CN118027947A - Fracturing fluid and fracturing method for interlayer shale oil and gas reservoirs - Google Patents
Fracturing fluid and fracturing method for interlayer shale oil and gas reservoirs Download PDFInfo
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Landscapes
- Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
Abstract
The invention relates to fracturing fluid and fracturing method for an interlayer shale oil and gas reservoir, and belongs to the technical field of oil and gas field development. The fracturing fluid for the interlayer shale oil and gas reservoir comprises a blocking remover, seepage liquid, low-viscosity slickwater and high-viscosity slickwater, wherein the CO 2 gas can be released by the reaction of the salt capable of releasing carbon dioxide in the blocking remover and an acidic compound, the fluidity of crude oil can be improved, and meanwhile, a large amount of heat is released, so that the cold injury of a reservoir in a near-wellbore zone can be reduced; the seepage liquid can improve the pore pressure, increase the microscopic damage degree of the rock, reduce the formation difficulty of complex joints, effectively replace the oil flow in the micropores and improve the post-pressing effect; the low-viscosity slick water can be matched with the propping agent to expand the seam, and the high-viscosity slick water can be matched with the propping agent to form a main seam.
Description
Technical Field
The invention relates to fracturing fluid and fracturing method for an interlayer shale oil and gas reservoir, and belongs to the technical field of oil and gas field development.
Background
Shale is a rock containing clay minerals (such as kaolinite, montmorillonite, hydromica, beidellite and the like), clastic minerals (such as quartz, feldspar, mica and the like) and autogenous minerals (such as oxides and hydroxides of iron, aluminum and manganese and the like), and the clastic minerals contained in the shale enable the shale to have the function of oil and gas storage. Shale oil is classified into 2 types of shale oil of shale type and interlayer shale oil.
Shale-type shale oil is a petroleum resource lodged in shale pores and cracks, and can be further divided into 2 sub-classes of matrix-type shale oil and crack-type shale oil. The matrix shale oil mainly comprises organic matters and clay minerals which are stored in the shale matrix, wherein the organic matters are in micropores such as inter-grain, intra-grain and corrosion and the like of the clay minerals, and the matrix shale oil is low-pore low-permeability shale oil which is relatively difficult to develop. The crack shale oil is mainly in free state in cracks and microcracks of the shale layer, the enrichment degree is controlled by the development degree of the cracks and the crack system, the storage and extraction conditions are good, and the extraction degree is high.
The organic-lean bands interspersed with organic-rich shale intervals are commonly referred to as interlayers. Interlayer action in shale: 1. the interlayer can be used as an effective reservoir of oil and gas; 2. the interlayer is an effective channel for shale oil production; 3. the interlayer development is beneficial to large-scale fracturing reformation. The minimum interlayer thickness identifiable by conventional well logging methods is 0.5m. Sandstone and carbonate rock with the interlayer thickness of 0.75-2 m and the proportion of the single layer thickness to the layer group thickness of less than 10-20% are defined as the interlayer. The interlayer shale oil and gas reservoir is a main space where sandstone and carbonate rock interlayers are used as oil and gas occurrence, and can be further divided into 2 subclasses of sandstone interlayer shale oil and carbonate rock interlayer shale oil. Although the single-layer thickness of the interlayer shale oil is thinner, the physical property condition is relatively better, and the oil gas in the upper and lower adjacent layers of shale oil can enter the interlayer for storage after being transported in a shorter distance.
But the reservoir heterogeneity of the interlayer shale oil is strong, the sand bodies are discontinuously distributed, the difficulty of optimizing and combining the section clusters is high, the two-way stress difference of the reservoir is high, the fracturing index is low, and the difficulty of forming complex joints is high. When the existing fracturing method and fracturing fluid adopted in fracturing are used for the interlayer shale oil, only single-form cracks can be formed, and the petroleum yield is low. Accordingly, there is a need to develop a fracturing fluid and fracturing method suitable for a sandwich shale oil and gas reservoir.
Disclosure of Invention
The invention aims to provide a fracturing fluid for a sandwich type shale oil and gas reservoir, which can solve the problems of poor fracturing effect and low oil yield when the conventional fracturing fluid is used for fracturing construction of the sandwich type shale oil and gas reservoir.
The invention further aims to provide a fracturing method of the interlayer shale oil and gas reservoir, which can solve the problems of poor fracturing effect and low oil yield when the fracturing construction is carried out on the interlayer shale oil and gas reservoir at present.
In order to achieve the above purpose, the fracturing fluid for the interlayer shale oil and gas reservoir adopts the following technical scheme:
A fracturing fluid for a sandwich shale oil and gas reservoir comprises a blocking remover, a seepage liquid, low-viscosity slick water and high-viscosity slick water; the blocking remover comprises an agent A and an agent B, wherein the agent A mainly comprises a salt capable of releasing carbon dioxide and water, the salt capable of releasing carbon dioxide is carbonate and/or bicarbonate, the mass fraction of the salt capable of releasing carbon dioxide in the agent A is 10-12%, the agent B mainly comprises an acidic compound and water, and the mass fraction of the acidic compound in the agent B is 1.82-3.72%;
The imbibition liquid mainly comprises a wetting regulator, a clay stabilizer, a resistance reducing agent and water, wherein the mass fraction of the wetting regulator is not more than 0.3%, the mass fraction of the clay stabilizer is not more than 0.3%, and the mass fraction of the resistance reducing agent is not more than 0.1%;
the low-viscosity slick water mainly comprises a resistance reducing agent, a clay stabilizer, a wetting regulator and water, wherein the mass fraction of the resistance reducing agent in the low-viscosity slick water is not less than 0.2%, the mass fraction of the clay stabilizer is not less than 0.3%, and the mass fraction of the wetting regulator is not less than 0.2%;
The high-viscosity slick water mainly comprises a resistance reducing agent, a clay stabilizer, a waterproof locking agent and water, wherein the mass fraction of the resistance reducing agent in the high-viscosity slick water is not less than 0.6%, the mass fraction of the clay stabilizer is not less than 0.3%, and the mass fraction of the waterproof locking agent is not less than 0.3%.
The fracturing fluid for the interlayer shale oil and gas reservoir comprises a blocking remover, seepage liquid, low-viscosity slickwater and high-viscosity slickwater, wherein the CO 2 gas can be released by the reaction of the salt capable of releasing carbon dioxide in the blocking remover and an acidic compound, the fluidity of crude oil can be improved, and meanwhile, a large amount of heat is released, so that the cold injury of a reservoir in a near-wellbore zone can be reduced; the seepage liquid can improve the pore pressure, increase the microscopic damage degree of the rock, reduce the formation difficulty of complex joints, effectively replace the oil flow in the micropores and improve the post-pressing effect; the low-viscosity slick water can be matched with the propping agent to expand the seam, and the high-viscosity slick water can be matched with the propping agent to form a main seam.
Preferably, the agent A and the agent B also independently comprise a discharge assisting agent, wherein the mass fraction of the discharge assisting agent in the agent A is 0.5-0.8%, and the mass fraction of the discharge assisting agent in the agent B is 0.5-0.7%.
Preferably, the agent A and the agent B also independently comprise ammonium chloride, and the mass fraction of the ammonium chloride in the agent A and the agent B is independently 2-4%.
Preferably, the agent A further comprises a cleanup additive, and the cleanup additive in the agent A is 0.5-0.8% by mass. The cleanup additive in the agent A has the function of reducing the surface interfacial tension of the liquid injected into the stratum by the pump, facilitating the flow back of the liquid to the ground from the ground and reducing the damage of the pumped fluid to the underground rock.
Preferably, the agent A also comprises ammonium chloride, and the mass fraction of the ammonium chloride in the agent A is 2-4%. The ammonium chloride in the agent A is used for preventing the underground rock from expanding due to the injection of the external fluid and reducing the porosity of the rock.
Preferably, the agent B further comprises a corrosion inhibitor, wherein the mass fraction of the corrosion inhibitor in the agent B is 1-3%. The corrosion inhibitor has the effects of delaying the release speed of H + in hydrochloric acid, reducing the addition amount, and not obviously improving the effect, so that the hydrochloric acid reacts in a shaft, cannot react with alkaline liquid in the ground to generate heat, and the release speed of H + can be delayed due to the excessive addition amount.
Preferably, the agent B further comprises a cleanup additive, and the cleanup additive in the agent B is 0.5-0.7% by mass. The cleanup additive in the agent B is used for reducing the surface interfacial tension of the liquid injected into the stratum by the pump, facilitating the flow back of the liquid to the ground from the ground and reducing the damage of the pumped fluid to the underground rock.
Preferably, the agent B further comprises ammonium chloride, and the mass fraction of the ammonium chloride in the agent B is 2-4%. The ammonium chloride in the agent B can participate in the reaction, and release heat.
Preferably, the agent B further comprises an iron ion stabilizer, and the mass fraction of the iron ion stabilizer in the agent B is 1-3%. The acid liquor contacts with the metal surface to form partial iron ions to enter the stratum, the acid liquor activity is gradually reduced along with the progress of acid rock reaction, the pH value is increased, free iron ions are precipitated in the form of Fe (OH) 3 to cause secondary pollution, the iron ion stabilizer can be complexed or chelated with Fe 3 +、Fe2+ to ensure that the iron ion stabilizer is not easy to hydrolyze in acid, the iron ion stabilizer can reduce Fe 3+ to Fe 2+, the purpose of stabilizing iron can be achieved under the pH value of spent acid, and iron gel precipitation is prevented, so that the iron ion stabilizer is discharged along with the spent acid.
Preferably, the acidic compound in the agent B is HCl, which is provided by hydrochloric acid. Commercially available hydrochloric acid is suitable for use in the present invention.
Preferably, the mass of the hydrochloric acid accounts for 12-14% of the total mass of the agent B.
