Old well temporary plugging directional fracture forming parameter optimization method based on stress difference-microseism joint control

Abstract

The invention discloses a stress difference-microseism joint control-based old well temporary plugging directional fracture forming parameter optimization method. The method comprises the following steps of S1, collecting data; s2, constructing an old well longitudinal stress calculation model; s3, simulating the shape of the crack, selecting and matching the temporary plugging particles and the filling particles, and obtaining the total dosage of a temporary plugging agent; s4, model stress characteristics are determined, and deflection angles of new and old cracks are calculated; s5, adjusting temporary blocking parameters by comparing the actual deflection angle; s6, after fracturing construction, comparing the distribution change of remaining oil in the target area, evaluating the fracturing effect in combination with accumulated production data, and correcting the model according to the evaluation result; and S7, fracturing operation of all the target sand bodies is completed in sequence. The method has the beneficial effects that accurate fixed-point crack initiation and height control of the crack in the target reservoir sand body are achieved, the remaining oil of the longitudinal reservoir sand body is effectively excavated, the risk of water layer communication is reduced, and the method has the application prospect in the aspects of improving the single-well yield of a low-yield well of an old oil field and excavating the potential of the remaining oil.

Description

Technical Field

[0001] The invention relates to the technical field of oilfield development, 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 Art

[0002] During oilfield development, changes in environmental conditions such as pressure and temperature often lead to wax and scaling blockage, proppant failure, or stress changes, resulting in the complete closure of over 60% of existing fractures and the loss of conductivity. Furthermore, insufficient initial fracturing efforts can shorten propped fractures and reduce fracture conductivity, often failing to meet expectations. Conventional hydraulic fracturing is a key technology for increasing oil and gas well production and water injection rates in medium- and high-permeability reservoirs, significantly boosting well production and ultimate recovery. However, for wells that have undergone prior hydraulic fracturing, the fracturing fluid preferentially enters the pre-existing fractures during refracturing, effectively opening only 12% to 30% of new fractures. Furthermore, these new fractures propagate in random directions, making it impossible to target areas rich in residual oil. Microseismic monitoring technology can only provide post-fracturing evaluations and lacks real-time control capabilities, hindering the extent of refracturing increases and development effectiveness. Summary of the Invention

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

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

[0005] S1: Screen the target area of ​​low permeability reservoir and collect corresponding data;

[0006] S2: Constructing a calculation model for the longitudinal stress of old wells;

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

[0008] S4: Determine the stress characteristics of the model by combining the stress calculation model and calculate the deflection angles of new and old cracks;

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

[0010] S6: After completing the fracturing operation, compare the changes in the remaining oil distribution in the target area, evaluate the fracturing effect in combination with the cumulative production data, and calibrate 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 characteristic data, old well engineering data and geomechanical data are collected.

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

[0014] S21: Establish the initial stress model through the elastic wave inversion formula,

[0015] ;

[0016] ;

[0017] ;

[0018] in, is the overlying stratum stress, is the dynamic Young's modulus, and are the longitudinal and transverse wave velocities, is the dynamic Poisson's ratio, is the formation density at the reference depth, is the reference depth, For the Segment stratum density, For the The thickness of the stratum, is the density of rock per unit volume, is the acceleration due to gravity;

[0019] S22: Construct vertical stress calculation model,

[0020] ;

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

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

[0023] ;

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

[0025] ;

[0026] in, is the maximum horizontal principal stress, is the horizontal minimum principal stress, and is the tectonic stress coefficient, is the elastic modulus of rock, is the Poisson's ratio of rock, is the effective stress coefficient, is the pore pressure.

[0027] Preferably, in step S3, the volume calculation formula corresponding to the temporary blocking particles and the filling particles is:

[0028] ;

[0029] ;

[0030] in, is the volume of the filling particles, is the volume of coarse particles, is the volume fraction of the filling particles in the gaps between coarse particles under the fluid-solid critical state, is the volume fraction of coarse particles in the total volume of the plugging layer in the most densely packed state, is the total volume of the plugging layer,

[0031] Get the ratio of filling particles,

[0032] ;

[0033] The total dosage of temporary plugging agent is:

[0034] ;

[0035] in, is the margin, the value range is 0.1~0.3, is the bulk density of the temporary plugging agent, For seam height, is the effective plugging depth, is the average width of the seam, is the loss coefficient of temporary plugging agent, is the total perforated thickness of the fracturing section, The thickness of the target temporary blocking section is It is Kongmi.

