellbore to avoid adverse effects on subsequent operations such as bridge plug setting and the like, and the subsequent displacement fluid is low-viscosity slickwater. The displacement is taken to be the highest value under limited pressure.
And step 13, inserting the bridge plug, and repeating the step 1 to the step 11 until all sections of construction are completed.
And step 14, drilling and plugging after pressing, flowback, testing and production solving.
Compared with the prior art, the invention has the following beneficial effects:
(1) The large-scale main cracks and the medium-scale branch cracks are adopted for temporary blocking in sequence, so that the full extension of the main cracks, the turning branch cracks and the micro cracks is promoted, the fracturing swept range is expanded, the modification volume is increased, and the utilization degree of the shale gas reservoir is finally improved;
(2) Multilevel plugging is adopted from the seam opening to the seam end in the main crack, and the strategy of temporary plugging of the main crack, the turning branch crack and the micro-crack in sequence is matched, so that the saturated filling of the three grain size proppants on the cracks with different scales is promoted, and the flow conductivity of the crack network is greatly improved;
(3) The main cracks, the turning branch cracks and the micro cracks are sequentially and temporarily blocked, so that the doping and mixing of three kinds of particle size propping agents in the main cracks and a few branch cracks are reduced and even avoided, and the damage of the mixture of the propping agents with different particle sizes to the flow guiding capacity of the main cracks is reduced, thereby being beneficial to improving the stable yield capacity of the shale gas well.
Drawings
Fig. 1 shows a schematic flow diagram of the method according to the invention.
Detailed Description
While the present invention will be described in detail with reference to the following examples, it should be understood that the following examples are illustrative of the present invention and are not to be construed as limiting the scope of the present invention.
The raw materials used in the examples and comparative examples are disclosed in the prior art if not particularly limited, and may be, for example, directly purchased or prepared according to the preparation methods disclosed in the prior art.
[ example 1 ]
The vertical depth of a shale gas well in the south of Sichuan is 2180m, the sounding depth is 3970m, and the horizontal section is 1200m. The method is characterized by comprising the following steps:
(1) Analyzing the compressibility, mechanical properties and fracturing quality of shale, optimizing the positions of engineering desserts and segment clusters, performing simulation optimization based on conventional flow to determine the optimal fracturing segment to be 19 segments, the optimal fracture half-length to be 300m and the single-segment sand amount scale to be 100m, on the basis of common commercial simulation software ECLIPSE for predicting fracturing yield and common commercial simulation software MEYEY for simulating fracture propagation 3 2 clusters of single section, the length of each cluster of perforation is 1.5m, the perforation density is 16 holes/m, and the optimized fracturing is realizedAnd (5) construction parameters.
(2) After the continuous oil pipe is adopted to carry the perforating gun to complete the first section of perforating operation, the length of the perforating gun is 1m 3 Permin discharge capacity co-injection pretreatment acid 10m 3 . Then at 4m 3 Injecting low viscosity slickwater (2mPa.s) 35m into the mixed solution at a delivery rate of/min 3 And (4) replacing acid. Then continuously injecting (2mPa.s) low-viscosity slickwater 10m 3 Displacing acid while reducing the discharge to 1m 3 Min to increase the acid rock reaction time. Then the displacement is increased to 2m in turn 3 Min and 4m 3 And/min, so as to ensure that the residual acid liquor can enter the rest perforation clusters.