The clay stabilizer in the seepage liquid, the low-viscosity slick water and the high-viscosity slick water has the functions of effectively adsorbing on the clay surface and preventing the damage to an oil and gas layer caused by hydration expansion and dispersion migration of water-sensitive minerals.
The function of the friction reducing agent in the seepage liquid, the low-viscosity slick water and the high-viscosity slick water is to reduce the liquid resistance.
The function of the wetting regulator in the low-viscosity slick water and the imbibition liquid is to improve the hydrophilicity or oleophobicity of the rock surface, so as to peel off the oil film adsorbed on the rock surface.
The waterproof locking agent in the high-viscosity slick water plays an important role in relieving water damage, can effectively prevent and relieve water-phase damage generated in the fracturing process of the low-permeability oil reservoir, and improves fracturing productivity. Reducing the water lock effect is an important measure for protecting natural gas reservoirs, and the water-proof lock agent needs to meet the following conditions: 1. the surface tension or interfacial tension of the solution can be greatly reduced by adding a small amount of the solution, the interfacial state of the system is changed, and the surface is in an activated state, so that wetting or dewetting is generated; 2. the waterproof locking agent can accelerate the drainage of the invaded liquid, and is favorable for the drainage of the stratum retention liquid near the well to better solve the water locking effect.
Preferably, the wetting modulator is an alkali metal salt of 9, 10-dihydroxystearic acid. For example, the wetting modulator is sodium 9, 10-dihydroxystearate.
The fracturing method of the sandwich shale oil and gas reservoir adopts the following technical scheme:
a fracturing method of an interlayer shale oil and gas reservoir comprises the following steps:
(1) Determining section shower hole positions according to geological desserts and engineering desserts of the target interlayer shale oil and gas reservoir;
(2) Bridge plugs and shower holes are combined for construction;
(3) Sequentially injecting a blocking remover, a first pad fluid, a first sand-carrying fluid, a middle top fluid, a second pad fluid, a second sand-carrying fluid and a displacement fluid into each fracturing segment to realize fracturing construction of each fracturing segment; the blocking remover is the blocking remover in the fracturing fluid; the first pad fluid and the second pad fluid independently comprise a imbibition fluid, a low viscosity slickwater, and a high viscosity slickwater in a fracturing fluid as described above; the first sand-carrying fluid and the middle top fluid are independently high-viscosity slick water in the fracturing fluid; the second sand-carrying fluid is high-viscosity slick water in the fracturing fluid, or comprises seepage liquid, low-viscosity slick water and high-viscosity slick water in the fracturing fluid; the displacement fluid is low-viscosity slickwater in the fracturing fluid.
The fracturing method of the sandwich shale oil and gas reservoir comprises the steps of determining a section shower hole position, then constructing a bridge plug and shower holes in a combined mode, and finally injecting the fracturing fluid for the sandwich shale oil and gas reservoir, wherein the plugging removing agent in the fracturing fluid has the following functions: on one hand, the acid liquor can reduce the fracture pressure of the reservoir, erode carbonate minerals and increase pore connectivity; on the other hand, CO 2 gas is generated by deep reaction of the oil layer, so that the fluidity of crude oil can be improved, and meanwhile, a large amount of heat is released, so that the cold damage of the reservoir in the near-wellbore zone is reduced; the high-viscosity slick water in the fracturing fluid can be used for making a seam in advance and forming a main seam, the seepage liquid in the fracturing fluid can be used for improving the pore pressure, increasing the microscopic damage degree of rock, reducing the formation difficulty of complex seams, effectively replacing the oil flow in micro-pores and improving the post-pressing effect; the low-viscosity slick water in the fracturing fluid can expand the joints; the fracturing method of the interlayer shale oil and gas reservoir can realize full support of cracks.
Preferably, the plugging removing agent is injected into the fracturing segment, and the agent A and the agent B in the plugging removing agent are sequentially injected into the fracturing segment. Further preferably, after the agent A is injected, a spacer fluid is injected into the fracture zone and then the agent B is injected. Preferably, the spacer fluid is water.
Preferably, the injecting the first pad into the fracturing section is sequentially injecting high-viscosity slickwater, imbibition liquid, low-viscosity slickwater and high-viscosity slickwater in the first pad into the fracturing section, wherein when a plurality of batches of low-viscosity slickwater are injected and a part of the plurality of batches are injected with the low-viscosity slickwater, the low-viscosity slickwater is adopted to carry the proppants, and the sand ratio carrying the proppants increases with the increase of the injected batches. For example, when 5 batches of low viscosity slickwater in the first pad are injected, the 1 st, 2 nd, 4 th and 5 th batches are injected with low viscosity slickwater, the proppant is carried with the low viscosity slickwater. Preferably, the proppants carried by the low-viscosity slick water in the first pad fluid are 70-140 mesh quartz sand.
Preferably, the first sand-carrying fluid is injected into the fracturing segment in a plurality of batches, when each batch of the first sand-carrying fluid is injected into the fracturing segment, the proppant is carried by the first sand-carrying fluid, and the sand ratio of the proppant is increased along with the increase of the injected batches. For example, the first sand-carrying fluid is injected into the fracturing stage in 6 batches. Preferably, the propping agent carried by the first sand-carrying fluid is 40-70 mesh ceramsite.
Preferably, when the middle propping liquid is injected into the fracturing section, the middle propping liquid is adopted to carry the propping agent mainly composed of temporary plugging balls and temporary plugging agents.
Preferably, the second pad fluid is injected into the fracturing segment by sequentially injecting the seepage fluid, the low-viscosity slickwater and the high-viscosity slickwater in the second pad fluid into the fracturing segment, wherein the low-viscosity slickwater is injected in at least 2 batches, when the low-viscosity slickwater is injected in each batch, the low-viscosity slickwater is used for carrying the proppants, and the sand ratio carrying the proppants increases with the increase of the injected batches. Preferably, the proppants carried by the low-viscosity slick water in the second pad fluid are 70-140 mesh quartz sand.
Preferably, the second sand-carrying fluid is high-viscosity slick water in the fracturing fluid, and the second sand-carrying fluid is injected into the fracturing section, wherein the second sand-carrying fluid is injected into the fracturing section in a plurality of batches, and when part of the batches are injected into the second sand-carrying fluid, the propping agent is carried by the second sand-carrying fluid. For example, the second sand-carrying fluid is injected into the fracturing section in 10 batches, when the 1 st to 5 th batches are injected into the second sand-carrying fluid, the proppant is carried by the second sand-carrying fluid, and the sand ratio carrying the proppant increases with the increase of the injected batches; and when the 7 th to 10 th batches are injected with the second sand-carrying fluid, the second sand-carrying fluid is adopted to carry the propping agent, and the sand ratio of the propping agent is increased along with the increase of the injected batches. Preferably, the propping agent carried by the second sand-carrying fluid is 40-70 mesh ceramsite.
Preferably, the second sand-carrying fluid comprises seepage liquid, low-viscosity slick water and high-viscosity slick water in the fracturing fluid, and the injection of the second sand-carrying fluid into the fracturing section is to sequentially inject the high-viscosity slick water, the seepage liquid, the low-viscosity slick water and the high-viscosity slick water in the second sand-carrying fluid into the fracturing section.
Preferably, before the imbibition liquid in the second sand-carrying liquid is injected into the fracturing section, the high-viscosity slickwater in the second sand-carrying liquid is injected into the fracturing section in a plurality of batches, when the high-viscosity slickwater in the second sand-carrying liquid is injected into each batch, the high-viscosity slickwater in the second sand-carrying liquid is adopted to carry proppants, the proppants carried by the high-viscosity slickwater in the second sand-carrying liquid injected in each batch before the last batch are ceramsites, the sand ratio of the proppants carried by the high-viscosity slickwater in the second sand-carrying liquid injected in each batch before the last batch is increased along with the increase of the injected batches, and the proppants carried by the high-viscosity slickwater in the second sand-carrying liquid injected in the last batch consist of a temporary plugging ball and a temporary plugging agent. For example, 6 batches of high viscosity slick water in the second sand-carrying fluid are injected into the fracturing stage.
Preferably, the injecting of the low-viscosity slickwater in the second sand-carrying fluid into the fracturing stage is to inject not less than 2 batches of the low-viscosity slickwater in the second sand-carrying fluid into the fracturing stage, wherein when the low-viscosity slickwater is injected into each batch, the low-viscosity slickwater is used for carrying the proppants, and the sand ratio carrying the proppants increases with the increase of the injected batches. Preferably, the propping agent carried by the low-viscosity slick water in the second sand-carrying fluid is quartz sand with 70-140 meshes.
Preferably, after the imbibition liquid in the second sand-carrying liquid is injected into the fracturing section, the high-viscosity slick water in the second sand-carrying liquid is injected into the fracturing section, a plurality of batches of the high-viscosity slick water in the second sand-carrying liquid are injected into the fracturing section, when the high-viscosity slick water is injected into each batch, the high-viscosity slick water is used for carrying the propping agent, and the sand ratio for carrying the propping agent is increased along with the increase of the injected batches. Preferably, the propping agent carried by the high-viscosity slick water in the second sand-carrying fluid injected after the imbibition fluid in the second sand-carrying fluid is injected into the fracturing section is 40-70 meshes of ceramsite.
Preferably, the construction displacement of the blocking remover, the first front-end fluid, the first sand-carrying fluid, the middle top fluid, the second front-end fluid, the second sand-carrying fluid and the displacement fluid is determined through simulation optimization.
Preferably, the conditions that the same fracture section needs to meet are as follows: natural gamma energy spectrum is less than 90, clay content is less than 30%, porosity is more than 3.5%, minimum principal stress value is less than 46MPa, young modulus is more than 3.5X10 4 MPa.
Preferably, a bridge plug is arranged between any two adjacent fracturing sections. Preferably, mudstone interlayer shielding is arranged between the fracturing sections, and the thickness of the interlayer is 1.3-3.0 m.
