Liquid injection temporary plugging parameter determination method based on horizontal well section production law

Abstract

The invention provides a liquid injection temporary plugging parameter determination method based on a horizontal well section production law, and belongs to the technical field of oil and gas field development engineering, and the method comprises the following steps: obtaining field geology and engineering data information; the erosion ratio of holes of the liquid injection well is calculated, and a main liquid outlet section cluster is delimited; predicting the liquid inlet capacity and the injection difference of each segment cluster, and designing a pump injection program; designing an injection slug, and injecting according to the concentration sequence from high to low; a temporary plugging agent combination is optimized according to the hole erosion proportion in combination with a fracturing process; and designing temporary plugging times and dosage. On the basis of the steps, parameters such as temporary plugging times, multi-particle-size optimization combination proportion and dosage of a temporary plugging agent are formulated according to horizontal well liquid injection in a one-well-one-strategy mode, and the problems that due to general liquid injection of the horizontal well, liquid inlet of each section cluster is not uniform, the section use degree is low, and stratum energy cannot be comprehensively and effectively supplemented are effectively solved; and technical support and guidance are provided for improving the recovery efficiency in the later stage of oilfield development.

Description

TECHNICAL FIELD

[0001] The present application belongs to the technical field of oil and gas field development engineering, and particularly relates to a liquid injection temporary plugging parameter determination method based on a horizontal well profile production rule. BACKGROUND

[0002] Affected by the characteristics and development mode of conglomerate reservoirs, the decline rate of the depletion-type developed reservoirs is large, the primary recovery rate is low (11.9% to 16.8%), and the remaining oil reserves around the horizontal well are abundant. Since the water drive has little effect on the recovery, it is urgent to explore a more efficient enhanced oil recovery mode. Field tests show that the liquid injection energy-increasing huff and puff of the horizontal well can effectively improve the recovery of the dense conglomerate reservoir. Since the effective opening rates of the clusters in different stages are quite different under different fracturing processes, and the liquid production degrees of different levels are different, the liquid injection energy-increasing huff and puff of the horizontal well will lead to uneven liquid injection of the clusters in the horizontal well, and the injected fluid mainly enters the reservoir along the dominant fracture channel, which has the risk of low profile production degree and inability to fully and effectively supplement the formation energy. SUMMARY

[0003] To solve the above problems of the prior art, the present application provides a liquid injection temporary plugging parameter determination method based on a horizontal well profile production rule. In the liquid injection process of the horizontal well, the liquid injection parameters are optimized by adding chemical temporary plugging agents to ensure that the energy-increasing liquid is uniformly distributed in each perforation cluster, the formation energy is effectively supplemented, the liquid injection is diverted and distributed, the liquid injection of each cluster is uniform, the overall liquid injection effect of the horizontal section is improved, and full imbibition replacement is achieved.

[0004] To achieve the above object, the present application provides the following technical scheme:

[0005] A liquid injection temporary plugging parameter determination method based on a horizontal well profile production rule, comprising the following steps:

[0006] Step S1: Collect downhole data through a downhole measuring instrument, judge the erosion degree of each cluster hole, calculate the hole erosion proportion, judge the liquid production contribution of each cluster according to the liquid production profile monitoring characteristics, and demarcate the main liquid production cluster.

[0007] Step S2: Predict the liquid injection capacity and injection difference of each cluster, and design a pump injection program according to the principle that the liquid injection amount of each cluster is positively correlated with the liquid production amount and the liquid is uniformly injected in the entire horizontal well section.

[0008] Step S3: Design an injection slug, and sequentially inject each slug from high to low liquid injection concentration while keeping the total liquid injection concentration at 0.2%.

[0009] Step S4: Optimize the combination of temporary plugging agents with different particle sizes according to the hole erosion proportion and the fracturing process.

[0010] Step S5: Design the number of segments to be temporarily blocked in the liquid inlet channel, the number of times to temporarily block, the total amount of temporary blocking agent, and the dosage of temporary blocking agent per time.

[0011] Furthermore, step S1 includes:

[0012] Step S101: Obtain on-site geological and engineering data, evaluate the fracturing effect of different fracturing processes, and collect big data on pore erosion rate;

[0013] Step S102: Analyze big data on the perforation erosion rate under different fracturing processes to determine the effective perforation opening rate of injection wells under different fracturing processes (to guide the subsequent combination ratio of temporary plugging agent particle size).

