Reservoir stimulation methods based on fracture propagation effect assessment

Abstract

This invention relates to the field of reservoir stimulation technology, specifically a reservoir stimulation method based on fracture extension effect determination. The method comprises the following steps: S1, conducting pre-prime formation testing to determine the optimal flow rate for controlling hydraulic fracturing fractures; S2, injecting fracturing fluid into the formation at the optimal flow rate and recording the pressure when the system is stable; S3, conducting flow rate increase testing and recording the pressure when the system is stable; S4, calculating the discrimination coefficient based on the stable pressure obtained in steps S2 and S3, and determining the specific construction flow rate based on the discrimination coefficient. This invention provides a method for determining the degree of fracture expansion by assessing the fracture extension effect and monitoring pressure fluctuations through small-flow-rate stepped pumping, thus guiding on-site construction operations. The method is simple to implement and significantly reduces operating costs while ensuring precise control of fracture extension.

Description

Technical Field

[0001] This invention relates to the field of reservoir stimulation technology, and is a reservoir stimulation method based on the determination of fracture extension effect. Background Technology

[0002] In the field of oil and gas field development, reservoir stimulation technology is widely used both domestically and internationally to develop reservoirs with poor permeability or improve the recovery rate of individual wells. Reservoir stimulation utilizes hydraulic action to artificially create one or more fractures in the reservoir, improving the flow of underground oil and gas channels and increasing the production of oil and gas wells. To achieve optimal oil and gas well productivity, it is necessary to control the extension of hydraulic fractures within the reservoir. However, with geological sedimentary structures, some reservoirs and interlayers have similar stresses and small stress differences. When the reservoir lacks an interlayer or, although it has an interlayer, its strength or thickness is insufficient, fractures may extend excessively vertically, wasting fracturing fluid and hindering the formation of sufficient fracture length. In such cases, it is necessary to control the fracture height extension as much as possible. Furthermore, in the later stages of oilfield development, the injection-production relationship becomes complex, and the position of the waterline front of the injection well is unclear. Conventional pressure stimulation, by forcing fractures along the original high-permeability channels, can lead to water flooding of the oil well. Therefore, in these situations, it is necessary to control the direction of the fracture plane during stimulation.

[0003] Chinese patent document CN 111980653 B discloses a method for controlling the direction of fracture fracturing based on alternating hot and cold rock fracturing. This method achieves directional fracturing of oil shale reservoirs through alternating hot and cold rock fracturing by injecting cryogenic fracturing fluid, solving the problem of being unable to control the direction of fracture propagation when using hydraulic fracturing technology for reservoir stimulation during in-situ oil shale mining. Chinese patent document CN 112228031 A discloses a fracturing method for controlling the direction of fracture propagation. This method involves perforating the target layer of the reservoir with a perforating gun; after perforation, a high-viscosity liquid is injected into the perforation for fracturing, followed by the injection of a combined proppant into the fracture, and then shutting in the well to wait for fracture closure. However, current technologies for controlling the direction of fracture propagation can only control the longitudinal extension of fractures and require extensive surface design or the use of large amounts of plugging agents. Existing technologies have limited longitudinal control capabilities and are costly, and cannot control the direction of planar fractures. Summary of the Invention

[0004] This invention provides a reservoir stimulation method based on fracture propagation effect determination, which overcomes the shortcomings of the prior art and can effectively solve the problem that existing reservoir stimulation methods cannot achieve fracture control and determination during the construction process.

[0005] The technical solution of this invention is achieved through the following measures: a reservoir stimulation method based on fracture propagation effect determination, comprising the following steps:

[0006] S1, Conduct pre-primary pressure formation tests to determine the optimal discharge rate for controlling hydraulic fracturing fractures;

[0007] S2, inject fracturing fluid into the formation at the optimal flow rate to control hydraulic fractures, and record the pressure when the system is stable;

[0008] S3, conduct displacement increase test and record the pressure when the system is stable;

[0009] S4. Based on the system pressure obtained in steps S2 and S3 when it is stable, calculate the discrimination coefficient and determine the specific construction discharge rate based on the discrimination coefficient.

