Reservoir fracture damage evaluation method of fracturing fluid and temporary plugging agent and method for judging whether temporary plugging agent dissolution time is qualified

Abstract

The application discloses a reservoir fracture damage evaluation method of fracturing fluid and temporary plugging agent and a method for judging whether the temporary plugging agent dissolving time is qualified. The application adopts forward and reverse displacement experiments, considers the damage factors of the fracturing fluid and the temporary plugging agent on the reservoir fracture conductivity, quantifies the damage degree of the fracturing fluid and the temporary plugging agent on the fracture conductivity, combines a scanning electron microscope microscopic analysis method, reveals the main control factors of the fracturing fluid-temporary plugging agent composite damage, and has important significance for optimizing the performance of the fracturing fluid and the temporary plugging agent and then improving the shale gas reservoir production.

Description

Technical Field

[0001] This invention relates to the field of hydraulic fracturing technology in oil extraction, and more specifically to a method for evaluating reservoir fracture damage caused by fracturing fluid and temporary plugging agent, and a method for determining whether the dissolution time of the temporary plugging agent is qualified. Background Technology

[0002] Volumetric fracturing technology has become a core means of effectively developing unconventional oil and gas reservoirs, occupying an extremely important position in today's oil and gas extraction field. Due to their special geological structure and reservoir characteristics, traditional extraction methods are difficult to achieve ideal development results for unconventional oil and gas reservoirs. However, volumetric fracturing technology, by creating a complex network of fractures in the reservoir, greatly increases the seepage channels for oil and gas, thereby effectively improving the extraction efficiency of oil and gas.

[0003] In the entire process of volumetric fracturing, temporary plugging agents play an indispensable role. Their main purpose is to precisely seal high-permeability layers, thereby cleverly altering the flow path of fluids in the formation, opening new fractures, and significantly increasing the volume of fracturing stimulation. This allows oil and gas to flow more smoothly from the reservoir to the wellbore, ultimately achieving efficient extraction.

[0004] Specifically, temporary plugging agents play a crucial role in sealing fractures during fracturing. When injected into formation fractures, they form an effective sealing barrier at specific locations, forcing a change in the flow direction of the fracturing fluid. This causes the fractures to deflect, further expanding the fracturing area and creating more favorable conditions for oil and gas extraction.

[0005] However, after the successful completion of fracturing operations, some potential problems caused by temporary plugging agents gradually emerged. As a polymer material, the dissolution characteristics of temporary plugging agents have a profound impact on subsequent oil and gas extraction. If the dissolution time is too long, far exceeding the reasonable expected range, it will continuously occupy the fracture space for a considerable period of time, hindering the normal flow of oil and gas. Moreover, if the dissolution rate is unqualified, that is, if it fails to dissolve completely according to the ideal ratio, the remaining temporary plugging agent residue will remain in the fracture, which will undoubtedly cause serious damage to the conductivity of the fracture. The consequences of this damage are multifaceted. It will not only directly affect the production efficiency of unconventional oil and gas reservoirs, greatly reducing the expected production increase achieved through volumetric fracturing technology, but may even cause more serious problems, such as formation and wellbore blockage. Once this occurs, it will greatly increase the difficulty and cost of subsequent extraction operations, seriously interfering with the normal progress of oil and gas extraction.

[0006] Existing evaluation standards for temporary plugging agents, such as Q / 91510681214285398E·15-2023 "Temporary Plugging Particle Polyester SD1-21 for Fracturing," while regulating and evaluating certain properties of temporary plugging agents to some extent, fall short when addressing the critical issue of damage caused by temporary plugging agents to reservoir fractures during volumetric fracturing. This standard fails to comprehensively and thoroughly reveal crucial information such as how temporary plugging agents damage reservoir fractures and the specific extent of that damage during actual volumetric fracturing operations.

[0007] A review of previous research on temporary plugging agents reveals that past studies primarily focused on optimizing their sealing performance using core displacement and true triaxial hydraulic fracturing devices. While these methods have indeed improved the sealing effect of temporary plugging agents to some extent, enabling them to play a better role in the fracturing process, they have significant limitations. They haven't fully considered the solubility and potential damage caused by temporary plugging agents under two common and crucial real-world formation conditions: high closure stress and high reservoir temperature. In real oil and gas reservoir environments, high closure stress and high reservoir temperature are prevalent phenomena that significantly impact the performance of temporary plugging agents. For example, they can accelerate or delay the dissolution process, altering the degree of dissolution and consequently affecting the conductivity of fractures and the overall effectiveness of oil and gas extraction.

[0008] Furthermore, existing industry standards for fracturing injection materials are typically developed around the performance evaluation of a single material. However, in real-world formation environments, the situation is far more complex. Fracturing injection materials do not function in isolation; for example, multiple materials such as fracturing fluid, proppant, and temporary plugging agents are pumped into the formation together, and their properties interact and constrain each other. Taking fracturing fluid and temporary plugging agents containing polymers as an example, when they coexist in the formation, the polymers in the fracturing fluid may undergo a chemical reaction with the temporary plugging agent or interfere with each other physically, thus jointly damaging the reservoir. This interaction has not been adequately considered or accurately assessed in existing industry standards.

