A method for optimizing directional fracture creation parameters for temporary plugging in old wells based on stress difference-microseismic joint control

Abstract

This invention discloses a method for optimizing directional fracture creation parameters in old wells based on stress difference-microseismic joint control, comprising the following steps: S1: Data acquisition; S2: Constructing a longitudinal stress calculation model for the old well; S3: Simulating fracture morphology, selecting and matching temporary plugging particles and filling particles, and obtaining the total amount of temporary plugging agent; S4: Determining the stress characteristics of the model and calculating the deflection angles of new and old fractures; S5: Adjusting the temporary plugging parameters by comparing with the actual deflection angles; S6: After fracturing, comparing the changes in the distribution of remaining oil in the target area, evaluating the fracturing effect in conjunction with cumulative production data, and correcting the model based on the evaluation results; S7: Sequentially completing the fracturing operations for each target sand body. The beneficial effects of this invention are: It achieves precise point initiation and height control of fractures within the target reservoir sand body, effectively tapping the remaining oil in the longitudinal reservoir sand body, reducing the risk of water-connecting layers, and has promising applications in increasing single-well production and tapping the remaining oil potential in low-yield wells in old oilfields.

Description

Technical Field

[0001] This invention relates to the field of oilfield development technology, and in particular to a method for optimizing parameters of temporary plugging and directional fracture creation in old wells based on stress difference-microseismic joint control. Background Technology

[0002] During oilfield development, changes in environmental conditions such as pressure and temperature often lead to wax and scale buildup causing blockages, proppant failure, or stress changes, resulting in the complete closure of over 60% of old fractures and loss of conductivity. Furthermore, insufficient initial fracturing scale results in short propped fractures with low conductivity, failing to meet expectations. Conventional hydraulic fracturing is a crucial technique for increasing oil and gas well production and water injection in injection wells, showing significant effectiveness in enhancing production in medium-to-high permeability oil and gas reservoirs, substantially improving well production and ultimate recovery. However, for old wells that have already undergone fracturing, due to existing hydraulic fractures, fracturing fluid preferentially enters the original old fractures during repeated fracturing, with only 12%–30% of new fractures effectively opened. Moreover, the expansion direction of these new fractures is random, failing to target remaining oil-rich areas. Microseismic monitoring technology can only provide post-event evaluation and lacks real-time control capabilities, impacting the production increase and development effectiveness of repeated fracturing. Summary of the Invention

[0003] The purpose of this invention is to overcome the shortcomings of traditional temporary plugging fracturing, such as uncontrollable fracture extension direction and difficulty in actively targeting and communicating with the target remaining oil-rich area, and to provide an optimization method for directional fracture creation parameters of temporary plugging in old wells based on stress difference-microseismic joint control.

[0004] The objective of this invention is achieved through the following technical solution: a method for optimizing directional fracture creation parameters for temporary plugging in old wells based on stress difference-microseismic joint control, comprising the following steps:

[0005] S1: Screen low-permeability reservoir target areas and collect corresponding data;

[0006] S2: Construct a longitudinal stress calculation model for the old well;

[0007] S3: Simulate crack morphology, select and match temporary plugging particles and filling particles, and obtain the total amount of temporary plugging agent;

[0008] S4: Combine the stress calculation model to determine the stress characteristics of the model and calculate the deflection angle of new and old cracks;

[0009] S5: Adjust the temporary blocking parameters by comparing with the actual deflection angle;

[0010] S6: After the fracturing operation is completed, compare the changes in the distribution of remaining oil in the target area, evaluate the fracturing effect in combination with the cumulative production data, and correct the model based on the evaluation results;

[0011] S7: Complete the fracturing operation of each target sand body in sequence.

[0012] Preferably, in step S1, geological feature data, old well engineering data, and geomechanical data are collected.

[0013] Preferably, step S2 further includes the following step:

[0014] S21: Establish the initial stress model using the elastic wave inversion formula.

[0015] ;

[0016] ;

[0017] ;

[0018] in, For the stress of the overlying strata, For dynamic Young's modulus, and For the P-wave and S-wave velocities, For dynamic Poisson's ratio, Formation density at the reference depth, As the reference depth, For the first Sectional density, For the first The thickness of the strata is as follows: The density of rock per unit volume It is the acceleration due to gravity;

[0019] S22: Construct a vertical stress calculation model.