In the invention, the sand ratio of the propping agent carried by the low-viscosity slickwater in the fracturing fluid is smaller than that of the propping agent carried by the high-viscosity slickwater in the fracturing fluid.
Drawings
FIG. 1 is a schematic diagram showing the results of rheological property test of highly viscous slick water in a pad fluid in an experimental example of the present invention;
FIG. 2 is a graph showing the change of reservoir reforming volume (stimulated reservoir reforming volume) with single cluster liquid amount in an experimental example of the present invention;
FIG. 3 is a graph showing the net pressure of the stratum over time at different construction displacements according to the experimental example of the present invention;
FIG. 4 is a schematic drawing showing the extension of a fracture at the 6 perforation cluster locations in the first fracture zone during a fracturing process simulated by software in an experimental example of the present invention;
FIG. 5 is a schematic drawing showing the extension of a fracture at the 4 perforation cluster locations in the second fracture zone during fracturing with software simulation in an experimental example of the present invention;
FIG. 6 is a schematic drawing showing the extension of a fracture at the 5 perforation cluster locations in the third fracturing stage in the fracturing process employing software simulation in the experimental example of the present invention
FIG. 7 is a schematic illustration of the extension of a fracture at the 4 perforation cluster locations in the fourth fracturing segment during fracturing with software simulation in an experimental example of the present invention;
FIG. 8 is a schematic representation of production curves recorded during a fracturing construction of the well A in accordance with the present invention;
FIG. 9 is a schematic representation of production curves recorded during an M-well fracturing operation in accordance with the present invention;
FIG. 10 is a schematic illustration of production curves recorded during an N-well fracturing operation in accordance with the present invention;
FIG. 11 is a schematic illustration of production curves recorded during a P-well fracturing operation in accordance with the present invention;
FIG. 12 is a schematic representation of production curves recorded during a fracturing operation for a Q well in accordance with the present invention.
Detailed Description
The technical scheme of the invention is further described below with reference to specific embodiments.
1. The specific examples of fracturing fluids for the laminated shale oil and gas reservoirs of the invention are as follows:
Example 1
The fracturing fluid for the interlayer shale oil and gas reservoir comprises a blocking remover, a seepage liquid, low-viscosity slick water and high-viscosity slick water;
Wherein the blocking remover comprises an agent A and an agent B, wherein the agent A consists of the following components in percentage by mass: 10% of sodium bicarbonate, 0.5% of a cleanup additive, 2% of ammonium chloride and the balance of water; the agent B consists of the following components in percentage by mass: 12% of hydrochloric acid, 1% of corrosion inhibitor, 0.5% of cleanup additive, 2% of ammonium chloride, 1% of iron ion stabilizer and the balance of water; the mass concentration of hydrochloric acid in the agent B is 31%;
The seepage liquid consists of the following components in percentage by mass: 0.3% of a wetting regulator, 0.3% of a clay stabilizer, 0.1% of a resistance reducing agent and the balance of water; the low-viscosity slick water consists of the following components in percentage by mass: 0.2% of resistance reducing agent, 0.3% of clay stabilizer, 0.2% of wetting regulator and the balance of water; the high-viscosity slick water consists of the following components in percentage by mass: 0.6% of resistance reducing agent, 0.3% of clay stabilizer, 0.3% of waterproof locking agent and the balance of water.
Example 2
The fracturing fluid for the interlayer shale oil and gas reservoir comprises a blocking remover, a seepage liquid, low-viscosity slick water and high-viscosity slick water;
Wherein the blocking remover comprises an agent A and an agent B, wherein the agent A consists of the following components in percentage by mass: 10-12% of sodium bicarbonate, 0.8% of a cleanup additive, 4% of ammonium chloride and the balance of water; the agent B consists of the following components in percentage by mass: 14% of hydrochloric acid, 3% of corrosion inhibitor, 0.7% of cleanup additive, 4% of ammonium chloride, 3% of iron ion stabilizer and the balance of water; the mass concentration of hydrochloric acid in the agent B is 13%;
The seepage liquid consists of the following components in percentage by mass: 0.3% of a wetting regulator, 0.3% of a clay stabilizer, 0.1% of a resistance reducing agent and the balance of water; the low-viscosity slick water consists of the following components in percentage by mass: 0.2% of resistance reducing agent, 0.3% of clay stabilizer, 0.2% of wetting regulator and the balance of water; the high-viscosity slick water consists of the following components in percentage by mass: 0.6% of resistance reducing agent, 0.3% of clay stabilizer, 0.3% of waterproof locking agent and the balance of water.
2. The specific embodiment of the fracturing method of the interlayer shale oil and gas reservoir is as follows:
Example 3
The fracturing method of the interlayer shale oil and gas reservoir of the embodiment specifically comprises the following steps:
(1) Determining a fracture segment and a fracture cluster of a target well (a well) formation of interest
The well A is a compact interlayer shale oil reservoir, and the planar layout diagram of the well A region shows that the well A is positioned in a region with higher TOC (organic matter content) on the planar position, so that the well A has exploitation potential. The well conditions of the A well are shown in Table 1.
Table 1 well conditions of the well
The A well is an interlayer shale oil well, the inclination data of part of target layers are shown in table 2, the well cementation quality is shown in table 3, and the evaluation method of the well cementation quality refers to table 5 in the standard SY/T6592-2016 well cementation quality evaluation method.
Table 2A well target zone well deviation data
Table 3A well cementing quality data
Note that: the first interface in table 3 refers to the bonding interface between the cemented cement and the casing, and the second interface refers to the bonding interface between the formation and the cemented cement.
As can be seen from table 3, when fracturing the target layer, fracturing is required in a well section with oil and gas and a well cementation quality in which the second interface is not lower than the middle well section.
Well structures are divided into a vertical well, an inclined well and a horizontal well, wherein the A well is an inclined well with a high inclination. For wells with a certain inclination, after the new reservoir is perforated, a certain amount of propping agent with small particle size of 70-140 meshes is needed to be driven in due to the inclination angle between the well bore and the stratum so as to reduce the friction force generated by the angle between the well bore and the stratum. If the small-particle-size propping agent is not added, the friction force generated by the included angle between the shaft and the stratum has a shearing action on the subsequent gel-shaped fracturing fluid, so that the viscosity of the gel-shaped fracturing fluid is reduced and the sand carrying proportion is reduced, namely the sand-liquid ratio is reduced, and the sand adding is not facilitated.
The results of the hydrocarbon parameters of the a-well wall rock detected by the logging device are shown in table 4.
Table 4A oil and gas parameters of well wall rock
Note that: in table 4, Σc is the distribution range of the gas-measured total hydrocarbon amount measured in the well section, and C1 is the gas-measured total hydrocarbon amount measured in a certain position area in the well section; s.0 is the amount of hydrocarbon containing gas; s.l is the amount of gas-containing oil; s.2 is the pyrolysis hydrocarbon amount; pi is the overall yield index.
As can be seen from table 4, the gas-measured total hydrocarbon content of different well sections is different, the gaseous hydrocarbon content, the gas-containing oil content, the pyrolyzed hydrocarbon content and the total yield index are all different, in order to improve the fracturing effect, the area with high oil gas content is taken as a fracturing object, and the geological requirements and the logging interpretation result are combined, so that the corresponding segment clusters are preferably fractured through geological desserts and engineering desserts, and the selection standard of the fracturing segment clusters is as follows: natural gamma energy spectrum GR < 90, argillaceous content SH < 30%, porosityThe minimum main stress value delta min is less than 46MPa, the Young modulus E is more than 3.5X10 4 MPa, meanwhile, the perforation point should avoid the casing collar position, and the bridge plug position should be selected and arranged on the well section with the best well cementation quality.
According to the selection criteria, the objective interval of the a well is divided into 4 fracturing segments and 20 fracturing clusters, and the number of fracturing clusters (perforation clusters) in each fracturing segment, the top depth (cluster top depth) and bottom depth (cluster bottom depth) of each fracturing cluster, the length (cluster length) of each fracturing cluster, the number of perforations (hole number) in each fracturing cluster, the geological dessert data and engineering dessert data of each fracturing cluster are shown in table 5.
Table 5 number of fracturing clusters (perforation clusters) in each fracturing segment, top depth (cluster top depth) and bottom depth (cluster bottom depth) of each fracturing cluster, length of each fracturing cluster (cluster length), number of perforations (holes) in each fracturing cluster, geological dessert data and engineering dessert data of each fracturing cluster
Note that: the absence of corresponding data is shown in table 5.
And a bridge plug is arranged between any two adjacent fracturing sections, the depth of the bridge plug arranged between the first fracturing section and the second fracturing section is 3355m, the depth of the bridge plug arranged between the second fracturing section and the third fracturing section is 3255m, and the depth of the bridge plug arranged between the third fracturing section and the fourth fracturing section is 3120m. Perforation parameters in the a-well fracturing section are shown in table 6.
Table 6A perforation parameters in a well fracturing section
The span of a target layer related to the fracturing of the well A is 431.4m, four fracturing sections are all arranged, a certain mudstone interlayer is reserved among the fracturing sections, the thickness of the interlayer is 1.3-3.0 m, the stress difference is 3.8-5.4 MPa, the inclined depth, the vertical depth and the minimum stress of each fracturing section of the well A and the layer number of each fracturing section are shown in table 7, and the thickness of the interlayer and the minimum stress between two adjacent fracturing sections are shown in table 8.