[0009] In light of the aforementioned circumstances, there is an urgent need for a comprehensive and in-depth improvement to the performance evaluation methods for fracturing fluids and temporary plugging agents. Specifically, this requires establishing a dedicated method for evaluating reservoir fracture damage caused by fracturing fluids and temporary plugging agents. This novel evaluation method can systematically and accurately reveal the main controlling factors of fracturing fluid-temporary plugging agent damage to reservoir fractures, clearly defining under what conditions and which factors cause the most severe damage. This will not only fill the gap in enterprise standards regarding the performance evaluation of temporary plugging agents on reservoir damage, providing enterprises with a more scientific and accurate basis for the production and use of temporary plugging agents, but also provide a highly valuable research direction for the joint optimization of fracturing fluids and temporary plugging agents. This will help promote the further development of fracturing technology and related material applications in the entire oil and gas extraction industry, achieving more efficient, safe, and sustainable oil and gas extraction goals. Summary of the Invention

[0010] To overcome the defects and deficiencies in the existing technology, this invention provides a method for evaluating reservoir fracture damage caused by fracturing fluid and temporary plugging agent, and a method for determining whether the dissolution time of the temporary plugging agent is qualified. The purpose of this invention is to provide a method for evaluating reservoir fracture damage caused by fracturing fluid and temporary plugging agent, and a method for determining whether the dissolution time of the temporary plugging agent is qualified, revealing the main controlling factors of fracturing fluid-temporary plugging agent damage to reservoir fractures, and filling the gap in current enterprise standards regarding the performance evaluation of temporary plugging agent damage to reservoirs. This invention considers the damaging factors of fracturing fluid and temporary plugging agent on the conductivity of reservoir fractures, quantifies the degree of damage to fracture conductivity caused by fracturing fluid and temporary plugging agent, and, combined with scanning electron microscopy microscopic analysis, reveals the main controlling factors of combined damage caused by fracturing fluid and temporary plugging agent, which is of great significance for optimizing the performance of fracturing fluid and temporary plugging agent and thus improving shale gas reservoir production.

[0011] To address the problems existing in the prior art, the present invention is achieved through the following technical solution.

[0012] The first aspect of this invention provides a method for evaluating reservoir fracture damage caused by fracturing fluid and temporary plugging agent, the method comprising the following steps:

[0013] S101. Take the set amount of proppant and temporary plugging agent, and dry them at low temperature;

[0014] S102. Prepare one part of water-based fracturing fluid with complete gel breaking, one part of water-based fracturing fluid with partial gel breaking, and one part of standard saline solution respectively.

[0015] S103. The proppant is laid in diversion chambers A and B; the proppant and temporary plugging agent are mixed and then laid in diversion chamber C; diversion chambers A, B, and C are heated to the reservoir temperature; diversion chambers A, B, and C are all held in place by rock plates.

[0016] S104. Using a set flow rate, the standard saline solution prepared in step S102 is forward-displaced in flow chambers A, B, and C, and the flow carrying capacity F is measured respectively. A1 F B1 and F C1 ;

[0017] S105. In the flow chamber A, which has completed the forward displacement of standard brine in step S104, completely displace the water-based fracturing fluid prepared in step S102 by reverse displacement; in the flow chambers B and C, which have completed the forward displacement of standard brine in step S104, partially displace the water-based fracturing fluid prepared in step S102 by reverse displacement for a set time, and maintain the temperature and pressure for a period of time.

[0018] S106. Displace the standard saline solution again in the forward direction through flow chambers A, B, and C at the same flow rate as in step S104. Measure the stable flow capacity as F. A2 F B2 and F C2 And record the time t1 when the flow guiding capacity in the flow guiding chamber C stabilizes;

[0019] S107. Take out the proppant-temporary plugging agent mixture from the flow chamber C, record the dissolution of the temporary plugging agent, and observe the aggregation state and surface properties of the mixture using an optical microscope and a scanning electron microscope.

[0020] S108. The flow-conducting capacity F measured according to step S104. A1 F B1 and F C1 And the conductivity measured in step S106 is F A2 F B2 and F C2 The effects of fracturing fluid on reservoir fracture conductivity, incomplete fracturing fluid breakdown on reservoir fracture conductivity, fracturing fluid-temporary plugging agent on reservoir fracture conductivity, and temporary plugging agent on reservoir fracture conductivity were evaluated.

[0021] In a further preferred embodiment, in step S108, evaluating the damage of fracturing fluid to the reservoir fracture conductivity refers to calculating the damage rate η1 of the fracturing fluid to the reservoir fracture conductivity. The damage rate η1 of fracturing fluid to the conductivity of reservoir fractures was evaluated.

[0022] In a further preferred embodiment, in step S108, evaluating the damage to the reservoir fracture conductivity caused by incomplete fracturing fluid rupture refers to calculating the damage rate η2 caused by incomplete fracturing fluid rupture to the reservoir fracture conductivity. The damage rate η2 to the reservoir fracture conductivity was evaluated by the incomplete gel breaking of the fracturing fluid.