[0014] Step S103: Collect downhole data using downhole measuring instruments, classify the perforations into Class I, Class II, and Class III perforations according to their diameter, and calculate the perforation erosion ratio of different types of perforations in the injection well (to guide the subsequent combination ratio of temporary plugging agent particle size).

[0015] Step S104: Based on the characteristics of the liquid production profile monitoring, determine the contribution of each cluster to the liquid production and delineate the main liquid production clusters.

[0016] Furthermore, in step S102, the fracturing process includes large-section multi-cluster fracturing, continuous tubing bottom seal dragging, and conventional bridge plug.

[0017] Furthermore, in step S103, the formula for calculating the percentage of hole erosion is the number of holes of each type / the total number of monitored holes.

[0018] Furthermore, the principle for defining the main liquid output clusters is as follows: sorted according to the amount of liquid produced as shown in the liquid production profile, the clusters ranked before the preset ranking are the main liquid output clusters.

[0019] Furthermore, in step S4, the temporary plugging agent is classified into Type 1, Type 2, Type 3, Type 4, Type 5, Type 6, Type 7, Type 8, and Type 9 according to particle size, wherein:

[0020] 1mm≤Particle size of Type 1 < 3mm, 3≤Particle size of Type 2 < 5mm, 5≤Particle size of Type 3 ≤ 8mm, 13≤Particle size of Type 4 ≤ 15mm, 18≤Particle size of Type 5 < 22mm, 22≤Particle size of Type 6 < 24mm, 24≤Particle size of Type 7 < 28mm, 28≤Particle size of Type 8 < 32mm, 32≤Particle size of Type 9 ≤ 35mm.

[0021] Furthermore, in step S4, the optimization principle for combinations of temporary plugging agents with different particle sizes is as follows:

[0022] For horizontal wells using coiled tubing bottom-sealed fracturing technology, the ratio of temporary plugging agent at the fracture opening is: Type 7: Type 8 = 7:3;

[0023] For horizontal wells using large-section multi-cluster or conventional bridge plug combined with large-section multi-cluster fracturing technology, the ratio of temporary plugging agent at the fracture opening is: Type 5: Type 7: Type 8 = 7:2:1;

[0024] For horizontal wells using conventional bridge plug fracturing technology, the ratio of temporary plugging agent at the fracture opening is: Type 5: Type 7 = 7:3.

[0025] Furthermore, in step S5, when designing the number of segments for temporary plugging of the fluid inlet channel, the number of injection segments per injection is controlled to be 1 / 4 to 1 / 3 of the total number of fracturing stages in a single well, based on the microseismic data from the fluid injection.

[0026] Furthermore, each well is temporarily plugged 2-3 times, with each plugging session covering 1 / 4 to 1 / 3 of the total effective number of holes in the well.

[0027] Furthermore, the total amount of temporary plugging agent should be designed to be 1.0 to 1.3 times the number of effective orifices.

[0028] Furthermore, for horizontal wells employing coiled tubing bottom sealing drag or large-section multi-cluster fracturing technology, the total amount of temporary plugging agent should be designed according to 1.3 times the number of effective perforations for a single temporary plugging operation;

[0029] For horizontal wells using conventional bridge plug fracturing technology, the total amount of temporary plugging agent should be designed based on 1.0 times the number of effective perforations for a single temporary plugging operation.

[0030] Furthermore, the amount of temporary plugging agent used at the joint opening of a single well is determined according to the following formula:

[0031] N = a × n × m / M × b

[0032] In the formula: N represents the amount of temporary plugging agent used at the joint of a single well, which is the same as the number of joints temporarily plugged; a represents the cluster stimulation utilization rate; n represents the total number of holes; m represents the number of temporary plugging times; M represents the number of slug plugging times; and b represents an empirical coefficient, which ranges from 1.0 to 1.3.

[0033] Furthermore, the temporary plugging dose is designed based on 0.25-0.35 times the effective orifice for a single temporary plugging.

[0034] Compared with the prior art, the present invention has the following beneficial effects:

[0035] 1. This invention determines temporary plugging parameters by combining multiple particle sizes, monitoring downhole production profiles, monitoring downhole measuring instruments, and analyzing fracturing processes. This effectively replenishes formation energy, achieves diversion and diversion of injected fluid, ensures uniform fluid injection into each cluster, improves the overall injection effect of horizontal sections, and fully achieves the purpose of permeation and replacement.