(3) Adopting low-viscosity slickwater to make main seam, its viscosity is 2mPa.s, and its quick-raising discharge capacity is up to 16m 3 /min。
(4) Injecting high viscosity glue solution (viscosity is 40mPa.s) containing 60-80 mesh blocking agent, and adding the blocking agent into the glue solution at a ratio of 35% to 1.05m 3 The dissolution time is about 40min, and the total high-viscosity glue solution is 3m 3 。
(5) Low viscosity 85m of 2 mPa.s-infused slick water 3 . In the injection process, when the 60-80 mesh plugging agent reaches the end of the seam, the discharge capacity is reduced to 2m 3 And/min. The pressure begins to rise, and the pressure acceleration rate is about 1.1MPa/min, which indicates that the end part of the crack is successfully plugged. Then the displacement is lifted to 16m 3 /min。
(6) Injecting high viscosity slickwater (viscosity is 15mPa.s) containing 100-200 mesh blocking agent, adding blocking agent into the solution at a ratio of 35% to 1.05m 3 The dissolution time is about 25min, and the high-viscosity slick water is 3m 3 。
(7) Low viscosity 85m of 2 mPa.s-infused slick water 3 . In the injection process, when the 100-200 mesh plugging agent reaches the end of the seam, the discharge capacity is reduced to 2m 3 And/min. The pressure begins to rise, and the pressure acceleration rate is about 0.25MPa/min, which indicates that the end part of the crack is successfully plugged. Then the displacement is lifted to 16m 3 /min。
(8) Injecting 3mPa.s low-viscosity slickwater containing 140-210 meshes of propping agent, and continuously adding the 140-230 meshes of propping agent into the slickwater at a sand ratio of 1-2-3-5-7-9% to form a solution with a thickness of 12.15m 3 The amount of the single-section slug sand-carrying liquid under each sand ratio is 45m 3 。
(9) Injecting medium-viscosity slickwater containing 40-70 meshes of propping agent, wherein the viscosity of the slickwater is 5mPa.s. Adding 40-70 mesh proppant into 10.4m proppant in a slug manner according to the sand-liquid ratio of 5-7-9-11-13-15 percent 3 . The amount of the sand-carrying liquid at each sand ratio is 25m 3 、20m 3 、15m 3 、20m 3 、15m 3 、15m 3 Totally divided into 2 sand-carrying liquid slugs, the first 3 sand-liquid ratios are the 1 st sand-carrying liquid slug, the last 3 sand-liquid ratios are the 2 nd sand-carrying liquid slug, and the liquid amount of the isolation liquid is 45m 3 。
(10) And (5) repeating the steps (3) to (9) for 2 times.
(11) Injecting high-viscosity glue solution containing 30-50 meshes of propping agent, wherein the viscosity of the fracturing fluid is 40mPa.s. Adding 30-50 mesh proppant into the mixture according to the sand-liquid ratio of 15-18-21-24-27-30% in a continuous manner to form a mixture with the particle diameter of 40.5m 3 . The amount of the sand-carrying liquid under each sand ratio is 30m 3 。
(12) Injecting a displacement fluid comprising: 26m 3 50mPa.s high-viscosity glue solution and 40m 3 1mPa.s low viscosity slickwater. Then the bridge plug is lowered.
(13) A similar process is used to perform the fracturing operation of the remaining section.
(14) Treating the flowback liquid, and discharging the oil for production.
After the well is put into production, compared with an adjacent well, the maximum gas production rate and the stable production time are higher than those of an adjacent well, which shows that the method can increase the effective modification volume of the reservoir, improve the modification efficiency of the reservoir and has extremely high application value.
[ example 2 ]
In the southwest Sichuan area, a shale gas well has a vertical depth of 2068m, a depth of 4100m and a horizontal section length of 1360m. The method is characterized by comprising the following steps:
(1) Analyzing the compressibility, mechanical properties and fracturing quality of shale, optimizing the positions of engineering desserts and segment clusters, performing simulation optimization based on conventional flow to determine the optimal fracturing segment to be 19 segments, the optimal fracture half-length to be 300m and the single-segment sand amount scale to be 100m, on the basis of common commercial simulation software ECLIPSE for predicting fracturing yield and common commercial simulation software MEYEY for simulating fracture propagation 3 2 clusters of single section, the length of each cluster of perforation is 1.5m, the perforation density is 16 holes/m, and the fracturing construction parameters are optimized.
(2) After the continuous oil pipe is adopted to carry the perforating gun to complete the first section of perforating operation, the distance between the perforating gun and the continuous oil pipe is 1.5m 3 Permin discharge capacity co-injection pretreatment acid 20m 3 . Then at 6m 3 Injecting low-viscosity slickwater (3mPa.s) 35m at a discharge rate of/min 3 And (4) replacing acid. Then continuously injecting low-viscosity slick water for 10m 3 Displacing acid while reducing the discharge to 1.5m 3 Min to increase acid rock reaction time. Then the displacement is increased to 3m in turn 3 Min and 6m 3 And/min, so as to ensure that the residual acid liquor can enter the rest perforation clusters.