[0023] In a further preferred embodiment, in step S108, evaluating the damage of fracturing fluid-temporary plugging agent to the reservoir fracture conductivity refers to calculating the damage rate η3 of the fracturing fluid-temporary plugging agent to the reservoir fracture conductivity. The damage rate η3 to the reservoir fracture conductivity was evaluated using fracturing fluid-temporary plugging agent.

[0024] More preferably, in step S108, evaluating the damage of the temporary plugging agent to the reservoir fracture conductivity refers to calculating the damage rate η4 of the temporary plugging agent to the reservoir fracture conductivity, and evaluating the damage rate η4 of the temporary plugging agent to the reservoir fracture conductivity; the damage rate η4 of the temporary plugging agent to the reservoir fracture conductivity is the difference between the damage rate η3 of the fracturing fluid-temporary plugging agent to the reservoir fracture conductivity and the damage rate η1 of the fracturing fluid to the reservoir fracture conductivity, i.e.

[0025] More preferably, the water-based fracturing fully broken gel fluid in step S102 is obtained by placing the water-based fracturing fluid at the reservoir temperature to break the gel. When the viscosity of the water-based fracturing fluid is below 5 mPa·s, the water-based fracturing fluid is taken out to form the water-based fracturing fully broken gel fluid.

[0026] More preferably, the water-based fracturing partial gel breaking fluid in step S102 is obtained by placing the water-based fracturing fluid at the reservoir temperature to break the gel. When the viscosity of the water-based fracturing fluid is between 7 mPa·s and 15 mPa·s, the water-based fracturing fluid is taken out to form the water-based fracturing partial gel breaking fluid.

[0027] More preferably, in step S102, the type of water-based fracturing fluid includes any one of low-viscosity slickwater, medium-high viscosity slickwater, cross-linked fracturing fluid, and supramolecular hydrophobic associative fracturing fluid.

[0028] More preferably, the low-viscosity slippery water is prepared with the following proportions: 0.05% to 0.1% drag reducer; 0.05% to 0.1% bactericide; and the remainder being water for preparing the solution.

[0029] More preferably, the medium-high viscosity slippery water is formulated with the following proportions: 0.2% to 0.5% drag reducer; 0.05% to 0.1% bactericide; 0.1% degumming agent; and the remainder is water for mixing.

[0030] More preferably, the crosslinked fracturing fluid is formulated with the following proportions: 0.5%–0.7% drag reducer; 0.5%–0.6% crosslinking agent; 0.2% bactericide; 0.2% breaker; and the remainder is water for mixing.

[0031] More preferably, the formulation of the supramolecular hydrophobic associative fracturing fluid is as follows: 0.15%–0.25% supramolecular thickener; 0.2% bactericide; 0.005%–0.02% breaker; and the remainder is water for fluid preparation.

[0032] More preferably, the temporary plugging agent is a temporary plugging particle or a temporary plugging powder.

[0033] The second aspect of this invention provides a method for determining whether the dissolution time of a temporary plugging agent is qualified. Specifically, the method involves placing the temporary plugging agent in a beaker containing standard saline solution and allowing it to stand at the reservoir temperature. The dissolution time t2 of the temporary plugging agent in the beaker is then measured. The measured dissolution time t2 is compared with the time t1 for stable conductivity measured using the reservoir fracture damage evaluation method for fracturing fluid and temporary plugging agent in the first aspect of this invention. If the difference between t1 and t2 is more than 24 hours, the dissolution time of the temporary plugging agent is deemed unqualified.

[0034] Compared with the prior art, the beneficial technical effects of the present invention are as follows:

[0035] 1. This invention comprehensively considers the damaging factors of fracturing fluid and temporary plugging agent on the conductivity of reservoir fractures, including liquid phase damage, solid phase damage, damage from incomplete gel breaking of fracturing fluid, sealing damage from temporary plugging agent, and damage from incomplete dissolution of temporary plugging agent. It can quantify the degree of damage to fracture conductivity caused by fracturing fluid and temporary plugging agent. Combined with scanning electron microscopy microscopic analysis, it reveals the main controlling factors of the combined damage of fracturing fluid and temporary plugging agent, providing ideas for the optimization of fracturing fluid and temporary plugging agent.

[0036] 2. This invention considers the damage to the reservoir's fracture conductivity caused by incomplete fracturing fluid breakdown. By injecting fracturing fluid with a viscosity of 7-15 mPa·s to break the gel, the injectability of the fluid is satisfied, and the fracturing fluid breakdown process is effectively simulated, thus realistically reflecting the damage to the reservoir caused by the fracturing fluid's gel-breaking properties.

[0037] 3. This invention quantifies the damage to fracture conductivity caused by temporary plugging agents by comparing the damage rate under proppant, proppant and temporary plugging agent mixed placement conditions, filling the gap in enterprise standards regarding the evaluation of reservoir damage performance of temporary plugging agents.