[0020] ;

[0021] in, For vertical principal stress, The hydrostatic pressure gradient per unit depth. This is the formation pressure coefficient. For depth,

[0022] The formula for calculating the maximum horizontal principal stress is:

[0023] ;

[0024] The formula for calculating the minimum horizontal principal stress is:

[0025] ;

[0026] in, The maximum principal stress is horizontal. For the minimum principal stress in the horizontal direction, and The structural stress coefficient, For the elastic modulus of rock, For the Poisson's ratio of rocks, The effective stress coefficient, This refers to pore pressure.

[0027] Preferably, in step S3, the volume calculation formula for the temporary plugging particles and the filling particles is as follows:

[0028] ;

[0029] ;

[0030] in, To fill the particle volume, For coarse particle volume, This refers to the volume fraction of the filling particles in the voids between coarse particles during the critical fluid-solid state. This refers to the volume fraction of coarse particles in the total volume of the sealing layer under the most compact packing state. This represents the total volume of the sealing layer.

[0031] Obtain the ratio of filler particles.

[0032] ;

[0033] The total amount of temporary plugging agent used is:

[0034] ;

[0035] in, This represents a margin, with a value ranging from 0.1 to 0.3. This refers to the bulk density of the temporary plugging agent. To make the seam higher, To achieve effective sealing depth, The average width of the seam. The loss coefficient of the temporary plugging agent in the orifice. This represents the total perforated thickness of the fracturing section. The thickness of the target temporary blocking section is determined by the injection. It is a hole-tight hole.

[0036] Preferably, step S4 further includes the following step:

[0037] S41: Calculate the average flow velocity of the fluid inside the fracture.

[0038] ;

[0039] in, The flow regime coefficient is... The conductivity coefficient of the fracture. The rock damage coefficient is... For the Poisson's ratio of rocks, For dynamic Young's modulus, For horizontal stress difference, For dynamic seam width, The net pressure inside the seam. This refers to the viscosity of the fracturing fluid. The length of the crack segment;

[0040] S42: The mechanical mechanism calculation formula for the angle between the new and old cracks, based on the stress difference, is as follows:

[0041] ;

[0042] in, The crack deflection angle, The tensile strength of the rock at the location where new cracks form in the well wall. The tensile strength of the crack at the point where a new crack forms in the wellbore.

[0043] Preferably, in step S5, the threshold is set to 8°. When insufficient steering is determined, the concentration of coarse particles in the temporary plugging agent is increased while keeping the total amount unchanged, or the injection rate of the temporary plugging agent is increased while keeping other parameters stable. When excessive steering is determined, the proportion of coarse particles is reduced and the overall concentration is increased.

[0044] The deflection angle will be recalculated after each adjustment based on the microseismic data. Compared with the model baseline value In comparison, if the absolute deviation If the parameters are not adjusted, a new round of parameter adjustments will be initiated; otherwise, the current construction parameters will be maintained.

[0045] If the deviation still exceeds the threshold after three consecutive rounds of adjustments, construction will be suspended and the results will be rechecked.

[0046] This invention has the following advantages: It establishes a geostress model based on data parameters, designs a temporary plugging and directional fracture creation scheme using the model, and utilizes microseismic monitoring technology for real-time monitoring. Adjustments are made to the operation based on the monitoring results. After fracturing, the distribution changes of remaining oil in the target area are compared, and the fracturing effect is evaluated in conjunction with cumulative production data. Simultaneously, model correction is carried out based on the evaluation results, achieving precise location-based fracturing initiation and height control within the target reservoir sand body. This effectively taps the remaining oil in the vertical reservoir sand body and significantly reduces the risk of connecting water layers. This method has broad application prospects in improving single-well production and tapping the remaining oil potential in low-yield wells in old oilfields. Attached Figure Description

[0047] Figure 1 This is a schematic diagram of the process for optimizing the parameters of directional fracture creation through temporary plugging in old wells based on stress difference-microseismic joint control.