TABLE 7 inclined depth, vertical depth, minimum stress for each fracturing segment of well A and horizon number for each fracturing segment
| Fracturing segment | Horizon number | Inclined deep (m) | Vertical deep (m) | Minimum stress (MPa) |
| Fourth fracturing section | 105 | 3041-3098.3 | 2610.7-2631.3 | 43.2 |
| Third fracturing section | 107 | 3135.5-3235 | 2644.6-2680.2 | 43.8 |
| Second fracturing section | 111 | 3270-3330 | 2692.8-2714.3 | 44.5 |
| First fracturing section | 115 | 3370.8-3472 | 2728.9-2765.2 | 45.3 |
TABLE 8 thickness and minimum stress of the barrier between two adjacent fracture sections
| Interlayer layer | Thickness (m) | Minimum stress (MPa) |
| A barrier layer between the third fracture section and the fourth fracture section | 1.5 | 48.3 |
| A barrier layer between the second fracture section and the third fracture section | 1.3 | 47.9 |
| An interlayer between the first fracture section and the second fracture section | 3.0 | 49.1 |
According to Young's modulus and Poisson's ratio calculated by the ground stress, the fracturing index (the calculating method of the fracturing index refers to the calculating method of the brittleness index B rit in the Chinese patent document CN 115749756A) is 31-48.9%, the triaxial stress comprises vertical stress in one vertical direction and horizontal stress in two horizontal directions, the horizontal stress difference in the two horizontal directions is 13-14.1 MPa, and as shown in the table 9, the reservoir compressibility of the A well is poor and the difficulty of forming complex joints is high.
Table 9A well fracturing index calculation results
(2) Segmented multi-cluster fracturing construction for target well
In the embodiment, during the fracturing construction, plugging removing agent, first pad fluid, first sand carrying fluid, middle top fluid, second pad fluid, second sand carrying fluid and displacing fluid are sequentially injected into each fracturing segment so as to realize the fracturing construction of each fracturing segment;
① Composition of liquid used in fracturing process and amount of propping agent
The blocking remover used in the embodiment comprises an agent A and an agent B, wherein the agent A comprises the following components in percentage by mass: 10% of bicarbonate, 0.5% of cleanup additive, 2% of ammonium chloride and the balance of water; the agent B consists of the following components in percentage by mass: 12% of hydrochloric acid, 1% of corrosion inhibitor, 0.5% of cleanup additive, 2% of ammonium chloride, 1% of iron ion stabilizer and the balance of water. Wherein bicarbonate in the agent A is sodium bicarbonate, the cleanup additives in the agent A and the agent B are commercial cleanup additives (website: http:// bfckj. Well/product_detail/id/34. Html) produced by Beijing Baofuchun Petroleum technologies, the corrosion inhibitor in the agent B is commercial corrosion inhibitor (website: http:// bfckj. Well/product_detail/id/21. Html) produced by Beijing Baofuchun petroleum technologies, and the iron ion stabilizer in the agent B is commercial iron ion stabilizer (website: http:// bfckj. Well/product_detail/id/24. Ml) produced by Beijing Baofuchun petroleum technologies. When the blocking remover used in the embodiment is used, the volume ratio of the agent A to the agent B is 1:1, and the injection mode or the using method of the blocking remover is as follows: firstly, the agent A is injected, then the isolating liquid (active water with the volume of 2m 3) is injected, and finally the agent B is injected.
The agent A and the agent B in the blocking remover used in the embodiment can be completely reacted within 30min after being mixed, CO 2 gas of about 27-40 m 3 can be generated after the agent A solution of each m 3 is completely reacted, meanwhile, larger heat can be generated when the agent A and the agent B are mixed for reaction, and heat of 33 multiplied by 10 4 KJ can be generated after the agent A solution of each m 3 is completely reacted.
The volumes of agent A and agent B in the plugging removal agent used in each fracturing section of the well A are shown in Table 10.
TABLE 10 inclined depth, perforation thickness (jet thickness) of each fracturing section of well A volumes of agent A and agent B in temporary plugging agent used for each fracturing section
| Fracturing segment | Inclined deep (m) | Thickness of jet (m) | Agent A (m 3) | Agent B (m 3) |
| First fracturing section | 3370.8～3472 | 6 | 55 | 55 |
| Second fracturing section | 3270～3330 | 4 | 35 | 35 |
| Third fracturing section | 3135.5～3235 | 5.5 | 50 | 50 |
| Fourth fracturing section | 3041～3098.3 | 5 | 45 | 45 |
The first and second pad solutions used in this example each include a bleed solution, a low viscosity slick water, and a high viscosity slick water; wherein the imbibition liquid consists of the following components in percentage by mass: 0.3% of a wetting regulator, 0.3% of a clay stabilizer, 0.1% of a resistance reducing agent and the balance of water; the low-viscosity slick water consists of the following components in percentage by mass: 0.2% of resistance reducing agent, 0.3% of clay stabilizer, 0.2% of wetting regulator and the balance of water; the high-viscosity slick water consists of the following components in percentage by mass: 0.6% of resistance reducing agent, 0.3% of clay stabilizer, 0.3% of waterproof locking agent and the balance of water. The wetting regulator in the permeation liquid is 9, 10-dihydroxysodium stearate, and can be prepared according to the method in the literature interface wettability regulation oil displacement agent preparation and performance evaluation, wherein the clay stabilizer is a commercial clay stabilizer (the website is http:// bfckj.website.cn/product_detail/id/32. Html) produced by Beijing Baofuchun petroleum technology Co., ltd.), and the resistance reducing agent is a commercial resistance reducing agent (the website is http:// bfckj.webd.testwebsite/product_detail/id/39. Html) produced by Beijing Baofuchun petroleum technology Co., ltd; resistance reducing agent in low-viscosity slickwater commercial resistance reducing agent (website: http:// bfckj.website. Cn/product_detail/id/39. Html) produced by Beijing Baofu Petroleum technologies Co., ltd., the clay stabilizer is commercial clay stabilizer (website: http:// bfckj.website. Cn/product_detail/id/32. Html) produced by Beijing Baofu petroleum technologies Co., ltd., the wetting regulator is sodium 9, 10-dihydroxystearate; the friction reducer in the high-viscosity slick water is a commercial friction reducer (with the website of http:// bfckj.website.cn/product_detail/id/39. Html) produced by Beijing Baofun Petroleum technologies Co., ltd.), and the waterproof locking agent is a commercial waterproof locking agent for fracturing provided by the new polymer industry and trade company of Kelmyx, the model of which is XJ-18 (with the website of https:// klmexjgm.com/newsinfo/1627392. Html).
The first sand-carrying fluid used in this embodiment is the same as the high-viscosity slick water in the first pre-fluid, the middle top fluid is the same as the high-viscosity slick water in the first pre-fluid, the second sand-carrying fluid is the same as the high-viscosity slick water in the first pre-fluid, or the second sand-carrying fluid comprises a seepage fluid, a low-viscosity slick water and a high-viscosity slick water, the seepage fluid, the low-viscosity slick water and the high-viscosity slick water in the second sand-carrying fluid are respectively the same as the seepage fluid, the low-viscosity slick water and the high-viscosity slick water in the first pre-fluid, and the displacement fluid is the same as the low-viscosity slick water in the first pre-fluid.
The pH value of the first pre-solution and the second pre-solution used in the embodiment is 6.5-7.5, the resistivity of the imbibition solution in the pre-solution can reach 74.284% when the flow rate is 22L/min, the field construction requirement is met, the viscosity of the low-viscosity slickwater in the pre-solution is 15 mPa.s, and the viscosity of the high-viscosity slickwater in the pre-solution is 48 mPa.s. Meanwhile, the rheological property of the high-viscosity slick water in the front liquid is tested, and the temperature and shear resistant curve obtained by the test is shown in figure 1, and as can be seen from figure 1, when the high-viscosity slick water is sheared for 120min at 170s -1 at 100 ℃, the tail viscosity is 32.58 mPa.s. Then, the gel breaking performance of different gel breakers on the pre-solution is tested, and the time when the viscosity of the gel breaker is 3 mPas is recorded, and the result shows that when the experiment temperature is 90 ℃, the gel breaking time when the viscosity of the gel breaker is 3 mPas is 2.5 hours, 1.5 hours and 0.5 hours respectively when ammonium persulfate with the mass fraction of 0.01%, 0.02% and 0.03% is adopted as the gel breaker, and the gel breaking time when the viscosity of the gel breaker is 3 mPas is adopted as 2.0 hours, and the gel breaking time when the viscosity of the gel breaker is 0.02% is adopted as the gel breaking time when the mixture (in the mixture, the mass fraction of ammonium persulfate, the capsule breaker and water is 0.02% is adopted as the gel breaking time when the mass fraction of the ammonium persulfate is 0.02% is adopted as the gel breaking time when the mixture (in the manufacturer is the Shanxi petroleum, the website is http:// www.sxsrkj.com/product_view. AspxID=342) and the water is adopted as the mixture.
Within a certain period of time, the gel is harmful to early hydration and late hydration; the fracturing fluid is macromolecule gel in a gel state under the ground, oxidant such as ammonium persulfate and the like is added on site when the fluid is pumped, and the gel is oxidized and decomposed into small molecules, namely hydration, by the ammonium persulfate under the ground along with the temperature and the pressure along with the pumping of the fluid into an underground stratum; too much ammonium persulfate is added on the on-site mixing vehicle, so that the oxidization and decomposition speed of the gel is high, the gel is hydrated and decomposed quickly in the underground, the propping agent wrapped by the gel at the previous stage can be hydrated in the rock too early and cannot be carried to the deep part of the stratum by the gel, the propping agent is caused to be settled at a position close to a shaft, a petroleum flowing channel is reduced, the propping agent support is lacking at the far end of a seam, and petroleum yield is reduced. If too little ammonium persulfate oxidant is added, the oxidative decomposition effect is poor, the gel cannot be completely decomposed, and the propping agent is carried to the deep part of the crack, but the propping agent wrapped by the gel exists in the crack, so that the petroleum flowing channel is blocked, and the petroleum yield is reduced. In summary, both too much and too little oxidant addition is detrimental to the oil production
According to experimental results, a mixture consisting of ammonium persulfate, a capsule breaker and water (in the mixture, the mass fraction of the ammonium persulfate is 0.02 percent, and the mass fraction of the capsule breaker is 0.02 percent) is used as the breaker, the ammonium persulfate and the capsule breaker in the breaker are both oxidants, and in the construction process, the breaker is added into the fracturing fluid, so that the gel-shaped fracturing fluid can be oxidized to form water, and the hydrated fracturing fluid is further returned to the ground from the ground. Finally, the damage of the high-viscosity slickwater in the fracturing fluid to the reservoir is evaluated, and since the rock of the fracturing reservoir is not obtained by the A well, the adjacent wells (the B well and the C well) of the A well are selected as experimental objects, and a water sensitivity experiment and an alkali sensitivity experiment (the test methods of the water sensitivity experiment and the alkali sensitivity experiment refer to the regulations of the standard SY/T5358-2010 reservoir sensitivity flow experiment evaluation method) are respectively carried out on the adjacent wells of the A well, and the results are shown in the table 11.