[0010] The following are further optimizations and / or improvements to the above-mentioned technical solution:

[0011] In step S3 above, the discharge rate increase test involves increasing the discharge rate by 0.2 m based on the optimal discharge rate for controlling the hydraulic cracks. 3 / min to 0.5m 3 Inject fracturing fluid into the formation at a rate of / min.

[0012] The specific operation of S1 above is as follows:

[0013] S11, conduct the first formation test, injecting produced water from the oil wells in this block into the reservoir formation at a depth of 0.1m. 3 / min to 0.3m 3 Pumping begins at an initial injection rate of / min, with the injection rate increased by 0.1m every 10 to 20 minutes. 3 / min to 0.3m 3 / min, until half of the design discharge capacity is reached, record the change curve of formation pressure with pump discharge capacity during the first formation test, and record the highest construction pressure when the system is stable during the first formation test.

[0014] S12, stop the pump and observe the pressure drop for 15 to 30 minutes;

[0015] S13, conduct the second formation test, injecting produced water from the oil wells in this block into the reservoir formation. The initial injection rate will be half the designed flow rate, with the injection rate increased by 0.1 m³ / min every 10 to 20 minutes. 3 / min to 0.3m 3 / min, until the design discharge rate is reached, record the change curve of formation pressure with pump discharge rate during the second formation test, and record the highest construction pressure when the system is stable during the second formation test.

[0016] S14, stop the pump and observe the pressure drop for 15 to 30 minutes;

[0017] S15, determine the optimal discharge rate for controlling hydraulic fracturing fractures based on the occurrence of inflection points in the curve.

[0018] In step S4 above, the discriminant coefficient is calculated using the following formula:

[0019]

[0020] In the formula: C is the discriminant coefficient; K is the formation permeability, mD; ρ is the fracturing fluid density, kg / m³ 3 A1 is the friction coefficient of the first pump shutdown, dimensionless; A2 is the friction coefficient of the second pump shutdown, dimensionless; P1 is the pressure when the system stabilizes in step S2, MPa; P2 is the pressure when the system stabilizes in step S3, MPa; t1 is the time point corresponding to pressure P1 in step S2, min; t2 is the time point corresponding to pressure P2 in step S3, min; q1 is the preferred discharge rate for controlling the hydraulic crack in step S2, m. 3 / min; q2 is the increased displacement corresponding to step S3, m 3 / min; μ is the fracturing fluid viscosity, mPa·s; h is the reservoir thickness, m.

[0021] In step S4 above, the criterion for determining the specific construction discharge volume based on the discriminant coefficient is as follows:

[0022] If C≤0.3, it indicates that the fracture has extended sufficiently, and the optimal displacement q1 corresponding to the reservoir fracturing construction step S2 for controlling the hydraulic fracture should be used for construction.

[0023] If 0.3 < C < 0.7, it indicates that the crack extension is average, and construction should be carried out after increasing the drainage volume at q2.

[0024] If C ≥ 0.7, it indicates that the crack has not extended sufficiently, so the discharge rate should be increased by 0.2 m based on q2. 3 / min to 0.5m 3 / min, conduct a displacement increase test and recalculate the discrimination coefficient until C < 0.7;

[0025] When C≥0.7, during the displacement test operation, if the displacement is increased to the design limit and the bottom hole pressure value is approximately equal to or greater than the theoretical fracturing value of the formation, the design limit displacement shall be adopted for construction.

[0026] The friction coefficients A1 for the first pump shutdown and A2 for the second pump shutdown are calculated using the following formula:

[0027]

[0028]

[0029] In the formula: P pP is the nozzle pressure drop, MPa; H is the tubing insertion depth, m; t1 P represents the highest construction pressure within the displacement range corresponding to the stable displacement in step S11, in MPa; t2 P represents the highest construction pressure within the displacement range corresponding to the stable displacement in step S13, in MPa; s1 P is the instantaneous pump stop pressure in S12, expressed in MPa. s2 The instantaneous pump stop pressure in S14 is in MPa.