[0048] Figure 2A schematic diagram of the initial oil saturation of the PI sublayer;

[0049] Figure 3 This is a schematic diagram of the oil saturation after PI small-layer fracturing. Detailed Implementation

[0050] 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, and not all embodiments. The components of the embodiments of the present invention described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.

[0051] 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.

[0052] It should be noted that, unless otherwise specified, the embodiments and features described in this invention can be combined with each other.

[0053] It should be noted that similar labels and letters in the following figures indicate similar items. Therefore, once an item is defined in one figure, it does not need to be further defined and explained in subsequent figures.

[0054] In the description of this invention, the method involved is applied to the Pubei Fault Block for experimentation, and the specific experimental steps are as follows:

[0055] In this embodiment, as Figure 1 As shown, a method for optimizing directional fracture creation parameters for temporary plugging in old wells based on stress difference-microseismic joint control includes the following steps:

[0056] S1: Screen low-permeability reservoir target areas and collect corresponding data;

[0057] S2: Construct a longitudinal stress calculation model for the old well;

[0058] S3: Simulate crack morphology, select and match temporary plugging particles and filling particles, and obtain the total amount of temporary plugging agent;

[0059] S4: Combine the stress calculation model to determine the stress characteristics of the model and calculate the deflection angle of new and old cracks;

[0060] S5: Adjust the temporary blocking parameters by comparing with the actual deflection angle;

[0061] S6: After the fracturing operation is completed, compare the changes in the distribution of remaining oil in the target area, evaluate the fracturing effect in combination with the cumulative production data, and correct the model based on the evaluation results;

[0062] S7: Complete the fracturing operations for each target sand body sequentially. This invention establishes a geostress model based on data parameters, designs a temporary plugging directional fracture creation scheme using the model, and utilizes microseismic monitoring technology for real-time monitoring. Adjustments are made to the operation based on the monitoring results. After fracturing, the distribution changes of remaining oil in the target area are compared, and the fracturing effect is evaluated in conjunction with cumulative production data. Simultaneously, model correction is carried out based on the evaluation results. Through stress difference guidance, temporary plugging redirection, and real-time microseismic control, precise location initiation and height control of fractures within the target reservoir sand body are achieved, effectively tapping the remaining oil in the vertical reservoir sand body and significantly reducing the risk of connecting water layers. This method has broad application prospects in increasing single-well production and tapping the remaining oil potential of low-yield wells in old oilfields.

[0063] Further, in step S1, geological characteristic data, old well engineering data, and geomechanical data are collected. Further, the geological characteristic data includes reservoir porosity data, permeability data, oil saturation data, cumulative oil production data, rock density data (average density of overlying strata, density of strata at different depths), pore pressure data, and remaining oil distribution data of sand bodies (including planar distribution range and vertical enrichment intervals); the old well engineering data includes well history data, covering fracture morphology (fracture length, width, height), fracture orientation, formation pressure, sand-producing intervals, geostress test data, and continuous distribution of pore pressure with depth; the geomechanical parameters include Young's modulus, Poisson's ratio of the rock, rock elastic modulus, transverse and longitudinal wave velocities, and tectonic stress coefficients. Specifically, the geological data collected and processed based on the PI sublayer of the Pubei fault block are shown in Table 1, and the oil saturation data are as follows: Figure 2 As shown,

[0064] Table 1

[0065] Reservoir thickness (m) Porosity (%) Penetration rate (mD) Oil saturation (%) Young's modulus (GPa) The overlying strata are dense (g / cm³). 54.9 17 1.3 60 19 2.32 Poisson's ratio Average seam length (m) Average seam width (mm) Formation pressure (MPa) Cumulative oil production (t) Pore ​​pressure (MPa) 0.29 100 0.27 23 <![CDATA[56×10 4 t]]> 23.5

[0066] In this embodiment, step S2 further includes the following step:

[0067] S21: Establish the initial stress model using the elastic wave inversion formula.