Table 11 damage to reservoirs by highly viscous slick water in fracturing fluids
As can be seen from table 11, the highly viscous slick water in the fracturing fluid used in this example did not harm the reservoir.
Meanwhile, the water lock injury of seepage and absorption liquid in fracturing fluid is tested, the testing method refers to the specification of the standard Q/SHCG 116,116-2017 waterproof locking agent technical requirement, when in testing, the sampling core of the adjacent well of the A well is used as a test object, and the test result is shown in table 12.
Table 12 water lock nociceptive in fracturing fluid
As can be seen from table 12, in this embodiment, there is a water lock damage to the wells in the block (adjacent wells of the a well), so the chemical liquid (fracturing liquid) injected into the a well by the fracturing pump needs to contain a wetting regulator, and the water lock effect is avoided.
The temporary plugging agent used in the embodiment is a commercial temporary plugging agent (the website is http:// bfckj.webd.testwebsite.cn/product_detail/id/19. Html) produced by Beijing Baofuchun Petroleum technologies, and through testing, the pressure bearing strength of the temporary plugging agent is up to 40MPa, the plugging rate is over 99.5 percent, the degradation rate is over 99 percent, and the construction requirement is met. The amount of temporary plugging agent is determined according to the following method: according to the thickness of the reservoir, the type of the crack and the scale of the crack, the conventional on-site temporary plugging agent is combined for use experience to carry out optimal design, and the calculation formula is as follows: Q=h×w×r×2×ρ×2K, wherein Q is the mass of the temporary plugging agent, h is 0.6-0.8 of the thickness of the perforating section, w is the slit width, r is the thickness of the filter cake, ρ is the density of the filter cake, K is an empirical coefficient, and the value is 1-2; in the embodiment, h is 0.8 of the thickness of the perforating section, w is 0.06-0.08 m, r is 15-17 m, and rho is 1.9kg/m 3. When the thickness of the perforating section (jet thickness) is 5m, the calculated amount of the temporary plugging agent is 100kg.
In this embodiment, the amount of temporary plugging balls is equal to the number of perforations multiplied by 1.2, and the amount of propping agent (quartz sand or ceramsite) is an empirical value obtained according to the construction conditions of the same region.
② Fracturing process
The first pad fluid is injected into the fracturing segment, namely high-viscosity slickwater, imbibition fluid, low-viscosity slickwater and high-viscosity slickwater in the first pad fluid are sequentially injected into the stratum of the fracturing segment, wherein 5 batches of low-viscosity slickwater are injected, when the 1 st batch, the 2 nd batch, the 4 th batch and the 5 th batch are injected with the low-viscosity slickwater, the low-viscosity slickwater is adopted to carry proppants (proppants are quartz sand with 70-140 meshes), and the sand ratio of the proppants is increased along with the increase of the injected batches.
The first sand-carrying fluid is injected into the stratum of the fracturing section in 6 batches, when the first sand-carrying fluid is injected into each batch, the propping agent is carried by the first sand-carrying fluid (the propping agent is 40-70 meshes of ceramsite), and the sand ratio of the propping agent is increased along with the increase of the injected batches.
When the middle propping liquid is injected into the fracturing section, the middle propping liquid is adopted to carry propping agent (the propping agent consists of 20 temporary plugging balls with the particle size of 3cm and 100kg of temporary plugging agent).
And the second pre-fluid is injected into the fracturing segment, namely the seepage liquid, the low-viscosity slickwater and the high-viscosity slickwater in the second pre-fluid are sequentially injected into the stratum of the fracturing segment, wherein the low-viscosity slickwater is injected in 2 batches, when the low-viscosity slickwater is injected into each batch, the low-viscosity slickwater is adopted to carry proppants (the proppants are quartz sand with 70-140 meshes), and the sand ratio carrying proppants is increased along with the increase of the injected batches.
When the second sand-carrying fluid comprises seepage liquid, low-viscosity slickwater and high-viscosity slickwater, the method for injecting the second sand-carrying fluid into the fracturing section comprises the following steps of:
s1, firstly, 6 batches of high-viscosity slickwater in second sand-carrying fluid are injected into a stratum of a fracturing section, when the 1 st to 5 th batches are injected with high-viscosity slickwater, the high-viscosity slickwater is adopted to carry proppants (proppants are 40-70 meshes of ceramsite) when each batch is injected with high-viscosity slickwater, the sand ratio of the proppants is increased along with the increase of the injected batches, and when the 6 th batch is injected with high-viscosity slickwater, the high-viscosity slickwater is adopted to carry proppants (the proppants consist of 20 temporary plugging balls with the particle size of 3cm and 100kg of temporary plugging agents);
S2, injecting the imbibition liquid in the second sand-carrying liquid into the stratum of the fracturing section, and injecting 2 batches of low-viscosity slickwater in the second sand-carrying liquid into the stratum of the fracturing section, wherein when low-viscosity slickwater is injected into each batch, the proppant (the proppant is quartz sand with 70-140 meshes) is carried by the low-viscosity slickwater, and the sand ratio carrying the proppant is increased along with the increase of the injected batches;
And S3, finally, 4 batches of high-viscosity slick water in the second sand-carrying fluid are injected into the stratum of the fracturing section, when the high-viscosity slick water is injected into each batch, the high-viscosity slick water is adopted to carry propping agent (the propping agent is 40-70 meshes of ceramsite), and the sand ratio of the propping agent is increased along with the increase of the injected batches.
When the second sand-carrying fluid is high-viscosity slick water, the second sand-carrying fluid is injected into the fracturing section, wherein the second sand-carrying fluid is injected into the stratum of the fracturing section in 10 batches, and when the second sand-carrying fluid is injected into the 1 st to 5 th batches, the propping agent is carried by the second sand-carrying fluid (the propping agent is 40-70 meshes of ceramsite), and the sand ratio of the propping agent is increased along with the increase of the injected batches; and when the second sand-carrying fluid is injected into the 7 th to 10 th batches, the second sand-carrying fluid is adopted to carry proppants (proppants are all 40-70 meshes of ceramsite), and the sand ratio of the proppants is increased along with the increase of the injected batches.
③ Determination of liquid volume and construction displacement
In order to determine the optimal single-cluster liquid amount, a change curve of the reservoir reforming volume (reservoir reforming stimulated volume) with the single-cluster liquid amount is obtained by simulating the reservoir reforming volume (reservoir reforming stimulated volume) when different single-cluster liquid amounts, and as a result, as shown in fig. 2, when the single-cluster liquid amount reaches more than 1800m 3, the increase amplitude of the reservoir reforming volume (reservoir reforming stimulated volume) is gradually reduced, so that the reservoir reforming volume (reservoir reforming stimulated volume) is taken as an optimization target, the optimization construction scale (total liquid amount) is 1800-2100 m 3, and the single-cluster liquid amount is 360-400 m 3.
In order to determine the optimal construction displacement, the formation net pressure change with time of the carrier fluid under different construction displacement is simulated to obtain formation net pressure change with time of different construction displacement, and the result is shown in figure 3 (in figure 3, #1 represents the formation net pressure change with time of the construction displacement of 9m 3/min, #2 represents the formation net pressure change with time of the construction displacement of 10m 3/min, #3 represents the formation net pressure change with time of the construction displacement of 11m 3/min, #4 represents the formation net pressure change with time of the construction displacement of 12m 3/min, #5 represents the formation net pressure change with time of the construction displacement of 13m 3/min, #6 represents the formation net pressure change with time of the construction displacement of 14m 3/min, and in order to improve the complexity of cracks, the construction displacement of 14-16 m 3/min, namely, the formation net pressure difference between the two directions of the well is calculated according to the ground stress profile is about 13MPa, namely, the formation net pressure can be simulated under the condition that the formation net pressure of no less than 14m 3562/min is ensured under the condition of being larger than 13MPa when the displacement is equal to the displacement of 3.