[0030] The theoretical fracturing values ​​for the above-mentioned formations are calculated using the following formula:

[0031] P f =3σ h -σ H -αP c +σ t Formula 4

[0032] In the formula: P f σ is the theoretical fracture pressure of the formation, MPa; h The minimum horizontal ground stress is given in MPa; σ H The maximum horizontal ground stress is expressed in MPa; P c σ is the formation pore pressure, MPa; α is the effective stress coefficient, dimensionless; σ t denoted as the tensile strength of the rock, in MPa.

[0033] This invention provides a reservoir stimulation method based on fracture extension effect assessment. It eliminates the need for additional fracture detection equipment. By assessing the fracture extension effect during construction and monitoring pressure fluctuations using small-volume stepped pumping, the degree of fracture propagation is determined, guiding on-site operations. This method is simple to implement, significantly reduces operating costs while ensuring precise control of fracture extension, and simultaneously improves fracture propagation to connect with oil-bearing formations, thereby increasing the utilization rate of single wells. Detailed Implementation

[0034] This invention is not limited to the following embodiments; specific implementation methods can be determined according to the technical solutions and actual conditions of this invention. Unless otherwise specified, the equipment and apparatus used in this invention are all existing, publicly known, and commonly used equipment and apparatus in the art.

[0035] The present invention will be further described below with reference to embodiments:

[0036] Example 1: The reservoir stimulation method based on fracture propagation effect is carried out according to the following steps:

[0037] S1, Conduct pre-primary pressure formation tests to determine the optimal discharge rate for controlling hydraulic fracturing fractures;

[0038] S2, inject fracturing fluid into the formation at the optimal flow rate to control hydraulic fractures, and record the pressure when the system is stable;

[0039] S3, conduct displacement increase test and record the pressure when the system is stable;

[0040] S4. Based on the system pressure obtained in steps S2 and S3 when it is stable, calculate the discrimination coefficient and determine the specific construction discharge rate based on the discrimination coefficient.

[0041] Example 2: As an optimization of the above example, in step S3, the discharge rate test operation is to increase the discharge rate by 0.2m based on the optimal discharge rate for controlling the hydraulic cracks. 3 / min to 0.5m 3 Inject fracturing fluid into the formation at a rate of / min.

[0042] Example 3: As an optimization of the above example, the specific operation of S1 is as follows:

[0043] S11, conduct the first formation test, injecting produced water from the oil wells in this block into the reservoir formation at a depth of 0.1m. 3 / min to 0.3m 3 Pumping begins at an initial injection rate of / min, with the injection rate increased by 0.1m every 10 to 20 minutes. 3 / min to 0.3m 3 / min, until half of the design discharge capacity is reached, record the change curve of formation pressure with pump discharge capacity during the first formation test, and record the highest construction pressure when the system is stable during the first formation test.

[0044] S12, stop the pump and observe the pressure drop for 15 to 30 minutes;

[0045] S13, conduct the second formation test, injecting produced water from the oil wells in this block into the reservoir formation. The initial injection rate will be half the designed flow rate, with the injection rate increased by 0.1 m³ / min every 10 to 20 minutes. 3 / min to 0.3m 3 / min, until the design discharge rate is reached, record the change curve of formation pressure with pump discharge rate during the second formation test, and record the highest construction pressure when the system is stable during the second formation test.

[0046] S14, stop the pump and observe the pressure drop for 15 to 30 minutes;

[0047] S15, determine the optimal discharge rate for controlling hydraulic fracturing fractures based on the occurrence of inflection points in the curve.