[0068] ;

[0069] ;

[0070] ;

[0071] in, For the stress of the overlying strata, For dynamic Young's modulus, and For the P-wave and S-wave velocities, For dynamic Poisson's ratio, Formation density at the reference depth, As the reference depth, For the first Sectional density, For the first The thickness of the strata is as follows: The density of rock per unit volume It is the acceleration due to gravity;

[0072] S22: Construct a vertical stress calculation model.

[0073] ;

[0074] in, For vertical principal stress, The hydrostatic pressure gradient per unit depth. This is the formation pressure coefficient. For depth,

[0075] The formula for calculating the maximum horizontal principal stress is:

[0076] ;

[0077] The formula for calculating the minimum horizontal principal stress is:

[0078] ;

[0079] in, The maximum principal stress is horizontal. For the minimum principal stress in the horizontal direction, and The structural stress coefficient, For the elastic modulus of rock, For the Poisson's ratio of rocks, The effective stress coefficient is usually... The harder the rock skeleton, the closer it is to 0. This represents pore pressure. Specifically, the stress is calculated using the PI sublayer geological data collected in step S1, and the results are shown in Table 2.

[0080] Table 2

[0081] Vertical stress (MPa) Maximum horizontal principal stress (MPa) Horizontal minimum principal stress (MPa) Stress difference (MPa) PI layer 35.6 29.2 21.3 7.9

[0082] Furthermore, in step S3, based on the stress calculation model and considering the distribution of remaining oil in the sand body and the crack morphology, the temporary plugging particles and filler particles are selected and matched. Specifically, the temporary plugging particles are coarse-grained rigid materials that serve as bridging and sealing agents, with a median particle size matching 2 / 3 of the average pore diameter. The filler particles are used for filling and sealing, with a median particle size matching 1 / 3 of the average pore diameter. Both use spherical particles of different sizes. Specifically, the volume calculation formulas for the temporary plugging particles and filler particles are as follows:

[0083] ;

[0084] ;

[0085] in, To fill the particle volume, For coarse particle volume, This refers to the volume fraction of the filling particles in the voids between coarse particles during the critical fluid-solid state. This refers to the volume fraction of coarse particles in the total volume of the sealing layer under the most compact packing state. This represents the total volume of the sealing layer.

[0086] Obtain the ratio of filler particles.

[0087] ;

[0088] Based on the PI sublayer parameters collected in step S1, and calculated using the above formula, the particle size distribution of the filler particles and coarse particles is shown in Table 3.

[0089] Table 3

[0090] coarse particles Filler particles Average diameter (mesh) 100-120 200-230 Optimal ratio (%) 67.6 32.4

[0091] The total amount of temporary plugging agent used is:

[0092] ;

[0093] in, This represents a margin, with a value ranging from 0.1 to 0.3. This refers to the bulk density of the temporary plugging agent. To make the seam higher, To achieve effective sealing depth, The average width of the seam. The loss coefficient of the temporary plugging agent in the orifice. This represents the total perforated thickness of the fracturing section. The thickness of the target temporary blocking section is determined by the injection. For pore density. Specifically, calculations show that the amount of temporary plugging agent injected into the PI layer is 221 kg for the filler particles and 920 kg for the coarse particles. Specific calculation parameters are shown in Table 4.

[0094] Table 4

[0095] coarse particles Filler particles surplus 0.2 0.15 Bulk density of temporary plugging agent (kg / m³) 1600 1100 Average seam width (mm) 5 5 Loss coefficient 1.5 0.8 Total indentation thickness (m) 12 12 Target segment penetration thickness (m) 4 4 Pore ​​density (pores / m) 14 14

[0096] Furthermore, step S4 also includes the following steps:

[0097] S41: Calculate the average flow velocity of the fluid inside the fracture.

[0098] ;

[0099] in, The flow regime coefficient is... The conductivity coefficient of the fracture. The rock damage coefficient is... For the Poisson's ratio of rocks, For dynamic Young's modulus, For horizontal stress difference, For dynamic seam width, The net pressure inside the seam. This refers to the viscosity of the fracturing fluid. The length of the crack segment;

[0100] S42: The mechanical mechanism calculation formula for the angle between the new and old cracks, based on the stress difference, is as follows:

[0101] ;

[0102] in, The crack deflection angle, The tensile strength of the rock at the location where new cracks form in the well wall. This refers to the tensile strength of the fractures at the points where new fractures form in the wellbore. Specifically, by adjusting the injection rate to change the average flow velocity of the fluid within the fractures, the formation stress difference is reshaped, thus achieving the deflection angle between old and new fractures. With precise control, the flow velocity inside the gap was calculated to be 0.53 m / min. The specific calculation parameters are shown in Table 5.