③ Fracturing construction
When carrying out fracturing construction on the first fracturing section, the second fracturing section, the third fracturing section and the fourth fracturing section of the well A, the specific steps are as follows:
s1, carrying out fracturing construction on a first fracturing segment
When the first fracturing section of the well A is subjected to fracturing construction, firstly, plugging removing agent is injected into a stratum, then, high-viscosity slickwater in first pre-fluid is injected into the stratum to carry out pre-joint making, then, seepage liquid in the first pre-fluid is injected into the stratum, then, low-viscosity slickwater in the first pre-fluid is injected into the stratum in 5 batches, when the low-viscosity slickwater is injected into the 1 st batch, the 2 nd batch, the 4 th batch and the 5 th batch, the low-viscosity slickwater is adopted to carry proppants (proppants are quartz sand with 70-140 meshes), the sand ratio of the proppants is increased along with the increase of the injected batches, then, high-viscosity slickwater in the first pre-fluid is injected into the stratum, then, first sand-carrying fluid is injected into the stratum in 6 batches (the first sand-carrying fluid is identical with the high-viscosity slickwater in the first pre-fluid), and when the first sand-carrying fluid is injected into each batch, adopting a first sand-carrying fluid to carry propping agent (propping agent is 40-70 meshes of ceramsite), increasing the sand ratio of the propping agent along with the increase of injection batches, then injecting a middle top fluid (the middle top fluid is the same as the high-viscosity slick water in the first front fluid) into a stratum, adopting the middle top fluid to carry propping agent (the propping agent consists of 24 temporary blocking balls with the grain size of 3cm and 100kg of temporary blocking agent) during the injection of the middle top fluid, then injecting the seepage liquid in a second front fluid into the stratum, then injecting the low-viscosity slick water in the second front fluid into the stratum in 2 batches, adopting the low-viscosity slick water to carry propping agent (the propping agent is 70-140 meshes of quartz sand) during the injection of each batch, increasing the sand ratio of the propping agent along with the increase of the injection batches, then injecting the high-viscosity slick water in the second front fluid into the stratum, then 6 batches of high-viscosity slickwater in the second sand-carrying fluid are injected into the stratum (the high-viscosity slickwater in the second sand-carrying fluid is the same as the high-viscosity slickwater in the first front fluid), when the 1 st to 5 th batches of high-viscosity slickwater are injected, the high-viscosity slickwater is used for carrying proppants (proppants are 40-70 meshes of ceramsite) when each batch of high-viscosity slickwater is injected, the sand ratio of the proppants is increased along with the increase of the injected batches, when the 6 th batch of high-viscosity slickwater is injected, the high-viscosity slickwater is used for carrying proppants (the proppants consist of temporary plugging balls with 20 grain diameters of 3cm and temporary plugging agents with 100 kg), then the imbibitions in the second sand-carrying fluid are injected into the stratum (imbibitions in the second sand-carrying fluid are the same as imbibitions in the first front fluid), then injecting low-viscosity slickwater in the second sand-carrying fluid (the low-viscosity slickwater in the second sand-carrying fluid is the same as the low-viscosity slickwater in the first front fluid) into the stratum in 2 batches, when the low-viscosity slickwater is injected into each batch, adopting the low-viscosity slickwater to carry proppants (the proppants are quartz sand with 70-140 meshes), the sand ratio of the proppants is increased along with the increase of the injected batch, then injecting high-viscosity slickwater in the second sand-carrying fluid (the high-viscosity slickwater in the second sand-carrying fluid is the same as the high-viscosity slickwater in the first front fluid) into the stratum in 4 batches, when the high-viscosity slickwater is injected into each batch, adopting the high-viscosity slickwater to carry proppants (the proppants are ceramic particles with 40-70 meshes), and the sand ratio of the propping fluid (the propping fluid is the same as the low-viscosity slickwater in the first front fluid) is injected into the stratum for displacement, and (3) finishing the fracturing operation of the first fracturing stage, after finishing the fracturing operation, soaking the well for 7 days, and then opening the flowback. Meanwhile, software is adopted to simulate the extension schematic of cracks at the positions of 6 perforation clusters in the first fracturing section in the fracturing process, and the result is shown in fig. 4.
The fracturing pumping parameters and the simulated fracture parameters and fracturing pumping procedures of the first fracturing stage of the A well are counted, and the results are shown in tables 13 and 14 respectively. The construction displacement and the sand ratio can be adjusted according to the pressure in the construction process.
Table 13 fracture pumping parameters and simulated fracture parameter statistics for fracturing the first fracture zone of well a
Table 14 statistics of fracturing pump injection program for fracturing a first fracturing stage of well a
When the first fracturing section of the well A is subjected to fracturing construction, firstly, in-situ self-generated CO 2 is adopted for pretreatment, bicarbonate solution and active acid solution are injected into the stratum, on one hand, the acid solution can reduce the fracture pressure of the reservoir, erode carbonate minerals and increase pore connectivity; on the other hand, CO 2 gas is generated by deep reaction of the oil layer, so that the fluidity of crude oil can be improved, and meanwhile, a large amount of heat is released, so that the cold damage of the reservoir in the near-wellbore zone is reduced; then injecting high-viscosity slick water to make a seam in advance, then injecting seepage liquid, increasing pore pressure, increasing microscopic damage degree of rock, reducing formation difficulty of complex seams, effectively replacing oil flow in micro-pores, improving post-compaction effect, then injecting low-viscosity slick water to expand the seam, injecting high-viscosity slick water to form a main seam, then injecting high-viscosity slick water into a stratum to control fine seam height by adopting a variable displacement pump injection construction process, matching different seam width cracks by adopting a combined grain size sand adding process, realizing full support of the cracks, and injecting propping agents consisting of temporary plugging balls and temporary plugging agents into the stratum along with the high-viscosity slick water to temporarily plug the sleeve wall opening and the stratum, wherein the temporary plugging balls are used for temporarily plugging the sleeve wall opening, and the temporary plugging agents are used for temporarily plugging the stratum.
S2, carrying out fracturing construction on the second fracturing segment
When the second fracturing section of the well A is subjected to fracturing construction, firstly, plugging removing agent is injected into the stratum, then, high-viscosity slickwater in first pre-fluid is injected into the stratum to perform pre-joint making, then, seepage liquid in the first pre-fluid is injected into the stratum, then, low-viscosity slickwater in the first pre-fluid is injected into the stratum in 5 batches, when low-viscosity slickwater is injected into the 1 st batch, the 2 nd batch, the 4 th batch and the 5 th batch, the low-viscosity slickwater is adopted to carry proppants (proppants are quartz sand with 70-140 meshes), the sand ratio of the proppants is increased along with the increase of the injected batches, then, high-viscosity slickwater in the first pre-fluid is injected into the stratum, then, first sand-carrying fluid is injected into the stratum in 6 batches (the first sand-carrying fluid is identical with the high-viscosity slickwater in the first pre-fluid), and when the first sand-carrying fluid is injected into each batch, adopting a first sand-carrying fluid to carry propping agent (propping agent is 40-70 meshes of ceramsite), increasing the sand ratio of the propping agent along with the increase of injection batches, then injecting a middle top fluid (the middle top fluid is the same as the high-viscosity slick water in the first front fluid) into a stratum, adopting the middle top fluid to carry propping agent (the propping agent consists of 20 temporary blocking balls with the grain size of 3cm and 100kg of temporary blocking agent) during the injection of the middle top fluid, then injecting the seepage liquid in a second front fluid into the stratum, then injecting the low-viscosity slick water in the second front fluid into the stratum in 2 batches, adopting the low-viscosity slick water to carry propping agent (the propping agent is 70-140 meshes of quartz sand) during the injection of each batch, increasing the sand ratio of the propping agent along with the increase of the injection batches, then injecting the high-viscosity slick water in the second front fluid into the stratum, injecting second sand-carrying fluid (the second sand-carrying fluid is the same as the high-viscosity slickwater in the first pre-fluid) into the stratum in 10 batches, wherein when the second sand-carrying fluid is injected into the 1 st to 5 th batches, the second sand-carrying fluid is adopted to carry proppants (the proppants are all 40-70-mesh ceramsite), and the sand ratio of the proppants is increased along with the increase of the injected batches; and when the 7 th to 10 th batches are injected with the second sand-carrying fluid, carrying proppants (proppants are 40-70 meshes of ceramsite) by the second sand-carrying fluid, increasing the sand ratio of the proppants along with the increase of the injected batches, and finally injecting displacement fluid (the displacement fluid is the same as low-viscosity slickwater in the first pre-fluid) into the stratum for displacement, so as to finish the fracturing operation of the second fracturing stage, and after the fracturing operation is finished, carrying out well stewing for 10 days, and then discharging flowbacks. Meanwhile, software is adopted to simulate the extension schematic of cracks at the positions of 4 perforation clusters in the second fracturing section in the fracturing process, and the result is shown in fig. 5.
The fracturing pumping parameters and simulated fracture parameters and fracturing pumping procedures were counted when the second fracturing stage of the a well was subjected to fracturing construction, and the results are shown in tables 15 and 16, respectively. The construction displacement and the sand ratio can be adjusted according to the pressure in the construction process.