[0048] In this invention, if the change curves obtained from the first and second formation tests both show an inflection point, the pump injection rate corresponding to that inflection point is the preferred rate for controlling hydraulic fracturing fractures. If both the first and second formation tests show inflection points, and the pressure drop rates in steps S12 and S14 are not significantly different, then the pump injection rate corresponding to the inflection point in one of the test curves is selected as the preferred rate for controlling hydraulic fracturing fractures based on geological requirements. When the change curves of formation pressure with pump injection rate show an inflection point in both formation tests, it indicates that the produced water has created significant new fractures in the formation at that rate. According to common sense in fracturing operations, the higher the rate, the larger the fractures produced should be. Based on the geological requirements of well stimulation, if it is necessary to control the fracture size, the pump injection rate corresponding to the inflection point in the change curve during the first test should be selected as the preferred rate for controlling hydraulic fracturing fractures. If it is necessary to expand the fracture stimulation scale, the pump injection rate corresponding to the inflection point in the change curve during the second test should be selected as the preferred rate for controlling hydraulic fracturing fractures. Both inflection points indicate that the fracturing test produced new fractures. The fracture size and the fracturing displacement are positively correlated. If it is necessary to control the fracturing scale (fracture length, width, and height), the fracturing operation should be carried out using the displacement corresponding to a smaller inflection point obtained from the test. Adjustments should be made based on the control during the later stages of the operation. If a larger scale is required, the fracturing operation should be carried out using the displacement corresponding to a larger inflection point obtained from the test. If the pressure drop rate after the second formation test is significantly greater than that after the first formation test, it indicates that within the design displacement range, the fracture size produced by the first and second tests differs significantly. The original design displacement range needs to be optimized, and the displacement range needs to be redefined based on geological requirements. If it is necessary to control the fracturing scale modification (fracture length, width, and height), the design displacement range should be reduced. If it is necessary to modify the scale, the design displacement range should be increased. In this case, the design scheme should be reconsidered, and the test should be repeated after optimizing the fracturing displacement.

[0049] Example 4: As an optimization of the above embodiment, in step S4, the discrimination coefficient is calculated by the following formula:

[0050]

[0051] In the formula:

[0052] C is the discriminant coefficient;

[0053] K is the formation permeability (obtained from the fracturing geological scheme), mD;

[0054] ρ is the density of the fracturing fluid, kg / m³ 3 ;

[0055] A1 is the friction coefficient during the first pump stop, which is dimensionless;

[0056] A2 is the friction coefficient during the second pump stoppage, which is dimensionless;

[0057] P1 is the pressure when the system is stable in step S2, in MPa;

[0058] P2 is the pressure when the system is stable in step S3, in MPa;

[0059] t1 is the time point corresponding to pressure P1 in step S2, in minutes;

[0060] t2 is the time point corresponding to pressure P2 in step S3, in minutes;

[0061] q1 is the preferred discharge rate for controlling the hydraulic fracture in step S2, m 3 / min;

[0062] q2 represents the increased displacement in step S3, m 3 / min;

[0063] μ is the viscosity of the fracturing fluid, mPa·s;

[0064] h is the reservoir thickness, in meters (m).

[0065] Example 5: As an optimization of the above embodiment, in step S4, the criterion for determining the specific construction discharge volume based on the discriminant coefficient is as follows:

[0066] If C≤0.3, it indicates that the fracture has extended sufficiently, and the optimal displacement q1 corresponding to the reservoir fracturing construction step S2 for controlling the hydraulic fracture should be used for construction.

[0067] If 0.3 < C < 0.7, it indicates that the crack extension is average, and construction should be carried out after increasing the drainage volume at q2.

[0068] If C ≥ 0.7, it indicates that the crack has not extended sufficiently, so the discharge rate should be increased by 0.2 m based on q2. 3 / min to 0.5m 3 / min, conduct a displacement increase test and recalculate the discrimination coefficient until C < 0.7;

[0069] When C≥0.7, during the displacement test operation, if the displacement is increased to the design limit and the bottom hole pressure value is approximately equal to or greater than the theoretical fracturing value of the formation, the design limit displacement shall be adopted for construction.

[0070] The bottom hole pressure value is calculated as follows: Bottom hole pressure value = wellhead pump pressure during construction + pressure generated by the liquid column in the tubing - frictional resistance of the fracturing liquid tubing and surface pipelines - nozzle pressure drop.