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

[0037] S41: Calculate the average flow velocity of the fluid in the fracture,

[0038] ;

[0039] in, is the flow coefficient, is the fracture conductivity coefficient, is the rock damage coefficient, is the Poisson's ratio of rock, is the dynamic Young's modulus, is the horizontal stress difference, is the dynamic seam width, is the net pressure in the seam, is the fracturing fluid viscosity, is the length of the crack segment;

[0040] S42: The mechanical formula for calculating the angle between the new crack and the old crack is:

[0041] ;

[0042] in, is the crack deflection angle, The tensile strength of the rock where new cracks are formed on the well wall, It is the tensile strength of the new cracks formed in the well wall.

[0043] Preferably, 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 dosage remains unchanged, or the injection speed 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.

[0044] After each adjustment, the deflection angle of the microseismic recalculation is With model benchmark value In contrast, if the absolute deviation , a new round of parameter adjustment is started, otherwise the current construction parameters are maintained;

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

[0046] The present invention has the following advantages: the present invention establishes a geostress model based on data parameters, designs a temporary plugging and directional fracture creation scheme through the model, and uses microseismic monitoring technology for real-time monitoring, adjusts the operation according to the monitoring results, and after completing the fracturing construction, compares the changes in the distribution of residual oil in the target area, evaluates the fracturing effect in combination with the cumulative production data, and simultaneously performs model correction based on the evaluation results to achieve precise point-to-point initiation and height control of fractures in the target reservoir sand body, effectively tap the potential of residual oil in the vertical reservoir sand body, and significantly reduce the risk of connecting water layers. This method has broad application prospects in increasing the single well production and tapping the potential of residual oil in low-yield wells in old oil fields. BRIEF DESCRIPTION OF THE DRAWINGS

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

[0048] Figure 2Schematic diagram of the initial oil saturation of the PI layer;

[0049] Figure 3 Schematic diagram of oil saturation in the PI layer after fracturing. DETAILED DESCRIPTION

[0050] To make the objectives, technical solutions, and advantages of the embodiments of the present invention more clear, the technical solutions of the embodiments of the present invention will be clearly and completely described below in conjunction with the accompanying drawings of the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, not all embodiments. Generally, the components of the embodiments of the present invention described and shown in the drawings herein can be arranged and designed in various different configurations.

[0051] Therefore, the following detailed description of the embodiments of the present invention provided in the accompanying drawings is not intended to limit the scope of the invention as claimed, but rather merely represents selected embodiments of the present invention. All other embodiments derived by persons of ordinary skill in the art based on the embodiments of the present invention without creative effort are also within the scope of protection of the present invention.

[0052] It should be noted that, in the absence of conflict, the embodiments and features of the embodiments of the present invention can be combined with each other.

[0053] It should be noted that similar reference numerals and letters denote similar items in the following drawings, and therefore, once an item is defined in one drawing, it does not require further definition or explanation in subsequent drawings.

[0054] In the description of the present invention, the method involved in the present invention is applied to the Pubei fault block for experimentation, and the specific experimental steps are as follows:

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

[0056] S1: Screen the target area of ​​low permeability reservoir and collect corresponding data;

[0057] S2: Constructing a calculation model for the longitudinal stress of old wells;

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

[0059] S4: Determine the stress characteristics of the model by combining the stress calculation model and calculate the deflection angles of new and old cracks;

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

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

[0062] S7: Complete the fracturing operation of each target sand body in sequence. The present invention establishes a geostress model based on data parameters, designs a temporary plugging and directional fracture creation scheme through the model, and uses microseismic monitoring technology for real-time monitoring. The operation is adjusted according to the monitoring results. After the fracturing operation is completed, the distribution changes of the remaining oil in the target area are compared, and the fracturing effect is evaluated in combination with the cumulative production data. The model is calibrated synchronously based on the evaluation results. Through stress difference guidance, temporary plugging and diversion, and real-time microseismic regulation, the cracks are precisely initiating and highly controlled in the target reservoir sand body, effectively tapping the potential of the remaining oil in the vertical reservoir sand body and significantly reducing the risk of connecting the water layer. This method has broad application prospects in increasing the single well production and tapping the potential of the remaining oil in low-yield wells in old oil fields.