Table 15 statistics of fracture pumping parameters and simulated fracture parameters for fracturing the second fracture zone of well a
Table 16 statistics of fracturing pump injection program for fracturing construction of the second fracturing stage of well a
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S3, carrying out fracturing construction on the third fracturing segment
When the third fracturing section of the A well is subjected to fracturing construction, firstly, plugging removing agent is injected into the stratum, then, high-viscosity slickwater in first pre-fluid is injected into the stratum to perform pre-joint making, then, seepage liquid in the first pre-fluid is injected into the stratum, then, low-viscosity slickwater in the first pre-fluid is injected into the stratum in5 batches, when low-viscosity slickwater is injected into the 1 st batch, the 2 nd batch, the 4 th batch and the 5 th batch, the low-viscosity slickwater is adopted to carry proppants (proppants are quartz sand with 70-140 meshes), the sand ratio of the proppants is increased along with the increase of the injected batches, then, high-viscosity slickwater in the first pre-fluid is injected into the stratum, then, first sand-carrying fluid is injected into the stratum in 6 batches (the first sand-carrying fluid is identical with the high-viscosity slickwater in the first pre-fluid), and when the first sand-carrying fluid is injected into each batch, adopting a first sand-carrying fluid to carry propping agent (propping agent is 40-70 meshes of ceramsite), increasing the sand ratio of the propping agent along with the increase of injection batches, then injecting a middle top fluid (the middle top fluid is the same as the high-viscosity slick water in the first front fluid) into a stratum, adopting the middle top fluid to carry propping agent (the propping agent consists of 20 temporary blocking balls with the grain size of 3cm and 100kg of temporary blocking agent) during the injection of the middle top fluid, then injecting the seepage liquid in a second front fluid into the stratum, then injecting the low-viscosity slick water in the second front fluid into the stratum in 2 batches, adopting the low-viscosity slick water to carry propping agent (the propping agent is 70-140 meshes of quartz sand) during the injection of each batch, increasing the sand ratio of the propping agent along with the increase of the injection batches, then injecting the high-viscosity slick water in the second front fluid into the stratum, then 6 batches of high-viscosity slickwater in the second sand-carrying fluid are injected into the stratum (the high-viscosity slickwater in the second sand-carrying fluid is the same as the high-viscosity slickwater in the first front fluid), when the 1 st to 5 th batches of high-viscosity slickwater are injected, the high-viscosity slickwater is used for carrying proppants (proppants are 40-70 meshes of ceramsite) when each batch of high-viscosity slickwater is injected, the sand ratio of the proppants is increased along with the increase of the injected batches, when the 6 th batch of high-viscosity slickwater is injected, the high-viscosity slickwater is used for carrying proppants (the proppants consist of temporary plugging balls with 20 grain diameters of 3cm and temporary plugging agents with 100 kg), then the imbibitions in the second sand-carrying fluid are injected into the stratum (imbibitions in the second sand-carrying fluid are the same as imbibitions in the first front fluid), then injecting the low-viscosity slickwater in the second sand-carrying fluid (the low-viscosity slickwater in the second sand-carrying fluid is the same as the low-viscosity slickwater in the first front fluid) into the stratum in 2 batches, carrying proppants (proppants are quartz sand with 70-140 meshes) by adopting the low-viscosity slickwater when the low-viscosity slickwater in the second sand-carrying fluid is injected into each batch, increasing the sand ratio of the proppants with the increase of the injected batches, then injecting the high-viscosity slickwater in the second sand-carrying fluid (the high-viscosity slickwater in the second sand-carrying fluid is the same as the high-viscosity slickwater in the first front fluid) into the stratum in 4 batches, adopting the high-viscosity slickwater to carry proppants (proppants are ceramic grains with 40-70 meshes) when the high-viscosity slickwater is injected into each batch, and increasing the sand ratio of the proppants with the increase of the injected batches, and finally, injecting displacement fluid (the displacement fluid is the same as low-viscosity slickwater in the first pre-fluid) into the stratum for displacement, completing fracturing operation of the third fracturing stage, after the fracturing operation is completed, performing well stewing for 12 days, and then performing open flow flowback. Meanwhile, software is adopted to simulate the extension schematic of cracks at the positions of 5 perforation clusters in the third fracturing section in the fracturing process, and the result is shown in fig. 6.
The fracturing pumping parameters and simulated fracture parameters and fracturing pumping procedures were counted when the third fracturing stage of the a well was subjected to fracturing construction, and the results are shown in tables 17 and 18, respectively. The construction displacement and the sand ratio can be adjusted according to the pressure in the construction process.
Table 17 statistics of fracture parameters obtained by simulation of fracturing pump injection parameters during fracturing construction of the third fracturing stage of well a
Table 18 statistics of fracturing pump injection program for fracturing construction of the third fracturing stage of well a
S4, carrying out fracturing construction on the fourth fracturing segment
When the fourth fracturing section of the A well is subjected to fracturing construction, firstly, plugging removing agent is injected into the stratum, then, high-viscosity slickwater in first pre-fluid is injected into the stratum to carry out pre-joint making, then, seepage liquid in the first pre-fluid is injected into the stratum, then, low-viscosity slickwater in the first pre-fluid is injected into the stratum in 5 batches, when the low-viscosity slickwater is injected into the 1 st batch, the 2 nd batch, the 4 th batch and the 5 th batch, the low-viscosity slickwater is adopted to carry proppants (proppants are quartz sand with 70-140 meshes), the sand ratio of the proppants is increased along with the increase of the injected batches, then, high-viscosity slickwater in the first pre-fluid is injected into the stratum, then, first sand-carrying fluid is injected into the stratum in 6 batches (the first sand-carrying fluid is identical with the high-viscosity slickwater in the first pre-fluid), and when the first sand-carrying fluid is injected into each batch, adopting a first sand-carrying fluid to carry propping agent (propping agent is 40-70 meshes of ceramsite), increasing the sand ratio of the propping agent along with the increase of injection batches, then injecting a middle top fluid (the middle top fluid is the same as the high-viscosity slick water in the first front fluid) into a stratum, adopting the middle top fluid to carry propping agent (the propping agent consists of 20 temporary blocking balls with the grain size of 3cm and 100kg of temporary blocking agent) during the injection of the middle top fluid, then injecting the seepage liquid in a second front fluid into the stratum, then injecting the low-viscosity slick water in the second front fluid into the stratum in 2 batches, adopting the low-viscosity slick water to carry propping agent (the propping agent is 70-140 meshes of quartz sand) during the injection of each batch, increasing the sand ratio of the propping agent along with the increase of the injection batches, then injecting the high-viscosity slick water in the second front fluid into the stratum, then 6 batches of high-viscosity slickwater in the second sand-carrying fluid are injected into the stratum (the high-viscosity slickwater in the second sand-carrying fluid is the same as the high-viscosity slickwater in the first front fluid), when the 1 st to 5 th batches of high-viscosity slickwater are injected, the high-viscosity slickwater is used for carrying proppants (proppants are 40-70 meshes of ceramsite) when each batch of high-viscosity slickwater is injected, the sand ratio of the proppants is increased along with the increase of the injected batches, when the 6 th batch of high-viscosity slickwater is injected, the high-viscosity slickwater is used for carrying proppants (the proppants consist of temporary plugging balls with 20 grain diameters of 3cm and temporary plugging agents with 100 kg), then the imbibitions in the second sand-carrying fluid are injected into the stratum (imbibitions in the second sand-carrying fluid are the same as imbibitions in the first front fluid), then injecting low-viscosity slickwater in the second sand-carrying fluid (the low-viscosity slickwater in the second sand-carrying fluid is the same as the low-viscosity slickwater in the first front fluid) into the stratum in 2 batches, when the low-viscosity slickwater is injected into each batch, adopting the low-viscosity slickwater to carry proppants (the proppants are quartz sand with 70-140 meshes), the sand ratio of the proppants is increased along with the increase of the injected batch, then injecting high-viscosity slickwater in the second sand-carrying fluid (the high-viscosity slickwater in the second sand-carrying fluid is the same as the high-viscosity slickwater in the first front fluid) into the stratum in 4 batches, when the high-viscosity slickwater is injected into each batch, adopting the high-viscosity slickwater to carry proppants (the proppants are ceramic particles with 40-70 meshes), and the sand ratio of the propping fluid (the propping fluid is the same as the low-viscosity slickwater in the first front fluid) is injected into the stratum for displacement, and (3) finishing the fracturing operation of the fourth fracturing stage, after finishing the fracturing operation, stewing the well for 15 days, and then opening and spraying flowback. Meanwhile, software is adopted to simulate the extension schematic diagram of cracks at the positions of 4 perforation clusters in the fourth fracturing section in the fracturing process, and the result is shown in fig. 7.
The fracturing pumping parameters, the simulated fracture parameters and the fracturing pumping program of the fourth fracturing stage of the A well are counted, and the results are shown in tables 19 and 20 respectively. The construction displacement and the sand ratio can be adjusted according to the pressure in the construction process.
Table 19 statistics of fracture pumping parameters and simulated fracture parameters during fracturing construction of the fourth fracture zone of well a
Table 20 statistics of fracturing pump injection program for fracturing construction of the fourth fracturing stage of well a
In the fracturing construction of the well A, the production curve of the well A is recorded, and as shown in the graph 8, after the well A is measured, the production is stopped for 7 months and 20 days, the initial daily liquid production is 43.1 square, the daily oil production is 19.3 square, the liquid production is 31.5 square/day, and the oil production is 20.8 square/day in a stable production state.
In order to evaluate the fracturing effect of different fracturing methods, taking the adjacent wells (M well, N well, P well and Q well) of the A well and the A well as fracturing objects, the well logging curves (resistivity logging curves) show that the adjacent wells (M well, N well, P well and Q well) of the A well and the A well have considerable exploitation potential (namely, the deviation of the same logging data corresponding to the same depth of the A well and each adjacent well is not more than 5 percent), and the specific method for carrying out fracturing construction on the adjacent wells (M well, N well, P well and Q well) of the A well is shown in comparative examples 1-4.
Comparative example 1
The fracturing method of the sandwich type shale oil and gas reservoir of the present comparative example is different from the fracturing method of the sandwich type shale oil and gas reservoir of the embodiment 3 in that the fracturing method of the sandwich type shale oil and gas reservoir of the present comparative example fractures the adjacent well M well of the a well (the M well and the a well have comparable exploitation potential), and the fracturing method of the sandwich type shale oil and gas reservoir of the present comparative example omits the step of fracturing plugging agent, but directly injects the high-viscosity slick water in the first pre-fluid into each fracturing section of the M well to perform pre-joint formation.
In the fracturing construction of the M well, the production curve of the M well was recorded, and as shown in FIG. 9, the production curve was obtained by cutting off the production curve for 7 months and 21 days after the M well was taken, and the production curve was 20.9 times of the initial daily production fluid and 0.6 times of the daily production oil. In a stable production state, the liquid yield is 18.1 square/day, and the oil yield is 1.3 square/day.
Comparative example 2
The fracturing method of the sandwich type shale oil and gas reservoir of the present comparative example is different from the fracturing method of the sandwich type shale oil and gas reservoir of the embodiment 3 in that the fracturing method of the sandwich type shale oil and gas reservoir of the present comparative example fractures the adjacent well N well of the a well (the N well and the a well have comparable exploitation potential), and the seepage liquid used in the fracturing method of the sandwich type shale oil and gas reservoir of the present comparative example for fracturing each fracturing segment of the N well is the low-viscosity slickwater in the first pre-liquid used in the embodiment 3.