(3) Adopting low-viscosity slickwater to make main seam, its viscosity is 3mPa.s, and its quick-lifting discharge capacity is up to 16m 3 /min。
(4) Injecting high viscosity glue solution (viscosity of 50mPa.s) containing 60-80 mesh blocking agent, and adding blocking agent into the glue solution at a ratio of 40% to 0.8m 3 The dissolution time is about 35min, and the total high-viscosity glue solution is 2m 3 。
(5) Low-viscosity slickwater 85m injected with 3mPa.s 3 . In the injection process, when the 60-80 mesh plugging agent reaches the end of the seam, the discharge capacity is reduced to 2m 3 And/min. The pressure begins to rise, and the pressure acceleration rate is about 1.1MPa/min, which indicates that the end part of the crack is successfully plugged. Then the displacement is lifted to 16m 3 /min。
(6) Injecting high viscosity slippery water (viscosity is 10mPa.s) containing 100-200 mesh blocking agent, and adding the blocking agent into the mixed solution at a ratio of 30% to 0.9m 3 The dissolution time is about 25min, and the high-viscosity slick water is 3m 3 。
(7) Injecting low viscosity slickwater of 1mPa.s into the mixture of 85m 3 In the injection process, when the 100-200 mesh plugging agent reaches the end of the seam, the discharge capacity is reduced to 2m 3 And/min. The pressure begins to rise, and the pressure increase rate is about 0.25MPa/min, which indicates that the end of the crack is successfully plugged. Then the displacement is lifted to 16m 3 /min。
(8) Injecting low-viscosity slick water containing 70-140 meshes of propping agent, adding 12.6m of 70-140 meshes of propping agent into the mixture in a plug manner according to the sand ratio of 1-2-3-5-7-9% 3 And the volume of each sand-carrying fluid is one shaft volume compared with the volume of the lower sand-carrying fluid.
(9) Injecting middle-viscosity slickwater containing 40-70 mesh proppant, wherein the viscosity of the slickwater is 7mPa.s. Adding 40-70 mesh proppant into proppant 9.3m in a slug manner according to the sand-liquid ratio of 5-7-9-10-12-14% 3 . The amount of the sand-carrying liquid at each sand ratio is 25m 3 、20m 3 、15m 3 、20m 3 、15m 3 、15m 3 Totally divided into 2 sand-carrying liquid slugs, the first 3 sand-liquid ratios are the 1 st sand-carrying liquid slug, the last 3 sand-liquid ratios are the 2 nd sand-carrying liquid slug, and the liquid amount of the isolation liquid is 45m 3 。
(10) And (5) repeating the steps (3) to (9) for 2 times.
(11) Injecting high-viscosity glue solution containing 20-40 mesh proppant, wherein the viscosity of the fracturing fluid is 50mPa.s. Adding the 20-40 mesh proppant into the mixture according to the sand-liquid ratio of 14-17-20-22-25-28% in a continuous manner to form a mixture with the particle diameter of 37.8m 3 . The amount of the sand-carrying liquid under each sand ratio is 30m 3 。
(12) Injecting a displacement fluid comprising: 20m 3 50mPa.s high-viscosity glue and 46m 3 Low viscosity of 2mPa.s slickwater.
(13) Then the bridge plug is lowered. A similar process is used to perform the fracturing operation of the remaining section.
(14) Treating the return liquid, and discharging, mining and evaluating the yield.
After the well is put into production, compared with an adjacent well, the maximum gas production rate and the stable production time are higher than those of an adjacent well, which shows that the method can increase the effective modification volume of the reservoir, improve the modification efficiency of the reservoir and has extremely high application value.
Comparative example 1
The procedure of example 1 was repeated except that: directly adding sand after seam making at each stage, and then temporarily blocking, specifically as follows:
(A) Directly performing the step (11) before the step (4) after the main seam is manufactured in the step (3), namely performing the step (11) between the step (3) and the step (4);
(B) Step (9) is performed directly before step (6) after the branch seam is made in step (5), i.e., step (9) is performed between step (5) and step (6).
After the well is put into operation, compared with the embodiment 1, the maximum gas production rate and the stable production time are both lower, and the maximum gas production rate is lower than 30 percent.