[0063] Furthermore, in step S1, geological characteristic data, old well engineering data and geomechanical data are collected. Furthermore, the geological characteristic data include 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 sand body residual oil distribution data (including plane distribution range, vertical enrichment layer section); old well engineering data include well history data, covering fracture morphology (fracture length, fracture width, fracture height), fracture direction, formation pressure, sand layer section, ground stress test data and continuous distribution of pore pressure with depth; geomechanical parameters include Young's modulus, rock Poisson's ratio, rock elastic modulus, transverse and longitudinal wave velocities and tectonic stress coefficients. Specifically, the geological data collected and sorted based on the PI layer of the Pubei fault block are shown in Table 1, and the oil saturation data are shown in Table 1. Figure 2 As shown,

[0064] Table 1

[0065] Reservoir thickness (m) Porosity (%) Permeability (mD) Oil saturation (%) Young's modulus (GPa) Density of overlying strata (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 steps:

[0067] S21: Establish the initial stress model through the elastic wave inversion formula,

[0068] ;

[0069] ;

[0070] ;

[0071] in, is the overlying stratum stress, is the dynamic Young's modulus, and are the longitudinal and transverse wave velocities, is the dynamic Poisson's ratio, is the formation density at the reference depth, is the reference depth, For the Segment stratum density, For the The thickness of the stratum, is the density of rock per unit volume, is the acceleration due to gravity;

[0072] S22: Construct vertical stress calculation model,

[0073] ;

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

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

[0076] ;

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

[0078] ;

[0079] in, is the maximum horizontal principal stress, is the horizontal minimum principal stress, and is the tectonic stress coefficient, is the elastic modulus of rock, is the Poisson's ratio of rock, is the effective stress coefficient, usually , the harder the rock skeleton, the closer it is to 0, Specifically, the pore pressure is calculated based on the geological data of the PI layer collected in step S1. The stress results in various directions 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, combined with the distribution position of the remaining oil in the sand body and the fracture morphology, the temporary plugging particles and the filling particles are selected and matched. In other words, the temporary plugging particles are made of coarse rigid materials to play the role of bridging and plugging, and their median particle size matches 2 / 3 of the average pore diameter. The filling particles are used for filling and plugging, and their median particle size is adapted to 1 / 3 of the average pore diameter. Both use spherical particles of different sizes. Specifically, the volume calculation formula corresponding to the temporary plugging particles and the filling particles is:

[0083] ;

[0084] ;

[0085] in, is the volume of the filling particles, is the volume of coarse particles, is the volume fraction of the filling particles in the gaps between coarse particles under the fluid-solid critical state, is the volume fraction of coarse particles in the total volume of the plugging layer in the most densely packed state, is the total volume of the plugging layer,

[0086] Get the ratio of filling particles,

[0087] ;

[0088] Combined with the PI layer parameters collected in step S1, the above formula shows that the particle size distribution of filling particles and coarse particles is as shown in Table 3.

[0089] Table 3

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

[0091] The total dosage of temporary plugging agent is:

[0092] ;

[0093] in, is the margin, the value range is 0.1~0.3, is the bulk density of the temporary plugging agent, For seam height, is the effective plugging depth, is the average width of the seam, is the loss coefficient of temporary plugging agent, is the total perforated thickness of the fracturing section, The thickness of the target temporary blocking section is Specifically, according to calculations, the amount of temporary plugging agent injected into the PI layer is 221 kg for filling particles and 920 kg for coarse particles. The specific calculation parameters are shown in Table 4.