In the N-well fracturing construction, the production curve of the N-well was recorded, and as shown in fig. 10, the production curve was obtained from the results of the N-well, and as shown in fig. 10, the production was completed for 7 months and 21 days, the production rate was 5.7 times for the initial daily production, and the production rate was 0.1 times for the daily production. In a stable production state, the liquid yield is 2.9 square/day, and the oil yield is 0.1 square/day.
Comparative example 3
The fracturing method of the sandwich type shale oil and gas reservoir of the present comparative example is different from the fracturing method of the sandwich type shale oil and gas reservoir of the embodiment 3 in that the fracturing method of the sandwich type shale oil and gas reservoir of the present comparative example fractures the adjacent well P well of the a well (the P well and the a well have comparable exploitation potential), and the fracturing method of the sandwich type shale oil and gas reservoir of the present comparative example omits the step of injecting the highly viscous slick water in the first pre-fluid to perform pre-joint formation after injecting the plugging removing agent into the stratum when the fracturing construction is performed on each fracturing section of the P well.
In the P-well fracturing construction, the production curve of the P-well was recorded, and as shown in fig. 11, it was found from fig. 11 that the production was completed by 15.7 in the initial daily production of liquid and 1.3 in the daily production of oil after the P-well was completed for 7 months and 14 days. In a stable production state, the liquid yield is 18.2 square/day, and the oil yield is 1.1 square/day.
Comparative example 4
The fracturing method of the sandwich type shale oil and gas reservoir of the present comparative example is different from the fracturing method of the sandwich type shale oil and gas reservoir of the embodiment 3 in that the fracturing method of the sandwich type shale oil and gas reservoir of the present comparative example fractures the adjacent well Q well of the a well (the Q well and the a well have comparable mining potential), and the fracturing method of the sandwich type shale oil and gas reservoir of the present comparative example injects the low-viscosity slickwater in the first pre-fluid into the stratum in 5 batches when the fracturing construction is performed on each fracturing section of the Q well, and then injects the first sand-carrying fluid into the stratum in 6 batches directly without injecting the high-viscosity slickwater in the first pre-fluid.
In the construction of the Q well fracturing, the production curve of the Q well was recorded, and as shown in FIG. 12, the production of the Q well was stopped for 7 months and 12 days after the Q well was taken, the production of 11.9 parts of the initial daily production fluid and 4.3 parts of the daily production oil were recorded. In a stable production state, the liquid yield is 4.8 square/day, and the oil yield is 1.5 square/day.
Claims (10)
1. The fracturing fluid for the interlayer shale oil and gas reservoir is characterized by comprising a blocking remover, a seepage liquid, low-viscosity slick water and high-viscosity slick water; the blocking remover comprises an agent A and an agent B, wherein the agent A mainly comprises a salt capable of releasing carbon dioxide and water, the salt capable of releasing carbon dioxide is carbonate and/or bicarbonate, the mass fraction of the salt capable of releasing carbon dioxide in the agent A is 10-12%, the agent B mainly comprises an acidic compound and water, and the mass fraction of the acidic compound in the agent B is 1.82-3.72%;
The imbibition liquid mainly comprises a wetting regulator, a clay stabilizer, a resistance reducing agent and water, wherein the mass fraction of the wetting regulator is not more than 0.3%, the mass fraction of the clay stabilizer is not more than 0.3%, and the mass fraction of the resistance reducing agent is not more than 0.1%;
the low-viscosity slick water mainly comprises a resistance reducing agent, a clay stabilizer, a wetting regulator and water, wherein the mass fraction of the resistance reducing agent in the low-viscosity slick water is not less than 0.2%, the mass fraction of the clay stabilizer is not less than 0.3%, and the mass fraction of the wetting regulator is not less than 0.2%;
The high-viscosity slick water mainly comprises a resistance reducing agent, a clay stabilizer, a waterproof locking agent and water, wherein the mass fraction of the resistance reducing agent in the high-viscosity slick water is not less than 0.6%, the mass fraction of the clay stabilizer is not less than 0.3%, and the mass fraction of the waterproof locking agent is not less than 0.3%.
2. The fracturing fluid for a laminated shale oil and gas reservoir of claim 1, wherein the agent a and the agent B further independently comprise a cleanup additive, wherein the cleanup additive comprises 0.5-0.8% by mass of the cleanup additive in the agent a and 0.5-0.7% by mass of the cleanup additive in the agent B.
3. The fracturing fluid for a laminated shale oil and gas reservoir of claim 1, wherein the agent a and the agent B further independently comprise ammonium chloride, and the mass fraction of ammonium chloride in the agent a and the agent B is independently 2-4%.
4. The fracturing fluid for a sandwich shale oil and gas reservoir of any of claims 1-3, wherein the agent B further comprises a corrosion inhibitor, and the mass fraction of the corrosion inhibitor in the agent B is 1-3%.
5. The fracturing fluid for a laminated shale oil and gas reservoir of any of claims 1-3, wherein the agent B further comprises an iron ion stabilizer, and the mass fraction of the iron ion stabilizer in the agent B is 1-3%.
6. The fracturing method of the sandwich shale oil and gas reservoir is characterized by comprising the following steps of:
(1) Determining section shower hole positions according to geological desserts and engineering desserts of the target interlayer shale oil and gas reservoir;
(2) Bridge plugs and shower holes are combined for construction;
(3) Sequentially injecting a blocking remover, a first pad fluid, a first sand-carrying fluid, a middle top fluid, a second pad fluid, a second sand-carrying fluid and a displacement fluid into each fracturing segment to realize fracturing construction of each fracturing segment; the plugging removing agent is the plugging removing agent in the fracturing fluid according to any one of claims 1 to 5; the first and second pad fluids independently comprising a imbibition fluid, a low viscosity slickwater, and a high viscosity slickwater in the fracturing fluid of any one of claims 1-5; the first sand-carrying fluid and the middle top fluid are independently high-viscosity slickwater in the fracturing fluid according to any one of claims 1-5; the second sand-carrying fluid is high-viscosity slick water in the fracturing fluid according to any one of claims 1-5, or the second sand-carrying fluid comprises the seepage fluid, low-viscosity slick water and high-viscosity slick water in the fracturing fluid according to any one of claims 1-5; the displacement fluid is a low viscosity slickwater in the fracturing fluid of any one of claims 1-5.
7. The fracturing method of a sandwich shale oil and gas reservoir of claim 6, wherein the injection of the plugging removing agent into the fracturing segment is sequential injection of agent a and agent B of the plugging removing agent into the fracturing segment.
8. The fracturing method of a sandwich shale oil and gas reservoir of claim 6 wherein injecting the first pad into the fracturing section is sequentially injecting high viscosity slick water, imbibition fluid, low viscosity slick water and high viscosity slick water in the first pad into the fracturing section, wherein the low viscosity slick water is injected in a plurality of batches and when the low viscosity slick water is injected in a portion of the plurality of batches, the proppant is carried with the low viscosity slick water and the sand ratio carrying the proppant increases with increasing injected batches.
9. The fracturing method of the sandwich shale oil and gas reservoir of claim 6, wherein the step of injecting the first sand-carrying fluid into the fracturing section is to inject the first sand-carrying fluid into the fracturing section in a plurality of batches, wherein when each batch of the first sand-carrying fluid is injected, the proppant is carried by the first sand-carrying fluid, and the sand ratio carrying the proppant increases with the increase of the injected batches; when the middle propping liquid is injected into the fracturing section, the middle propping liquid is adopted to carry a propping agent mainly composed of temporary plugging balls and temporary plugging agents; and injecting the second pre-fluid into the fracturing section, namely sequentially injecting the seepage liquid, the low-viscosity slickwater and the high-viscosity slickwater in the second pre-fluid into the fracturing section, wherein the low-viscosity slickwater is injected in at least 2 batches, when the low-viscosity slickwater is injected into each batch, the proppant is carried by the low-viscosity slickwater, and the sand ratio carrying the proppant is increased along with the increase of the injected batches.
10. The fracturing method of the sandwich shale oil and gas reservoir according to claim 6, wherein the second sand-carrying fluid is high-viscosity slick water in the fracturing fluid according to any one of claims 1 to 5, the second sand-carrying fluid is injected into the fracturing section in a plurality of batches, and when part of the batches are injected into the second sand-carrying fluid, the second sand-carrying fluid is used for carrying proppants;
The second sand-carrying fluid comprises seepage liquid, low-viscosity slick water and high-viscosity slick water in the fracturing fluid according to any one of claims 1-5, and the injection of the second sand-carrying fluid into the fracturing section is to sequentially inject the high-viscosity slick water, the seepage liquid, the low-viscosity slick water and the high-viscosity slick water in the second sand-carrying fluid into the fracturing section;
Before the imbibition liquid in the second sand-carrying liquid is injected into the fracturing section, the high-viscosity slickwater in the second sand-carrying liquid is injected into the fracturing section in a plurality of batches, when the high-viscosity slickwater in the second sand-carrying liquid is injected into each batch, the propping agent is carried by the high-viscosity slickwater in the second sand-carrying liquid, the propping agent carried by the high-viscosity slickwater in the second sand-carrying liquid injected in each batch before the last batch is ceramsite, the sand ratio of the propping agent carried by the high-viscosity slickwater in the second sand-carrying liquid injected in each batch before the last batch is increased along with the increase of the injected batch, and the propping agent carried by the high-viscosity slickwater in the second sand-carrying liquid injected in the last batch consists of a temporary plugging ball and a temporary plugging agent;
And after the imbibition liquid in the second sand-carrying liquid is injected into the fracturing section, injecting the high-viscosity slick water in the second sand-carrying liquid into the fracturing section is to inject a plurality of batches of the high-viscosity slick water in the second sand-carrying liquid into the fracturing section, wherein when each batch is injected with the high-viscosity slick water, the high-viscosity slick water is adopted to carry proppants, and the sand ratio carrying proppants is increased along with the increase of the injected batches.
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