[0036] 2. This invention promotes the uniform distribution of energy-enhancing fluid in each perforation cluster by progressively setting the particle size of the temporary plugging agent, the number of temporary plugging clusters, the number of temporary plugging times per well, the number of temporary plugging holes per time, the total amount of temporary plugging agent, and the dosage of temporary plugging per time, thus achieving a "one well, one policy" approach. Attached Figure Description

[0037] Figure 1 This is a schematic flowchart of a method for determining injection temporary plugging parameters based on the dynamic law of horizontal well profile according to an embodiment of the present invention;

[0038] Figure 2 This is a production curve of horizontal well injection wells in a certain well area in 2021, according to an embodiment of the present invention.

[0039] Figure 3 This is a microseismic event diagram before and after temporary plugging of a horizontal well according to an embodiment of the present invention. Detailed Implementation

[0040] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0041] Therefore, the following detailed description of the embodiments of the invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the invention without inventive effort are within the scope of protection of the invention.

[0042] In this invention, unless otherwise explicitly specified and limited, the terms "installation," "connection," "linking," and "fixing," etc., should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a direct connection or an indirect connection through an intermediate medium. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0043] Furthermore, the technical solutions of the various embodiments can be combined with each other, but only if they are feasible for those skilled in the art. If the combination of technical solutions is contradictory or cannot be implemented, it should be considered that such combination of technical solutions does not exist and is not within the scope of protection claimed by this invention.

[0044] To better understand the purpose, structure, and function of this invention, the following description, in conjunction with the accompanying drawings, details a method for determining injection temporary plugging parameters based on the dynamic laws of horizontal well profiles.

[0045] Example 1

[0046] like Figure 1 As shown, this invention proposes a method for optimizing injection and temporary plugging parameters in horizontal wells. By combining downhole "eagle eye" monitoring, production profile monitoring characteristics, and multi-factor analysis considering differences in fracturing processes across wells, the injection and temporary plugging method is comprehensively determined. The specific steps are as follows:

[0047] 1. Obtain on-site geological and engineering data to evaluate the fracturing operation of each segment of a horizontal well under different fracturing techniques. The key feature is that by analyzing fracturing operation curves and bridge plug sealing conditions, the effectiveness of each fracturing segment can be determined. Specific fracturing operation curves can be categorized as pressure-time curves, flow rate-time curves, etc. The analysis of fracturing effectiveness is based on whether fractures initiate and propagate during the operation. Key characteristics include: rapid decrease in pump pressure and increase in flow rate; constant pump pressure and increase in flow rate; constant flow rate and rapid decrease in pump pressure after reaching a certain level. The presence of any one of these three characteristics indicates a good hydraulic fracture initiation effect. If the flow rate remains constant during the operation, and the pump pressure never increases or falls below the formation fracturing pressure, it indicates bridge plug failure and a poor fracturing effect. Based on the big data statistical analysis of the perforation erosion rate under different fracturing techniques (large-section multi-cluster, coiled tubing bottom-sealed drag, conventional bridge plug) in the reservoir, the effective number of open perforations in the injection well was determined. For example, based on downhole "eagle eye" monitoring and data statistics, the effective number of perforations for different fracturing techniques was determined. The specific effective perforation opening rate = actual monitored perforation opening rate / designed perforation opening rate. Generally, coiled tubing bottom-sealed drag is opened at 90%-100%, conventional bridge plug is opened at 60-70%, and large-section multi-cluster is opened at 30%-40%.

[0048] 2. Based on the downhole "eagle eye" monitoring results, determine the degree of erosion of the cluster holes in each section. Specifically, the holes can be divided into large holes (28-32mm), medium holes (24-28mm), and small holes (18-22mm). Then, based on the production profile monitoring results, determine the production contribution of each cluster.

[0049] 3. Based on steps 1 and 2, calculate the perforation erosion ratio of the injection well. Calculating the perforation erosion ratio is usually used to calculate the amount of temporary plugging agent needed for different sized fractures. First, relevant downhole data needs to be collected using downhole measuring instruments (Eagle Eye). This may include perforation size, depth, and number of perforations. The calculation formula is: monitored perforation diameter / total number of monitored perforations. Comprehensively identify the easily influent sections of the injection well (clusters of producing sections with larger production profiles) and the distribution of various types of perforations, analyze the main producing sections, predict the influent capacity and injection differences of each section, and design the pumping program according to "inject more fluid into sections with more production and less fluid into sections with less production" to achieve uniform fluid injection throughout the horizontal well section and repeated replenishment of formation energy.