[0038] 4. This invention compares the dissolution time of the temporary plugging agent under beaker static conditions and flow chamber dynamic flow conditions, and realistically simulates the dissolution performance of the temporary plugging agent in the backflow and production process under high closure stress and high reservoir temperature conditions, thus improving the enterprise standard. Attached Figure Description

[0039] Figure 1 This invention relates to a method for evaluating the combined reservoir damage caused by fracturing fluid and temporary plugging agent.

[0040] Figure 2 This is the mixture of the proppant and the temporary plugging agent described in this invention;

[0041] Figure 3This is the fracturing fluid breaker described in this invention. Detailed Implementation

[0042] The technical solutions in 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, and 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.

[0043] Example 1

[0044] As a preferred embodiment of the present invention, please refer to the appendix to the specification. Figure 1 As shown in the figure, this embodiment discloses a method for evaluating reservoir fracture damage caused by fracturing fluid and temporary plugging agent. The evaluation method includes the following steps:

[0045] S101. Take the predetermined amounts of proppant and temporary plugging agent and dry them at a low temperature. As an example in this embodiment, drying is carried out at 60°C. The low-temperature drying method used here is to remove any moisture that may be present in the sample while ensuring that the physicochemical properties of the proppant and temporary plugging agent are not affected to the greatest extent. By precisely controlling the drying temperature and time, the sample reaches an ideal dry state, laying a good foundation for subsequent experimental operations.

[0046] S102. Prepare one part of water-based fracturing fluid with complete gel breaking, one part of water-based fracturing fluid with partial gel breaking, and one part of standard saline solution respectively.

[0047] S103. Place the proppant in flow chamber A and flow chamber B; mix the proppant and temporary plugging agent and place them in flow chamber C; heat flow chamber A, flow chamber B and flow chamber C to the reservoir temperature;

[0048] S104. Using a set flow rate, the standard saline solution prepared in step S102 is forward-displaced in flow chambers A, B, and C, and the flow carrying capacity F is measured respectively. A1 F B1 and F C1 ;

[0049] S105. In the flow chamber A, which has completed the forward displacement of standard brine in step S104, completely displace the water-based fracturing fluid prepared in step S102 by reverse displacement; in the flow chambers B and C, which have completed the forward displacement of standard brine in step S104, partially displace the water-based fracturing fluid prepared in step S102 by reverse displacement for a set time, and maintain the temperature and pressure for a period of time.

[0050] S106. Displace the standard saline solution again in the forward direction through flow chambers A, B, and C at the same flow rate as in step S104. Measure the stable flow capacity as F. A2 F B2 and F C2 And record the time t1 when the flow guiding capacity in the flow guiding chamber C stabilizes;

[0051] S107. Take out the proppant-temporary plugging agent mixture from the flow chamber C, record the dissolution of the temporary plugging agent, and observe the aggregation state and surface properties of the mixture using an optical microscope and a scanning electron microscope.

[0052] S108. The flow-conducting capacity F measured according to step S104. A1 F B1 and F C1 And the conductivity measured in step S106 is F A2 F B2 and F C2 The effects of fracturing fluid on reservoir fracture conductivity, incomplete fracturing fluid breakdown on reservoir fracture conductivity, fracturing fluid-temporary plugging agent on reservoir fracture conductivity, and temporary plugging agent on reservoir fracture conductivity were evaluated.

[0053] Example 2

[0054] As another preferred embodiment of the present invention, this embodiment further supplements and elaborates on the technical solution of the present invention based on the above-described embodiment 1. In this embodiment, in step S108, evaluating the damage of fracturing fluid to the conductivity of reservoir fractures refers to calculating the damage rate η1 of the fracturing fluid to the conductivity of reservoir fractures. The damage rate η1 of fracturing fluid to the conductivity of reservoir fractures was evaluated.

[0055] Evaluating the damage to reservoir fracture conductivity caused by incomplete fracturing fluid rupture refers to calculating the damage rate η2 caused by incomplete fracturing fluid rupture to reservoir fracture conductivity. The damage rate η2 to the reservoir fracture conductivity was evaluated by the incomplete gel breaking of the fracturing fluid.

[0056] Evaluating the damage of fracturing fluid-temporary plugging agent to reservoir fracture conductivity refers to calculating the damage rate η3 of fracturing fluid-temporary plugging agent to reservoir fracture conductivity. The damage rate η3 to the reservoir fracture conductivity was evaluated using fracturing fluid-temporary plugging agent.

[0057] Evaluation of the damage of temporary plugging agents to reservoir fracture conductivity refers to calculating the damage rate η4 of the temporary plugging agent on reservoir fracture conductivity, and evaluating the effect based on the damage rate η4. The damage rate η4 is the difference between the damage rate η3 of fracturing fluid-temporary plugging agent on reservoir fracture conductivity and the damage rate η1 of fracturing fluid on reservoir fracture conductivity.

[0058] Example 3

[0059] As another preferred embodiment of the present invention, this embodiment is a further detailed supplement and explanation of the technical solution of the present invention based on the above-described Embodiment 1 or Embodiment 2. In this embodiment, reference is made to the appendix to the specification. Figure 3 As shown, the water-based fracturing fully broken gel fluid in step S102 is obtained by placing the water-based fracturing fluid at the reservoir temperature to break the gel. When the viscosity of the water-based fracturing fluid is below 5 mPa·s, the water-based fracturing fluid is taken out to form the water-based fracturing fully broken gel fluid.