[0071] In this invention, when C≥0.7, if the discharge rate is increased to the design limit during the discharge rate test and the bottom hole pressure is much smaller than the fracture pressure, the design scheme can be changed, and the design discharge rate and pressure parameters can be re-optimized before construction.

[0072] Example 6: As an optimization of the above example, the friction coefficient A1 of the first pump shutdown and the friction coefficient A2 of the second pump shutdown are calculated by the following formula:

[0073]

[0074]

[0075] In the formula: P p P is the nozzle pressure drop, MPa; H is the tubing insertion depth, m; t1 P represents the highest construction pressure within the displacement range corresponding to the stable displacement in step S11, in MPa; t2 P represents the highest construction pressure within the displacement range corresponding to the stable displacement in step S13, in MPa; s1 P is the instantaneous pump stop pressure in S12, expressed in MPa. s2 The instantaneous pump stop pressure in S14 is MPa. The nozzle pressure drop is the nozzle pressure drop of the directional hydraulic spray gun used during the modification process, and the tubing insertion depth is the insertion depth of the fracturing fluid injection tubing.

[0076] Example 7: As an optimization of the above examples, the theoretical fracturing value of the formation is calculated by the following formula:

[0077] P f =3σ h -σ H -αP c +σ t Formula 4

[0078] In the formula: P f σ is the theoretical fracture pressure of the formation, MPa; h The minimum horizontal ground stress is given in MPa; σ H The maximum horizontal ground stress is expressed in MPa; P c σ is the formation pore pressure, MPa; α is the effective stress coefficient, dimensionless; σ t The tensile strength of the rock is given in MPa. The theoretical fracturing pressure, minimum horizontal stress, maximum horizontal stress, formation pore pressure, effective stress coefficient, and tensile strength of the rock can all be obtained from fracturing geological design or block development plan.

[0079] Example 8: Taking the fracturing operation of the Chepaizi oilfield reservoir in Karamay, Xinjiang as an example:

[0080] S1, conduct pre-primary pressure formation tests to determine the optimal discharge rate for controlling hydraulic fracturing fractures.

[0081] S11, conduct the first formation test, injecting produced water from the oil wells in this block into the reservoir formation at a depth of 0.25m. 3 Pumping was initiated at an initial injection rate of / min, with the injection rate increased by 0.25m³ every 15 minutes. 3 / min, until half of the design displacement limit of 1.25m 3 / min, record the curve of formation pressure change with pump discharge rate during the first formation test;

[0082] S12, stop the pump and observe the pressure drop for 15 to 30 minutes;

[0083] S13, conduct the second formation test, injecting produced water from the oil wells in this block into the reservoir formation at the design discharge limit (2.5m). 3 Half of ( / min) (i.e., 1.25m) 3 Pumping was initiated at an initial injection rate of ( / min), with the injection rate increased by 0.25 m³ / min every 15 minutes. 3 / min, the displacement step increases from half of the upper limit of the design displacement to the upper limit of the design displacement (2.5m). 3 / min), record the curve of formation pressure change with pump discharge rate during the second formation test.

[0084] S14, stop the pump and observe the pressure drop for 15 to 30 minutes;

[0085] S15. Determine the optimal displacement for controlling hydraulic fracturing fractures based on the occurrence of inflection points in the curve: An inflection point appears in the first formation test curve, corresponding to a displacement of 1.0 m³ / s. 3 / min, corresponding to a maximum construction pressure of 20.5MPa within the interval; the second formation test curve shows two inflection points, corresponding to a displacement of 1.5m³ / min. 3 / min and 2.25m 3 The corresponding maximum construction pressures within the intervals were 29.8 MPa and 40.6 MPa, respectively, and the formation pressure drop rates were not significantly different between the two tests. Based on the geological requirements of this well (the need for expanded stimulation), a depth of 2.25m was selected during the second test. 3 / min represents the optimal construction discharge rate.