[0050] 4. Design injection slugs rationally. The total concentration of the injection fluid in each slug should remain constant at 0.2%. The concentration of the injection fluid (surfactant) within each slug should be injected in stages, from high to low. Simultaneously, based on the perforation erosion ratio and fracturing process, optimize the particle size combination of the temporary plugging agent. Specific types of temporary plugging agents selected for the fracture opening include: 1-3mm, 3-5mm, 5-8mm, 13-15mm, 18-22mm, 22-24mm, 24-28mm, 28-32mm, and 28-35mm. The specific optimization principles are as follows:

[0051] ① Bottom seal dragging: fewer holes, larger hole diameter, higher opening rate, greater abrasion, and the ratio of temporary plugging at the joint is 24-28mm: 28-32mm = 7:3;

[0052] ② Large-section multi-cluster + temporary plug / conventional bridge plug + large-section multi-cluster: fewer holes, low opening rate, large abrasion, and the ratio of temporary plug at the slot is 18-22mm: 24-28mm: 28-32mm = 7:2:1;

[0053] ③ Conventional bridge plugs: have many holes, a high opening rate, less abrasion, and a temporary plugging ratio of 18-22mm:24-28mm:=7:3.

[0054] 5. By monitoring the fracture clusters in the horizontal well and determining the amount of fluid replenishment, the number of temporary plugging operations and the amount of fluid replenishment are designed. The key feature is that the number of main fluid inlet channels and their proportion to the total number of fracturing stages before temporary plugging are calculated based on microseismic monitoring and analysis. Specifically, based on the results of the production profile test, the number of main fluid inlet channels before temporary plugging is calculated as: (Number of main fluid inlet channels monitored by Eagle Eye / Total number of fracturing stages) * 100%. The dosage of temporary plugging agent is based on previous construction and monitoring results. Generally, the utilization rate of bottom-sealed drag section clusters is 100% (effective number of holes); the utilization rate of conventional bridge plug perforation combined operation in sections (2-3 clusters per section) is about 70% (effective number of holes); and the utilization rate of large-section multi-cluster temporary plugging is about 40% (effective number of holes). Based on this principle, the effective number of holes is calculated, and the total amount of temporary plugging agent is designed to be 1.0 to 1.3 times the effective number of holes. The single-time temporary plugging dosage is designed to be 0.25-0.35 times the effective number of holes. Simultaneously, considering the microseismic data from previous injection, after a single injection, temporary plugging is implemented for the effective number of holes in the injection section. The single injection section is 1 / 4 to 1 / 3 of the total number of stages. Based on the characteristics of various perforation processes and boreholes, the design principles are as follows:

[0055] ①Based on downhole "eagle eye" monitoring and data statistics, the erosion ratio of different types of holes in the injection well is calculated. Combined with the comprehensive analysis of the production profile, it is determined that a single well should be temporarily plugged 2-3 times, with each temporary plugging effectively covering 1 / 4 to 1 / 3 of the holes.

[0056] ② Bottom seal dragging and large-section multi-cluster designs have large variations in orifice diameter and few orifices, and are designed according to 1.3 times the effective number of orifices for single temporary plugging;

[0057] ③ Conventional bridge plugs have a large number of holes and relatively small changes in hole diameter, and are designed according to 1.0 times the effective number of holes for temporary plugging in a single operation.

[0058] Formula for temporary plugging of single well joint: N=a×n×m / M×b

[0059] In the formula: N represents the number of temporary plugs at the seam, a represents the cluster modification utilization rate, n represents the total number of holes, m represents the number of temporary plugs, M represents the number of slug plugs, and b represents the empirical coefficient, which is generally taken as 1.0 to 1.3.

[0060] Based on the above steps, the "one well, one policy" approach is used to formulate parameters such as the number of temporary plugging times, the optimized combination ratio of multiple particle sizes of temporary plugging agents, and the dosage for horizontal well injection.