[0060] The water-based fracturing partial gel breaking fluid in step S102 is obtained by placing the water-based fracturing fluid at the reservoir temperature to break the gel. When the viscosity of the water-based fracturing fluid is between 7 mPa·s and 15 mPa·s, the water-based fracturing fluid is removed to form the water-based fracturing partial gel breaking fluid.

[0061] As another embodiment of this example, in step S102, the type of water-based fracturing fluid includes any one of low-viscosity slickwater, medium-high viscosity slickwater, cross-linked fracturing fluid, and supramolecular hydrophobic associative fracturing fluid.

[0062] As an example, the low-viscosity slippery water is prepared with the following proportions: 0.05% to 0.1% drag reducer; 0.05% to 0.1% bactericide; and the remainder is water for dispensing.

[0063] As another example, the medium-high viscosity slippery water is formulated with the following proportions: 0.2% to 0.5% drag reducer; 0.05% to 0.1% bactericide; 0.1% degumming agent; and the remainder is water for mixing.

[0064] As another example, the crosslinked fracturing fluid is formulated with the following proportions: 0.5%–0.7% drag reducer; 0.5%–0.6% crosslinking agent; 0.2% bactericide; 0.2% breaker; and the remainder is water for mixing.

[0065] As another example, the formulation of supramolecular hydrophobic associative fracturing fluid is as follows: 0.15%–0.25% supramolecular thickener; 0.2% bactericide; 0.005%–0.02% breaker; and the remainder is water for mixing.

[0066] In the four examples above, the proportions of each component only need to meet the specified range. The specific proportions can be set according to the actual fracturing fluid required by the target reservoir.

[0067] Example 4

[0068] This embodiment mainly illustrates the damaging factors of fracturing fluid and temporary plugging agent on the conductivity of reservoir fractures through experiments. The experimental steps are as follows:

[0069] S101. Take three 27g portions of 40 / 70 mesh proppant and one 8g portion of temporary plugging agent, and dry them at a low temperature of 60℃.

[0070] S102. Prepare one part of fully ruptured water-based fracturing fluid with a viscosity of 2 mPa·s and one part of partially ruptured water-based fracturing fluid with a viscosity of 13 mPa·s. Use one part of standard brine with no viscosity. The water-based fracturing fluid is mainly slickwater, specifically medium-high viscosity slickwater with a viscosity greater than 10 mPa·s. Its formula is 0.3% drag reducer + 0.2% bactericide + 0.1% rupture agent + water.

[0071] S103. Place one 27g proppant into flow chamber A and flow chamber B respectively, and mix one 27g proppant and 8g temporary plugging agent into flow chamber C; heat flow chamber A, flow chamber B and flow chamber C to reservoir temperature of 90℃, and clamp them with rock plates.

[0072] S104. At a flow rate of 3 mL / min, standard saline is forward-displaced in flow chambers A, B, and C to obtain the flow carrying capacity F of flow chamber A. A1 71.36μm 2 ·cm, to obtain the flow guiding capacity F of the flow guiding chamber B. B1 It is 67.23μm 2 ·cm, the flow guiding capacity of the flow guiding chamber C is F C1 16.31μm 2 ·cm;

[0073] S105, guide chamber A reverse displacement of water-based fracturing fluid completely breaks the gel; guide chambers B and C reverse displacement of water-based fracturing fluid partially breaks the gel, displacement time is 3 hours, and heat and pressure are maintained for 2 hours;

[0074] S106. Following step S104, the standard saline solution is again forward-displaced in flow chambers A, B, and C at the same flow rate. The stable flow carrying capacity is then measured as F. A2 68.35μm 2 ·cm、F B2 23.16μm 2 ·cm、F C2 It is 5.11μm 2•cm; and record the time t1 for the flow diversion capacity in the diversion chamber C to stabilize as 13h;

[0075] S7: Remove the proppant-propellant mixture from the flow chamber C, record the dissolution of the propellant, and observe the aggregation state and surface properties of the mixture using an optical microscope and a scanning electron microscope.

[0076] S8. The calculated damage rate η1 of fracturing fluid to reservoir fracture conductivity is 65.55%; the calculated damage rate η2 of incomplete fracturing fluid breakdown to reservoir fracture conductivity is 4.22%; the calculated damage rate η3 of fracturing fluid-temporary plugging agent to reservoir fracture conductivity is 68.67%; and the calculated damage rate η4 of temporary plugging agent to reservoir fracture conductivity is 3.12%.