[0086] S2, with a displacement of 2.25m 3 The system injects fracturing fluid into the formation at a rate of / min, and records the pressure when the system is stable at 41.5MPa.

[0087] S3, with a displacement of 2.25m 3 Increase the displacement to 2.5m based on the previous / min.3 / min, conduct the discharge rate increase test, and record the system pressure when it stabilizes after the discharge rate increase as 48.0MPa.

[0088] S4, calculate the discrimination coefficient, and determine the specific construction discharge volume based on the discrimination coefficient.

[0089] In step S1 of this embodiment, the corresponding test data recorded are as follows: P p The values ​​are 1.67 / 10.25, MPa, H is 1200m, and P t1 24.5MPa, P t2 44.5 MPa, P s1 16.5MPa, P s2 Substituting the above data into equations 2 and 3, we obtain the friction coefficient A1 for the first pump stoppage as 0.54 and the friction coefficient A2 for the second pump stoppage as 1.38.

[0090] The corresponding data in steps S2 and S3 are as follows: P1 = 41.5 MPa, P2 = 48.0 MPa, t1 = 42.0 min, t2 = 49.0 min, and q1 = 2.25 m. 3 / min, q2 is 2.5m 3 / min, K is 27.5mD (obtained from the fracturing geological scheme), and the fracturing fluid density ρ is 1000kg / m 3 Given a fracturing fluid viscosity μ of 50 mPa·s and a reservoir thickness h of 1.5 m, the discrimination coefficient C calculated according to Equation 1 above is 0.345 in this embodiment. Therefore, a displacement rate of 2.5 m³ / s after increasing the displacement rate can be used. 3 / min construction. With this displacement, the initial stage of construction can effectively break up the formation and artificially fracture the effective rock. The subsequent sand addition is smooth, and the construction parameters can be adjusted in a timely manner to ensure low-cost and high-efficiency fracturing.

[0091] The method of this invention has been successfully applied in 176 wells in the region, with 125 wells showing effectiveness. On average, each well has increased crude oil production by 1.4 t / d, resulting in a total increase of 6.3 × 10⁻⁶ t / d. 4 Compared to traditional methods, this method eliminates the need for additional testing equipment costs. Furthermore, the small-displacement, precise control of fracture propagation in reservoir stimulation reduces energy consumption and equipment costs, thus achieving the goal of improving quality and efficiency.

[0092] This invention provides a reservoir stimulation method based on fracture extension effect assessment. It eliminates the need for additional fracture detection equipment. By assessing the fracture extension effect during construction and monitoring pressure fluctuations using small-volume stepped pumping, the degree of fracture propagation is determined, guiding on-site operations. This method is simple to implement, significantly reduces operating costs while ensuring precise control of fracture extension, and simultaneously improves fracture propagation to connect with oil-bearing formations, thereby increasing the utilization rate of single wells.

[0093] The above technical features constitute the embodiments of the present invention, which have strong adaptability and implementation effect. Unnecessary technical features can be added or removed according to actual needs to meet the needs of different situations.