Claims (29)
1. A fracturing method for graded propping of proppants with different particle sizes in multi-scale fractures comprises the following steps:
step 1, perforating operation;
step 2, performing acid pretreatment operation;
step 3, injecting fracturing fluid to make a main crack;
step 4, injecting a plugging agent to plug the end part of the main crack;
step 5, injecting fracturing fluid to make branch seams;
step 6, injecting a plugging agent to plug the end part of the branch seam;
step 7, injecting fracturing fluid to make microcracks;
step 8, injecting a low-viscosity fracturing fluid carrying a small-particle-size propping agent, wherein the particle size of the small-particle-size propping agent is 140-210 meshes or 70-140 meshes, and the viscosity of the low-viscosity fracturing fluid is 1-3mPa.s;
step 9, injecting medium-viscosity fracturing fluid carrying medium-particle size proppant, wherein the particle size of the medium-particle size proppant is 40-70 meshes, and the viscosity of the medium-viscosity fracturing fluid is 5-7 mPa.s;
step 10, repeating the step 3 to the step 9 for multiple times;
step 11, injecting a high-viscosity fracturing fluid carrying a large-particle-size propping agent, wherein the particle size of the large-particle-size propping agent is 30-50 meshes or 20-40 meshes, and the viscosity of the high-viscosity fracturing fluid is 40-50mPa.s;
step 12, replacing operation;
step 13, placing a bridge plug, and repeating the steps 1 to 12 until all sections are constructed;
in step 4, injecting high-viscosity glue solution carrying a plugging agent to plug the end part of the main crack, wherein the dissolving time of the plugging agent is 3-40min;
in step 6, injecting high-viscosity slickwater carrying plugging agent to plug the end part of the branch seam, wherein the dissolving time of the plugging agent is 3-30min.
2. The fracturing method according to claim 1, characterized in that the following steps are carried out before step 1:
1-1, analyzing compressibility, mechanical property and fracturing quality of shale;
step 1-2, optimizing the positions of the engineering dessert and the segment clusters;
1-3, optimizing crack parameters;
and 1-4, optimizing fracturing construction parameters.
3. The fracturing method according to claim 1, wherein in step 2, the acid content is 10 to 20m 3 The discharge capacity of the injected acid is 1 to 1.5m 3 /min。
4. The fracturing method according to claim 3, wherein after acid injection is completed, low-viscosity slippery water with viscosity of 1 to 3mPa.s is used for replacing acid, and the discharge amount of the replaced acid is 3 to 6m 3 /min。
5. The fracturing method of claim 4, wherein after the acid enters the first blasthole close to the target A, the displacement of the acid is reduced to the displacement of the acid injection to increase the reaction time of the acid rock.
6. The fracturing method of claim 5, wherein the acid displacement is increased by 1~2 times after 30 to 40% of the acid enters the stratum, and the increase is 50 to 100% each time.
7. The fracturing method according to claim 2, wherein in step 3, the main fracture is made by using low-viscosity slickwater with viscosity of 1 to 3mPa.s.
8. The fracturing method according to claim 7, wherein the volume of the low-viscosity slickwater is obtained by averaging the volume of the fracturing fluid optimized in the steps 1-4 and the times of graded temporary plugging, and the displacement is the highest value under construction pressure limitation.
9. The fracturing method according to claim 1, wherein in step 4, the viscosity of the high-viscosity glue solution is 40 to 50mPa.s.
10. The fracturing method according to claim 9, wherein in step 4, the particle size of the plugging agent is 60-80 meshes, and the dissolution time is 30-40min.
11. The fracturing method according to claim 10, wherein in step 4, the sand-to-liquid ratio of the blocking agent is 30 to 40%, and the volume of the high-viscosity glue solution is 1 to 3m 3 。
12. The fracturing method according to claim 2, wherein in step 5, a low-viscosity slickwater with the viscosity of 1-3 mPa.s is used for manufacturing the diversion branch seam.
13. The fracturing method of claim 12, wherein in step 5, the injection volume is 5 branch seams, the length of each branch seam is 10% of the length of the optimized main seam in steps 1-3, the seam height is the height of the main seam or the top and bottom thickness of a fracturing target layer, and the efficiency of the fracturing fluid is calculated to be 20-30%.