[0103] Table 5

[0104] Flow coefficient Rock damage coefficient Horizontal stress difference (MPa) Fracturing fluid viscosity (Pa·s) Crack segment length (m) Net pressure inside the seam (MPa) 10 1.5 7.9 0.1 15 5

[0105] Based on the PI layer parameters, the deflection angle of the new suture can be calculated using a formula. It is 28°.

[0106] In this embodiment, in step S5, the threshold is set to 8°. When it is determined that the steering is insufficient, the concentration of coarse particles in the temporary plugging agent is increased while the total amount remains unchanged, or the injection rate of the temporary plugging agent is increased while the other parameters remain stable. When the steering is excessive, the proportion of coarse particles is reduced and the overall concentration is increased.

[0107] The deflection angle will be recalculated after each adjustment based on the microseismic data. Compared with the model baseline value In comparison, if the absolute deviation If the parameters are not adjusted, a new round of parameter adjustments will be initiated; otherwise, the current construction parameters will be maintained.

[0108] If the deviation still exceeds the threshold after three consecutive rounds of adjustments, construction should be suspended and the accuracy of the geostress model and microseismic monitoring should be rechecked to avoid ineffective adjustments that could lead to fracturing failure.

[0109] After fracturing is completed, the production dynamics data (including well production, pressure changes, etc.) are accurately imported into the model using the existing Petrel reservoir modeling software. Based on reservoir numerical simulation technology, a quantitative comparative analysis of the remaining oil distribution in the target area before and after fracturing is conducted. The remaining oil distribution in the target area after fracturing is shown below. Figure 3 As shown, it can be seen that there are obvious mobilization characteristics, and the original remaining oil-rich area has shrunk significantly, which confirms that the fracturing fractures have effectively connected the unused reservoir and achieved efficient displacement of the remaining oil.

[0110] The experimental results of this invention are analyzed as follows: Through field tests, it is shown that the method of optimizing the parameters of temporary plugging directional fracture creation based on stress difference-microseismic joint control is highly effective for sandstone reservoirs with remaining oil accumulation in directional old wells of this type of "multiple and thin" development reservoir. This method achieves precise directional expansion of fractures in the target sandstone body through stress difference analysis and real-time microseismic joint control, effectively tapping the potential of vertical remaining oil.

[0111] This invention addresses the complex oil-water relationship in the mid-to-late stages of low-permeability, medium-to-high water-cut reservoir development. To accurately tap the remaining oil in the vertical reservoir sandstone bodies and prevent water-bearing increases caused by fracturing, a geostress model is first established based on acquired data parameters. Then, using formulaic methods, a temporary plugging and directional fracture creation scheme is designed through the model. Subsequently, the design scheme guides the actual operation. During the process, microseismic monitoring technology is used for real-time monitoring, and adjustments are made to the operation based on the monitoring results. After the fracturing operation is completed, the changes in the distribution of remaining oil in the target area are compared, and the fracturing effect is evaluated in conjunction with cumulative production data. Simultaneously, model correction is carried out based on the evaluation results. Through stress difference guidance, temporary plugging and redirection, and microseismic control, precise location initiation and height control of fractures within the target reservoir sandstone bodies are achieved, effectively tapping the remaining oil in the vertical reservoir sandstone bodies and significantly reducing the risk of water-bearing. This method has broad application prospects in improving single-well production and tapping the remaining oil potential in low-yield wells in old oilfields.