[0077] Example 5

[0078] This embodiment mainly illustrates the damaging effect of incomplete fracturing fluid breakdown on reservoir fractures through experiments. The experimental steps are as follows:

[0079] S101: Take three 21g portions of 70 / 140 mesh proppant and one 5g portion of temporary plugging agent, and dry them at a low temperature of 60℃;

[0080] S102. Prepare one part of fully ruptured water-based fracturing fluid with a viscosity of 3 mPa·s and one part of partially ruptured water-based fracturing fluid with a viscosity of 11 mPa·s. Use one part of standard brine with no viscosity. The water-based fracturing fluid is mainly slickwater, specifically medium-high viscosity slickwater with a viscosity greater than 10 mPa·s. Its formula is 0.3% drag reducer + 0.2% bactericide + 0.1% rupture agent + water.

[0081] S103. Two 21g portions of proppant are respectively placed in flow chamber A and flow chamber B, and one 21g portion of proppant and 5g of temporary plugging agent are mixed and placed in flow chamber C; flow chamber A, flow chamber B, and flow chamber C are heated to the reservoir temperature of 90°C, and flow chamber A, flow chamber B, and flow chamber C are held together by rock plates.

[0082] S104. At a flow rate of 2.5 mL / min, standard saline is forward-displaced in flow chambers A, B, and C to obtain the flow carrying capacity F of flow chamber A. A1 It is 67.45μm 2 ·cm, to obtain the flow guiding capacity F of the flow guiding chamber B. B1 68.22μm 2 ·cm, the flow guiding capacity of the flow guiding chamber C is F C1 21.37μm 2 ·cm;

[0083] S105: The water-based fracturing fluid is completely displaced in the reverse direction in the flow chamber A; the water-based fracturing fluid is partially displaced in the reverse direction in the flow chambers B and C, with a displacement time of 3 hours and heat and pressure maintenance for 2 hours.

[0084] S106. Following step S104, the standard saline solution is again forward-displaced in flow chambers A, B, and C at the same flow rate. The stable flow carrying capacity is then measured as F. A2 60.29μm 2 ·cm、F B2 12.06μm 2 ·cm、F C2 3.89μm 2 •cm; and record the time t1 for the flow diversion capacity in the diversion chamber C to stabilize as 8h;

[0085] S107: Remove the proppant-propellant mixture from the flow chamber C, record the dissolution of the propellant, and observe the aggregation state and surface properties of the mixture using an optical microscope and a scanning electron microscope;

[0086] S108. The overall damage rate η1 of fracturing fluid to the reservoir fracture conductivity is calculated to be 82.32%; the damage η2 of incomplete fracturing fluid breakdown to the reservoir fracture conductivity is calculated to be 71.70%.

[0087] Example 6

[0088] This embodiment mainly illustrates the damaging effects of proppant, proppant, and temporary plugging agent mixed placement on reservoir fractures through experiments. The experimental steps are as follows:

[0089] S101: Take three 57g portions of 70 / 140 mesh proppant and one 10g portion of temporary plugging agent, and dry them at a low temperature of 60℃;

[0090] S102. Prepare one part of fully ruptured water-based fracturing fluid with a viscosity of 2 mPa·s and one part of partially ruptured water-based fracturing fluid with a viscosity of 13 mPa·s. Use one part of standard brine with no viscosity. The water-based fracturing fluid is a supramolecular hydrophobic associative fracturing fluid with a ratio of 0.2% supramolecular hydrophobic associative thickener + 0.2% bactericide + 0.05% rupture agent + water.

[0091] S103: Two 57g portions of proppant are placed in flow chamber A and flow chamber B, and one 57g portion of proppant and 10g of temporary plugging agent are mixed and spread in flow chamber C; flow chamber A, flow chamber B, and flow chamber C are heated to the reservoir temperature of 90°C, and flow chamber A, flow chamber B, and flow chamber C are held in place by rock plates;

[0092] S104. At a flow rate of 3 mL / min, standard saline is forward-displaced in flow chambers A, B, and C to obtain the flow carrying capacity F of flow chamber A.A1 52.78μm 2 ·cm, to obtain the flow guiding capacity F of the flow guiding chamber B. B1 51.63μm 2 ·cm, the flow guiding capacity of the flow guiding chamber C is F C1 20.13μm 2 ·cm;

[0093] S105, in the reverse displacement chamber A, the water-based fracturing fluid is completely disintegrated; in the reverse displacement chambers B and C, the water-based fracturing fluid is partially disintegrated, with a displacement time of 3 hours and heat and pressure maintained for 2 hours.

[0094] S106. According to S104, the standard saline solution was again forward-displaced in flow chambers A, B, and C at the same flow rate, and the stable flow carrying capacity was measured as F. A2 46.13μm 2 ·cm、F B2 40.68μm 2 ·cm、F C2 3.11μm 2 •cm; and record the time t1 for the flow diversion capacity in the diversion chamber C to stabilize as 17h;

[0095] S107: Remove the proppant-propellant mixture from the flow chamber C, record the dissolution of the propellant, and observe the aggregation state and surface properties of the mixture using an optical microscope and a scanning electron microscope;

[0096] S108. The calculated comprehensive damage rate η1 of fracturing fluid to reservoir fracture conductivity is 21.21%; the calculated damage η2 of incomplete fracturing fluid breakdown to reservoir fracture conductivity is 8.61%; the calculated comprehensive damage rate η3 of fracturing fluid-temporary plugging agent to reservoir fracture is 84.55%; and the calculated damage rate η4 of plugging agent to reservoir fracture conductivity is 63.34%.