[0094] Table 4

[0095] coarse particles Filling particles Redundancy 0.2 0.15 Temporary plugging agent bulk density (kg / m³) 1600 1100 Average seam width (mm) 5 5 Loss coefficient 1.5 0.8 Total opening thickness (m) 12 12 Target section penetration thickness (m) 4 4 Pore ​​density (pores / m) 14 14

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

[0097] S41: Calculate the average flow velocity of the fluid in the fracture,

[0098] ;

[0099] in, is the flow coefficient, is the fracture conductivity coefficient, is the rock damage coefficient, is the Poisson's ratio of rock, is the dynamic Young's modulus, is the horizontal stress difference, is the dynamic seam width, is the net pressure in the seam, is the fracturing fluid viscosity, is the length of the crack segment;

[0100] S42: The mechanical formula for calculating the angle between the new crack and the old crack is:

[0101] ;

[0102] in, is the crack deflection angle, The tensile strength of the rock where new cracks are formed on the well wall, The tensile strength of the new fractures formed in the well wall is determined. Specifically, by adjusting the injection rate to change the average flow rate of the fluid in the fracture, the formation stress difference is driven to reshape and the deflection angle of the new and old fractures is achieved. The flow velocity in the slit is 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 in the seam (MPa) 10 1.5 7.9 0.1 15 5

[0105] Combined with the PI layer parameters, the new seam deflection angle is calculated by the 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 dosage remains unchanged, or the injection speed 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] After each adjustment, the deflection angle of the microseismic recalculation is With model benchmark value In contrast, if the absolute deviation , a new round of parameter adjustment is started, otherwise the current construction parameters are maintained;

[0108] If the deviation still exceeds the threshold after three consecutive rounds of adjustments, construction will be suspended and the ground stress model and microseismic monitoring accuracy will be recalibrated to avoid invalid adjustments that may lead to fracturing failure.

[0109] After the fracturing operation is completed, the production dynamic data after the fracturing operation (including information such as oil well production and pressure changes) is accurately imported into the model through the existing Petrel reservoir modeling software. Based on the reservoir numerical simulation technology, a quantitative comparative analysis of the remaining oil distribution in the target area before and after the fracturing operation is carried out. The distribution of the remaining oil in the target area after fracturing is as follows: Figure 3 As shown in the figure, it can be seen that there are obvious production characteristics, and the scope of the original remaining oil-rich area has shrunk significantly, which proves that the fracturing cracks have effectively connected the unused reservoirs and achieved efficient displacement of the remaining oil.

[0110] The experimental results of the present invention are analyzed as follows: Through field tests, it is shown that the temporary plugging directional fracture creation parameter optimization method based on stress difference and microseismic joint control is very targeted for such "multiple and thin" developed oil reservoirs with rich sandstone reservoirs rich in residual oil in old wells. Through stress difference analysis and real-time microseismic joint control, this method realizes the precise directional expansion of fractures in the target sandstone, effectively tapping the potential of vertical residual oil.

[0111] The present invention aims at the middle and late stages of development of low-permeability and medium-high water-content oil reservoirs, where the overall oil-water relationship of the oil reservoir is complex. In order to accurately tap the potential of the remaining oil in the vertical reservoir sand body of the oil reservoir and prevent the water content from rising due to fracturing and communication with the water layer, the present invention first establishes a geostress model based on the acquired data parameters, and then uses the formula method to design a temporary plugging and directional fracture creation scheme through the model, and then uses the design scheme to guide the actual operation. During the process, microseismic monitoring technology is used for real-time monitoring, and the operation is adjusted according to the monitoring results. After the fracturing construction is completed, the distribution changes of the remaining oil in the target area are compared, and the fracturing effect is evaluated in combination with the cumulative production data. Simultaneously, the model is calibrated based on the evaluation results. Through stress difference guidance, temporary plugging and diversion, and microseismic regulation, the cracks are accurately initiating and highly controlled at the fixed point in the target reservoir sand body, effectively tapping the potential of the remaining oil in the vertical reservoir sand body, and significantly reducing the risk of communication with the water layer. This method has broad application prospects in increasing the single well production and tapping the potential of remaining oil in low-yield wells in old oil fields.