Claims

1. A reservoir stimulation method based on fracture propagation effect determination, characterized in that... Follow these steps: S1, Conduct pre-primary pressure formation tests to determine the optimal discharge rate for controlling hydraulic fracturing fractures; S2, inject fracturing fluid into the formation at the optimal flow rate to control the hydraulic fracturing fractures, and record the pressure when the system is stable; S3, conduct displacement increase test and record the pressure when the system is stable; S4. Based on the system pressure obtained in steps S2 and S3 when it is stable, calculate the discrimination coefficient and determine the specific construction discharge rate based on the discrimination coefficient. The discriminant coefficient is calculated using the following formula: In the formula: C is the discriminant coefficient; K is the formation permeability, mD; ρ is the fracturing fluid density, kg / m³ 3 A1 is the friction coefficient of the first pump shutdown, dimensionless; A2 is the friction coefficient of the second pump shutdown, dimensionless; P1 is the pressure when the system stabilizes in step S2, MPa; P2 is the pressure when the system stabilizes in step S3, MPa; t1 is the time point corresponding to pressure P1 in step S2, min; t2 is the time point corresponding to pressure P2 in step S3, min; q1 is the preferred discharge rate for controlling hydraulic fracturing fractures in step S2, m. 3 / min; q2 is the increased displacement corresponding to step S3, m 3 / min; μ is the fracturing fluid viscosity, mPa·s; h is the reservoir thickness, m; The criterion for determining the specific construction discharge volume based on the discriminant coefficient is as follows: If C≤0.3, it indicates that the fracture has extended sufficiently, and the optimal displacement q1 corresponding to the reservoir fracturing construction step S2 for controlling the hydraulic fracturing fracture should be used for construction. If 0.3 < C < 0.7, it indicates that the crack extension is average, and construction should be carried out after increasing the drainage volume at q2. If C ≥ 0.7, it indicates that the crack has not extended sufficiently, so the discharge rate should be increased by 0.2 m based on q2. 3 / min to 0.5m 3 / min, conduct a displacement increase test and recalculate the discrimination coefficient until C < 0.7; When C≥0.7, during the displacement test operation, if the displacement is increased to the upper limit of the design displacement and the bottom hole pressure value is equal to or greater than the theoretical fracturing value of the formation, the upper limit of the design displacement shall be adopted for construction.

2. The reservoir stimulation method based on fracture propagation effect determination according to claim 1, characterized in that... In step S3, the increased displacement test involves increasing the displacement by 0.2 m³ / s based on the optimal displacement for controlling the hydraulic fracturing fractures. 3 / min to 0.5m 3 Inject fracturing fluid into the formation at a rate of / min.

3. The reservoir stimulation method based on fracture propagation effect determination according to claim 1 or 2, characterized in that... The specific operation of step S1 is as follows: S11, conduct the first formation test, injecting produced water from the oil wells in this block into the reservoir formation at a depth of 0.1m. 3 / min to 0.3m 3 Pumping begins at an initial injection rate of / min, with the injection rate increased by 0.1m every 10 to 20 minutes. 3 / min to 0.3m 3 / min, until half of the design discharge capacity is reached, record the change curve of formation pressure with pump discharge capacity during the first formation test, and record the highest construction pressure when the system is stable during the first formation test. S12, stop the pump and observe the pressure drop for 15 to 30 minutes; S13, conduct the second formation test, injecting produced water from the oil wells in this block into the reservoir formation. The initial injection rate will be half the designed flow rate, with the injection rate increased by 0.1 m³ / min every 10 to 20 minutes. 3 / min to 0.3m 3 / min, until the design discharge rate is reached, record the change curve of formation pressure with pump discharge rate during the second formation test, and record the highest construction pressure when the system is stable during the second formation test. S14, stop the pump and observe the pressure drop for 15 to 30 minutes; S15, determine the optimal discharge rate for controlling hydraulic fracturing fractures based on the occurrence of inflection points in the curve.

4. The reservoir stimulation method based on fracture propagation effect determination according to claim 1, characterized in that... The friction coefficients A1 for the first pump shutdown and A2 for the second pump shutdown are calculated using the following formula: In the formula: P p P is the nozzle pressure drop, MPa; H is the tubing insertion depth, m; t1 The maximum construction pressure (MPa) corresponding to the system stability condition in step S11; P t2 The maximum construction pressure (MPa) corresponding to the system stability condition in step S13; P s1 P is the instantaneous pump stop pressure in S12, expressed in MPa. s2 The instantaneous pump stop pressure in S14 is in MPa.

5. The reservoir stimulation method based on fracture propagation effect determination according to claim 1, characterized in that... The theoretical fracturing value of the formation is calculated by the following formula: In the formula: P f σ represents the theoretical fracturing value of the formation, in MPa; h The minimum horizontal ground stress is given in MPa; σ H The maximum horizontal ground stress is expressed in MPa; P c σ is the formation pore pressure, MPa; α is the effective stress coefficient, dimensionless; σ t denoted as the tensile strength of the rock, in MPa.

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