[0097] Example 7

[0098] This embodiment mainly illustrates the method for determining whether the actual dissolution time of the temporary plugging agent is acceptable through experiments. The experimental steps are as follows:

[0099] S101: Take one part 21g of 70 / 140 mesh proppant and one part 5g of temporary plugging agent, and dry them at 60℃;

[0100] S102: Prepare a fracturing fluid with a viscosity of less than 5 mPa·s to completely break up the gel.

[0101] S103: The proppant and temporary plugging agent are mixed and laid in the diversion chamber, and heated to the reservoir temperature of 90°C. The diversion chamber is held by rock plates.

[0102] S104: The reverse displacement of water-based fracturing fluid in the guide chamber completely breaks the gel, with a displacement time of 3 hours and heat and pressure maintenance for 2 hours;

[0103] S105: With a flow rate of 4 mL / min for positive displacement of saline, the conductivity after stabilization was measured to be 16.25 μm. 2 The flow rate was measured in cm, and the stabilization time of the flow diversion capacity of the diversion chamber was recorded as 8 hours.

[0104] S106: Place the temporary plugging agent in a beaker containing standard saline solution, let it stand at the reservoir temperature, and determine the dissolution time of the temporary plugging agent in the beaker as t2, which is 4 hours.

[0105] The same temporary plugging agent and proppant were used in all of the above Examples 4-7. The temporary plugging agent used 1-3mm particles, and the proppant used 70 / 140 mesh fracturing quartz sand.

[0106] Example 8

[0107] As another preferred embodiment of the present invention, this embodiment further supplements and elaborates on the technical solution of the present invention based on the above embodiments 1-7. This embodiment provides a method for determining whether the dissolution time of the temporary plugging agent is qualified. The method specifically involves placing the temporary plugging agent in a beaker containing standard saline solution, allowing it to stand at the reservoir temperature, and measuring the dissolution time t2 of the temporary plugging agent in the beaker; comparing the measured dissolution time t2 with the time t1 for stable conductivity measured using the reservoir fracture damage evaluation method for fracturing fluid and temporary plugging agent described in embodiments 1, 2, 3, 4, 5, 6, or 7; if the difference between t1 and t2 is more than 24 hours, the dissolution time of the temporary plugging agent can be determined to be unqualified.

[0108] The above embodiments are only for illustrating the technical concept and features of the present invention, and are intended to enable those skilled in the art to understand the content of the present invention and implement it accordingly. They should not be construed as limiting the scope of protection of the present invention. All equivalent changes or modifications made in accordance with the spirit and essence of the present invention should be covered within the scope of protection of the present invention.

Claims

1. A method for evaluating reservoir fracture damage caused by fracturing fluid and temporary plugging agent, characterized in that, The evaluation method includes the following steps: S101. Take the set amount of proppant and temporary plugging agent, and dry them at low temperature; S102. Prepare one part of water-based fracturing fluid with complete gel breaking, one part of water-based fracturing fluid with partial gel breaking, and one part of standard saline solution respectively. S103. The proppant is laid in diversion chambers A and B; the proppant and temporary plugging agent are mixed and then laid in diversion chamber C; diversion chambers A, B, and C are heated to the reservoir temperature; diversion chambers A, B, and C are all held in place by rock plates. S104. Using a set flow rate, the standard saline solution prepared in step S102 is forward-displaced in flow chambers A, B, and C, and the flow carrying capacity F is measured respectively. A1 F B1 and F C1 ; S105. In the flow chamber A, which has completed the forward displacement of standard brine in step S104, completely displace the water-based fracturing fluid prepared in step S102 by reverse displacement; in the flow chambers B and C, which have completed the forward displacement of standard brine in step S104, partially displace the water-based fracturing fluid prepared in step S102 by reverse displacement for a set time, and maintain the temperature and pressure for a period of time. S106. Displace the standard saline solution again in the forward direction through flow chambers A, B, and C at the same flow rate as in step S104. Measure the stable flow capacity as F. A2 F B2 and F C2 And record the time t1 when the flow guiding capacity in the flow guiding chamber C stabilizes; S107. Take out the proppant-temporary plugging agent mixture from the flow chamber C, record the dissolution of the temporary plugging agent, and observe the aggregation state and surface properties of the mixture using an optical microscope and a scanning electron microscope. S108. The flow-conducting capacity F measured according to step S104. A1 F B1 and F C1 And the conductivity measured in step S106 is F A2 F B2 and F C2 The effects of fracturing fluid on reservoir fracture conductivity, incomplete fracturing fluid breakdown on reservoir fracture conductivity, fracturing fluid-temporary plugging agent on reservoir fracture conductivity, and temporary plugging agent on reservoir fracture conductivity were evaluated.