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

Claims

1. A method for optimizing parameters of temporary plugging and directional fracture creation in old wells based on stress difference-microseismic joint control, characterized by: The following steps are involved: S1: Screen the target area of ​​low permeability reservoir and collect corresponding data; S2: Constructing a calculation model for the longitudinal stress of old wells; S3: Simulate the crack morphology, select and match temporary plugging particles and filling particles, and obtain the total amount of temporary plugging agent; S4: Determine the stress characteristics of the model by combining the stress calculation model and calculate the deflection angles of new and old cracks; S5: Adjust the temporary blocking parameters by comparing with the actual deflection angle; S6: After completing the fracturing operation, compare the changes in the remaining oil distribution in the target area, evaluate the fracturing effect in combination with the cumulative production data, and calibrate the model based on the evaluation results; S7: completing the fracturing operation of each target sand body in sequence; The step S2 further includes the following steps: S21: Establish the initial stress model through the elastic wave inversion formula, ； ； ； in, is the overlying stratum stress, is the dynamic Young's modulus, and are the longitudinal and transverse wave velocities, is the dynamic Poisson's ratio, is the formation density at the reference depth, is the reference depth, For the Segment stratum density, For the The thickness of the stratum, is the density of rock per unit volume, is the acceleration due to gravity; S22: Construct vertical stress calculation model, ； in, is the vertical principal stress, is the hydrostatic pressure gradient per unit depth, is the formation pressure coefficient, For depth, The calculation formula for the horizontal maximum principal stress is: ； The calculation formula for the horizontal minimum principal stress is: ； in, is the maximum horizontal principal stress, is the horizontal minimum principal stress, and is the tectonic stress coefficient, is the elastic modulus of rock, is the Poisson's ratio of rock, is the effective stress coefficient, is the pore pressure.

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

3. The method for optimizing parameters of temporary plugging and directional fracture creation in old wells based on stress difference-microseismic joint control according to claim 2 is characterized by: In step S3, the volume calculation formula corresponding to the temporary blocking particles and the filling particles is: ； ； in, is the volume of the filling particles, is the volume of coarse particles, is the volume fraction of the filling particles in the gaps between coarse particles under the fluid-solid critical state, is the volume fraction of coarse particles in the total volume of the plugging layer in the most densely packed state, is the total volume of the plugging layer, Get the ratio of filling particles, ； The total dosage of temporary plugging agent is: ； in, is the margin, the value range is 0.1~0.3, is the bulk density of the temporary plugging agent, For seam height, is the effective plugging depth, is the average width of the seam, is the loss coefficient of temporary plugging agent, is the total perforated thickness of the fracturing section, The thickness of the target temporary blocking section is It is Kongmi.

4. The method for optimizing parameters of temporary plugging and directional fracture creation in old wells based on stress difference-microseismic joint control according to claim 3 is characterized by: The step S4 further includes the following steps: S41: Calculate the average flow velocity of the fluid in the fracture, ； in, is the flow coefficient, is the fracture conductivity coefficient, is the rock damage coefficient, is the Poisson's ratio of rock, is the dynamic Young's modulus, is the horizontal stress difference, is the dynamic seam width, is the net pressure in the seam, is the fracturing fluid viscosity, is the length of the crack segment; S42: The mechanical formula for calculating the angle between the new crack and the old crack is: ； in, is the crack deflection angle, The tensile strength of the rock where new cracks are formed on the well wall, It is the tensile strength of the new cracks formed in the well wall.

5. The method for optimizing parameters of temporary plugging and directional fracture creation in old wells based on stress difference-microseismic joint control according to claim 4 is characterized in that: 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 dosage remains unchanged, or the injection speed 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. After each adjustment, the deflection angle of the microseismic recalculation is With model benchmark value In contrast, if the absolute deviation , a new round of parameter adjustment is started, otherwise the current construction parameters are maintained; If the deviation still exceeds the threshold after three consecutive rounds of adjustments, construction will be suspended and recalibrated.

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