14. The fracturing method according to claim 13, wherein in step 5, the displacement takes the highest value under pressure limit.
15. The fracturing method according to claim 1, wherein the high viscosity slickwater has a viscosity of 10 to 15mpa.s.
16. The fracturing method according to claim 15, wherein in step 6, the particle size of the plugging agent is 100-200 meshes, and the dissolution time is 20-25min.
17. The fracturing method of claim 16,in the step 6, the sand-liquid ratio of the plugging agent is 30 to 40 percent, and the volume of the high-viscosity slippery water is 1 to 3m 3 。
18. The fracturing method according to claim 14, wherein in step 7, the microcracks are formed by using low-viscosity slickwater with viscosity of 1 to 3mpa.s.
19. The fracturing method of claim 18, wherein the delivery volume is 40-60% of the optimized delivery volume in step 5 to ensure sufficient communication with the microcrack system.
20. The fracturing method according to claim 1, wherein, in step 8,
when the particle size of the propping agent is 140-210 meshes, sand is added in a continuous sand adding mode, the sand carrying liquid volume is 5~7 times of the wellbore volume, the initial sand-liquid ratio is 1~2%, then the sand-liquid ratio of each section is sequentially increased by 1~2%, and the sand carrying liquid volume under each sand-liquid ratio is 0.7-1.2 wellbore volumes;
when the particle size of the proppant is 70-140 meshes, 5~7 sections of slug type sand adding is adopted, the initial sand-liquid ratio is 1~2%, then the sand-liquid ratio of each section is sequentially increased by 1~2%, and the volume of the sand-liquid carrying liquid under each sand-liquid ratio is 0.7-1.2 shaft volumes.
21. The fracturing method of claim 20, wherein in step 8, when the particle size of the proppant is 70-140 meshes, the sand-to-fluid ratio is 1% -2% -3% -5% -7% -9%, and the volume of the sand-carrying fluid in each sand-to-fluid ratio is the volume of the wellbore.
22. The fracturing method according to claim 1, wherein in step 9, 5~7 sections of slug-type sand feeding is adopted, the initial sand-liquid ratio is 4~6%, then the sand-liquid ratio of each section is sequentially increased by 1~3%, and the sand-liquid carrying volume of each sand-liquid ratio is 0.2 to 0.5 wellbore volume.
23. The fracturing method according to claim 22, wherein in step 9, the sand-to-fluid ratio is 5% -7% -9% -11% -13% -15%, and the volume of the sand-carrying fluid corresponding to each sand-to-fluid ratio is 0.25 to 0.4 of the volume of the wellbore.
24. The fracturing method according to claim 23, wherein in step 9, construction is performed according to long slugs, the slugs corresponding to the first 3 sand-liquid ratios are 1 st, the slugs corresponding to the last 3 sand-liquid ratios are 2 nd, and the volume of the middle spacer fluid is 0.8 to 1.2 equivalent sections of the shaft.
25. The fracturing method according to claim 1, wherein in step 11, continuous sand adding is adopted, the sand adding is performed 5~7 times, the sand-liquid ratio of the first sand adding is 14 to 16 percent, and then, the sand-liquid ratio is increased 2~4 percent for each time.
26. The fracturing method of claim 25, wherein the sand-to-liquid ratio is 15 to 18 to 21 to 24 to 27 to 30%.
27. The fracturing method according to any one of claims 1 to 26, wherein in step 12, a high-viscosity fracturing fluid and a low-viscosity slickwater are used for replacing operation, wherein the viscosity of the high-viscosity fracturing fluid is 40 to 50mPa.s, and the viscosity of the low-viscosity slickwater is 1 to 2mPa.s.
28. The fracturing method according to claim 27, wherein the volume of the displacement fluid is 110 to 130 percent of the volume of the cased well bore.
29. The fracturing method of claim 28, wherein the first 30 to 40% of the displacement fluid is high viscosity fracturing fluid and the subsequent displacement fluid is low viscosity slickwater.
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| CN115758851B (en) * | 2022-11-28 | 2024-01-05 | 中国海洋石油集团有限公司 | Method for selecting multi-scale propping agent for natural fracture-containing stratum fracture |
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