2. The method for evaluating reservoir fracture damage using fracturing fluid and temporary plugging agent as described in claim 1, characterized in that: In step S108, evaluating the damage of fracturing fluid to the reservoir fracture conductivity refers to calculating the damage rate η1 of the fracturing fluid to the reservoir fracture conductivity. The damage rate η1 of fracturing fluid to the conductivity of reservoir fractures was evaluated.

3. The method for evaluating reservoir fracture damage using fracturing fluid and temporary plugging agent as described in claim 1, characterized in that: In step S108, evaluating the damage to reservoir fracture conductivity caused by incomplete fracturing fluid rupture refers to calculating the damage rate η2 caused by incomplete fracturing fluid rupture to reservoir fracture conductivity. The damage rate η2 to the reservoir fracture conductivity was evaluated by the incomplete gel breaking of the fracturing fluid.

4. The method for evaluating reservoir fracture damage using fracturing fluid and temporary plugging agent as described in claim 1, characterized in that: In step S108, evaluating the damage of fracturing fluid-temporary plugging agent to reservoir fracture conductivity refers to calculating the damage rate η3 of fracturing fluid-temporary plugging agent to reservoir fracture conductivity. The damage rate η3 to the reservoir fracture conductivity was evaluated using fracturing fluid-temporary plugging agent.

5. The method for evaluating reservoir fracture damage using fracturing fluid and temporary plugging agent as described in claim 1, characterized in that: In step S108, evaluating the damage of the temporary plugging agent to the reservoir fracture conductivity refers to calculating the damage rate η4 of the temporary plugging agent to the reservoir fracture conductivity, and evaluating the damage rate η4. The damage rate η4 of the temporary plugging agent to the reservoir fracture conductivity is the difference between the damage rate η3 of the fracturing fluid-temporary plugging agent combination and the damage rate η1 of the fracturing fluid to the reservoir fracture conductivity.

6. The method for evaluating reservoir fracture damage using fracturing fluid and temporary plugging agent as described in any one of claims 1-5, characterized in that: The water-based fracturing fully broken fluid in step S102 is obtained by placing the water-based fracturing fluid at the reservoir temperature to break it up. When the viscosity of the water-based fracturing fluid is below 5 mPa·s, the water-based fracturing fluid is removed to form the water-based fracturing fully broken fluid.

7. The method for evaluating reservoir fracture damage using fracturing fluid and temporary plugging agent as described in any one of claims 1-5, characterized in that: The water-based fracturing partial gel breaking fluid in step S102 is obtained by placing the water-based fracturing fluid at the reservoir temperature to break the gel. When the viscosity of the water-based fracturing fluid is between 7 mPa·s and 15 mPa·s, the water-based fracturing fluid is removed to form the water-based fracturing partial gel breaking fluid.

8. The method for evaluating reservoir fracture damage using fracturing fluid and temporary plugging agent as described in any one of claims 1-5, characterized in that: In step S102, the type of water-based fracturing fluid includes any one of low-viscosity slickwater, medium-high viscosity slickwater, cross-linked fracturing fluid, and supramolecular hydrophobic associative fracturing fluid.

9. The method for evaluating reservoir fracture damage using fracturing fluid and temporary plugging agent as described in claim 8, characterized in that: The low-viscosity slippery water is prepared by the following proportions: 0.05% to 0.1% drag reducer; 0.05% to 0.1% bactericide; and the remainder is water for dispensing.

10. The method for evaluating reservoir fracture damage using fracturing fluid and temporary plugging agent as described in claim 8, characterized in that: The medium-high viscosity slippery water is formulated with the following proportions: 0.2%–0.5% drag reducer; 0.05%–0.1% bactericide; 0.1% degumming agent; and the remainder is water for mixing.

11. The method for evaluating reservoir fracture damage using fracturing fluid and temporary plugging agent as described in claim 8, characterized in that: The cross-linked fracturing fluid is formulated with the following proportions: 0.5%–0.7% drag reducer; 0.5%–0.6% cross-linking agent; 0.2% bactericide; 0.2% breaker; and the remainder is water for mixing.

12. The method for evaluating reservoir fracture damage using fracturing fluid and temporary plugging agent as described in claim 8, characterized in that: The formulation of supramolecular hydrophobic associative fracturing fluid is as follows: 0.15%–0.25% supramolecular thickener; 0.2% bactericide; 0.005%–0.02% breaker; the remainder is water for fluid preparation.

13. The method for evaluating reservoir fracture damage using fracturing fluid and temporary plugging agent as described in any one of claims 1-5, characterized in that: The temporary plugging agent is of the type of temporary plugging granules or temporary plugging powder.

14. A method for determining whether the dissolution time of a temporary plugging agent is qualified, characterized in that: Specifically, the method involves placing the temporary plugging agent in a beaker containing standard saline solution, allowing it to stand at the reservoir temperature, and measuring the dissolution time t2 of the temporary plugging agent in the beaker. The measured dissolution time t2 is then compared with the time t1 for the conductivity to stabilize, measured using the reservoir fracture damage assessment method for fracturing fluid and temporary plugging agent as described in any one of claims 1-13. If the difference between t1 and t2 is more than 24 hours, the dissolution time of the temporary plugging agent is deemed unqualified.

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