[0061] Example 2

[0062] 1. Summary of Cluster Stimulation Utilization Rate: Based on "Eagle Eye" monitoring data and different fracturing construction techniques, cluster stimulation utilization rates can be divided into three categories: "bottom-sealed drag" fracturing horizontal wells have a 100% cluster stimulation rate (effective number of holes); "conventional bridge plug perforation combined with segmented (2-3 clusters per segment)" fracturing horizontal wells have a cluster stimulation utilization rate of approximately 70% (effective number of holes); and "large segment multi-cluster" fracturing horizontal wells have a cluster stimulation utilization rate of approximately 40% (effective number of holes).

[0063] 2. Summary of temporary plugging agent dosage rules: The total amount of temporary plugging agent should be designed according to 1.0-1.3 times the number of effective orifices, and the dosage of temporary plugging agent per application should be designed according to 0.25-0.35 times the number of effective orifices per application, thereby determining the number of applications.

[0064] 3. Based on production profile monitoring and "Eagle Eye" monitoring data, the following analysis summarizes the combination rules of the proportion of multi-size temporary plugging agent usage in horizontal wells using different fracturing techniques: For horizontal wells constructed using "bottom-sealed drag" fracturing, there are fewer holes, larger hole diameters, higher opening rates, and greater abrasion; the ratio of temporary plugging at the fracture opening is 24-28mm:28-32mm = 7:3. For horizontal wells constructed using "conventional bridge plugs + large-section multi-cluster" fracturing, there are fewer holes, lower opening rates, and greater abrasion; the ratio of temporary plugging at the fracture opening is 18-22mm:24-28mm:28-32mm = 7:2:1. For horizontal wells constructed using "conventional bridge plugs" fracturing, there are more holes, higher opening rates, and less abrasion; the ratio of temporary plugging at the fracture opening is 18-22mm:24-28mm: = 7:3.

[0065] This embodiment determines temporary plugging parameters through multi-particle size combinations, downhole production profile monitoring, "eagle eye" monitoring, and fracturing process analysis. When temporary plugging is implemented according to the established parameters during horizontal well injection, the oil production increase effect is significant.

[0066] like Figures 2-3 As shown, in a certain well area, after using the method of this invention for temporary plugging during fluid injection for wells that were shut down or had low production, 31 horizontal wells accumulated an additional 27,000 tons of oil. Taking a horizontal well numbered MaHW6005 as an example, the data shows that the profile utilization rate increased by 22% (from 43.5% to 65.5%), which effectively solved the problems of uneven fluid injection in different sections, low profile utilization rate, and inability to fully and effectively replenish formation energy caused by general fluid injection in horizontal wells.

[0067] The above description is merely a preferred embodiment of the present invention and is not intended to limit the invention. Various modifications and variations can be made to the present invention by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention are included within the scope of protection of the present invention.

Claims

1. A method for determining injection temporary plugging parameters based on the dynamic characteristics of horizontal well profiles, characterized in that, Includes the following steps: Step S1: Collect downhole data using downhole measuring instruments, determine the degree of erosion of each cluster of holes, calculate the proportion of erosion of injection well holes, determine the contribution of each cluster of production based on the characteristics of production profile monitoring, and delineate the main production cluster of holes. Step S2: Predict the injection capacity and injection differences of each cluster segment, and design the pump injection program according to the principle that the injection volume and output volume of each cluster segment are positively correlated and the injection volume is uniform throughout the horizontal well section; Step S3: Design injection slugs, injecting the fluid concentration in each slug sequentially from high to low, while keeping the total injection concentration constant at 0.2%; Step S4: Optimize the combination of temporary plugging agents with different particle sizes based on the porosity ratio and fracturing process; Step S5: Design the number of segments to be temporarily blocked in the liquid inlet channel, the number of times to temporarily block, the total amount of temporary blocking agent, and the dosage of temporary blocking agent per time.

2. The method for determining injection temporary plugging parameters based on horizontal well profile utilization as described in claim 1, characterized in that, Step S1 includes: Step S101: Obtain on-site geological and engineering data, evaluate the fracturing effect of different fracturing processes, and collect big data on pore erosion rate; Step S102: Analyze big data on the perforation erosion rate under different fracturing processes to determine the effective perforation opening rate of injection wells under different fracturing processes (to guide the subsequent combination ratio of temporary plugging agent particle size). Step S103: Collect downhole data using downhole measuring instruments, classify the perforations into Class I, Class II, and Class III perforations according to their diameter, and calculate the perforation erosion ratio of different types of perforations in the injection well (to guide the subsequent combination ratio of temporary plugging agent particle size). Step S104: Based on the characteristics of the liquid production profile monitoring, determine the contribution of each cluster to the liquid production and delineate the main liquid production clusters.