[0112] Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions described in the foregoing embodiments or make equivalent substitutions for some of the technical features. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A method for optimizing directional fracture creation parameters in old wells based on stress difference-microseismic joint control, characterized in that: Includes the following steps: S1: Screen low-permeability reservoir target areas and collect corresponding data; S2: Construct a longitudinal stress calculation model for the old well; S3: Simulate crack morphology, select and match temporary plugging particles and filling particles, and obtain the total amount of temporary plugging agent; S4: Combine the stress calculation model to determine the stress characteristics of the model and calculate the deflection angle of new and old cracks; S5: Adjust the temporary blocking parameters by comparing with the actual deflection angle; S6: After the fracturing operation is completed, compare the changes in the distribution of remaining oil in the target area, evaluate the fracturing effect in combination with the cumulative production data, and correct the model based on the evaluation results; S7: Complete the fracturing operations of each target sand body in sequence; Step S2 further includes the following steps: S21: Establish the initial stress model using the elastic wave inversion formula. ； ； ； in, For the stress of the overlying strata, For dynamic Young's modulus, For the longitudinal wave velocity, For transverse wave velocity, For dynamic Poisson's ratio, Formation density at the reference depth, As the reference depth, For the first Sectional density, For the first The thickness of the strata is as follows: The density of rock per unit volume It is the acceleration due to gravity; S22: Construct a vertical stress calculation model. ； in, For vertical principal stress, The hydrostatic pressure gradient per unit depth. This is the formation pressure coefficient. For depth, The formula for calculating the maximum horizontal principal stress is: ； The formula for calculating the minimum horizontal principal stress is: ； in, The maximum principal stress is horizontal. For the minimum principal stress in the horizontal direction, and The structural stress coefficient, For the elastic modulus of rock, For the Poisson's ratio of rocks, The effective stress coefficient, Pore ​​pressure; Step S4 also includes the following steps: S41: Calculate the average flow velocity of the fluid inside the fracture. ； in, The flow regime coefficient is... The conductivity coefficient of the fracture. The rock damage coefficient is... For the Poisson's ratio of rocks, For dynamic Young's modulus, For horizontal stress difference, For dynamic seam width, The net pressure inside the seam. This refers to the viscosity of the fracturing fluid. The length of the crack segment; S42: Based on the stress difference, the mechanical mechanism for calculating the deflection angle of new and old cracks is as follows: ； in, The deflection angle between the old and new cracks. The tensile strength of the rock at the location where new cracks form in the well wall. The tensile strength of the crack at the point where a new crack forms in the wellbore; In step S5, the threshold is set to 8°. When the steering is determined to be insufficient, the concentration of coarse particles in the temporary plugging agent is increased while the total amount remains unchanged, or the injection rate of the temporary plugging agent is increased while the other parameters remain stable. When the steering is excessive, the proportion of coarse particles is reduced and the overall concentration is increased. The deflection angle will be recalculated after each adjustment based on the microseismic data. Compared with the model baseline value In comparison, if the absolute deviation If the parameters are not adjusted, a new round of parameter adjustments will be initiated; otherwise, the current construction parameters will be maintained. If the deviation still exceeds the threshold after three consecutive rounds of adjustments, construction will be suspended and the results will be rechecked.

2. The method for optimizing directional fracture creation parameters for temporary plugging of old wells based on stress difference-microseismic joint control as described in claim 1, characterized in that: In step S1, geological feature data, old well engineering data, and geomechanical data are collected.

3. The method for optimizing directional fracture creation parameters for temporary plugging of old wells based on stress difference-microseismic joint control as described in claim 2, characterized in that: In step S3, the volume calculation formulas for the temporary plugging particles and the filling particles are as follows: ； ； in, To fill the particle volume, For coarse particle volume, This refers to the volume fraction of the filling particles in the voids between coarse particles during the critical fluid-solid state. This refers to the volume fraction of coarse particles in the total volume of the sealing layer under the most compact packing state. This represents the total volume of the sealing layer. Obtain the ratio of filler particles. ； The total amount of temporary plugging agent used is: ； in, This represents a margin, with a value ranging from 0.1 to 0.

3. This refers to the bulk density of the temporary plugging agent. To make the seam higher, To achieve effective sealing depth, The average width of the seam. The loss coefficient of the temporary plugging agent in the orifice. This represents the total perforated thickness of the fracturing section. The thickness of the target temporary blocking section is determined by the injection. It is a hole-dense structure.

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