3. The method for determining injection temporary plugging parameters based on horizontal well profile utilization as described in claim 2, characterized in that, In step S102, the fracturing process includes large-section multi-cluster fracturing, continuous tubing bottom seal dragging, and conventional bridge plug.

4. The method for determining injection temporary plugging parameters based on horizontal well profile utilization as described in claim 2, characterized in that, In step S103, the formula for calculating the percentage of pore erosion is the number of each type of pore / the total number of pores monitored.

5. The method for determining injection temporary plugging parameters based on horizontal well profile utilization as described in claim 1, characterized in that, The principle for defining the main liquid output clusters is as follows: sorted according to the amount of liquid produced as shown in the liquid production profile, the clusters ranked first are the main liquid output clusters.

6. The method for determining injection temporary plugging parameters based on horizontal well profile utilization as described in claim 1, characterized in that, In step S4, the temporary plugging agent is classified into Type 1, Type 2, Type 3, Type 4, Type 5, Type 6, Type 7, Type 8, and Type 9 according to particle size, wherein: 1mm≤Particle size of Type 1 < 3mm, 3≤Particle size of Type 2 < 5mm, 5≤Particle size of Type 3 ≤ 8mm, 13≤Particle size of Type 4 ≤ 15mm, 18≤Particle size of Type 5 < 22mm, 22≤Particle size of Type 6 < 24mm, 24≤Particle size of Type 7 < 28mm, 28≤Particle size of Type 8 < 32mm, 32≤Particle size of Type 9 ≤ 35mm.

7. The method for determining injection temporary plugging parameters based on horizontal well profile utilization as described in claim 6, characterized in that, In step S4, the optimization principle for combinations of temporary plugging agents with different particle sizes is as follows: For horizontal wells using coiled tubing bottom-sealed fracturing technology, the ratio of temporary plugging agent at the fracture opening is: Type 7: Type 8 = 7:3; For horizontal wells using large-section multi-cluster or conventional bridge plug combined with large-section multi-cluster fracturing technology, the ratio of temporary plugging agent at the fracture opening is: Type 5: Type 7: Type 8 = 7:2:1; For horizontal wells using conventional bridge plug fracturing technology, the ratio of temporary plugging agent at the fracture opening is: Type 5: Type 7 = 7:

3.

8. The method for determining injection temporary plugging parameters based on horizontal well profile utilization as described in claim 1, characterized in that, In step S5, when designing the number of segments for temporary plugging of the fluid inlet channel, the number of single injection segments is controlled to be 1 / 4 to 1 / 3 of the total number of fracturing stages in a single well, based on the microseismic data from the fluid injection.

9. The method for determining injection temporary plugging parameters based on horizontal well profile utilization as described in claim 8, characterized in that, Each well is temporarily plugged 2-3 times, with each plugging session covering 1 / 4 to 1 / 3 of the total effective number of holes in the well.

10. The method for determining injection temporary plugging parameters based on horizontal well profile utilization as described in claim 8, characterized in that, The total amount of temporary plugging agent should be designed to be 1.0 to 1.3 times the number of effective orifices.

11. The method for determining injection temporary plugging parameters based on horizontal well profile utilization as described in claim 10, characterized in that, For horizontal wells using coiled tubing bottom sealing drag or large-section multi-cluster fracturing technology, the total amount of temporary plugging agent should be designed according to 1.3 times the number of effective perforations for a single temporary plugging. For horizontal wells using conventional bridge plug fracturing technology, the total amount of temporary plugging agent should be designed based on 1.0 times the number of effective perforations for a single temporary plugging operation.

12. The method for determining injection temporary plugging parameters based on horizontal well profile utilization as described in claim 8, characterized in that, The amount of temporary plugging agent used at the joint of a single well is determined according to the following formula: N = a × n × m / M × b In the formula: N represents the amount of temporary plugging agent used at the joint of a single well, which is the same as the number of joints temporarily plugged; a represents the cluster stimulation utilization rate; n represents the total number of holes; m represents the number of temporary plugging times; M represents the number of slug plugging times; and b represents an empirical coefficient, which ranges from 1.0 to 1.

3.

13. The method for determining injection temporary plugging parameters based on horizontal well profile utilization as described in claim 12, characterized in that, The single-time temporary plugging dose is designed to be 0.25-0.35 times the effective orifice.

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