A bidirectional coupled pressure-driven injection-production development method

Abstract

This invention discloses a bidirectional coupled pressure-driven injection-production development method, relating to the field of oil production technology. The method includes the following steps: Step 1, selecting a suitable development well area for coordinated injection and production; Step 2, determining the optimal injection volume and injection rate for water well pressure-driven injection; Step 3, determining the optimal injection volume and huff-and-puff design for high-pressure expansion in production wells; Step 4, implementing coordinated injection and production, establishing an effective balanced displacement relationship. This bidirectional coupled pressure-driven injection-production development method, on the one hand, implements slug-type pressure-driven water injection at the injection end to achieve the goals of increased injection, displacement, and wave expansion; simultaneously, on the other hand, it synchronously and synergistically implements high-pressure expansion huff-and-puff with active water at the production end to achieve synergistic expansion, energy replenishment, increased permeability, and improved oil washing efficiency and seepage capacity, preventing water channeling in the pressure drop funnel, and avoiding the surge of pressure-driven injected water along the principal stress direction and the direction of historical displacement strength, as well as fracture channeling.

Description

Technical Field

[0001] This invention relates to the field of low-permeability reservoir development technology, specifically a two-way coupled pressure-driven injection-production development method. Background Technology

[0002] In the development of low-permeability reservoirs by water injection, the conventional water injection method is less effective due to severe heterogeneity in both the horizontal and vertical directions. The high water injection pressure and difficulty in water injection result in low formation pressure, low oil production rate, recovery rate and degree of recovery, and severe dynamic heterogeneity in the reservoir pressure field and saturation field.

[0003] Water well pressure drive development is constrained by factors such as poor reservoir properties, strong static and dynamic heterogeneity, and irregular well patterns and spacing. Artificially constructing a high-pressure system consumes a large amount of water, has a long injection cycle, and has poor economic benefits. In non-mainstream directions, the formation pressure recovery speed of oil wells is low and it is difficult to achieve results. The production capacity increase of oil wells is lower than expected. Water channeling is very likely to occur in the mainstream and advantageous channels, and the development effect cannot be effectively improved.

[0004] In addition, when developing low-permeability reservoirs, the primary recovery rate is low when using long-section horizontal well dense cutting and segmented fracturing elastic development. After switching to water drive (pressure drive) development mode, water channeling is serious and the effect is still poor due to the influence of stress direction, well network, well spacing and fracturing mode.

[0005] Given the characteristics and development challenges of this type of reservoir, simply implementing pressure-driven water injection development cannot solve the serious problems of comprehensive effectiveness of oil wells and water channeling. Traditional methods such as water shut-off and profile control or injection-production coupling of oil wells cannot completely solve the problem. In order to improve the recovery rate and achieve efficient reservoir development, it is urgent to explore new and effective development models. Summary of the Invention

[0006] To address the shortcomings of existing technologies, this invention provides a bidirectional coupled pressure-driven injection and production development method, which solves the problems of severe water channeling and poor performance in water-driven and pressure-driven systems.

[0007] To achieve the above objectives, the present invention provides the following technical solution: a bidirectional coupled pressure-driven injection-production development method, comprising the following steps:

[0008] Step 1: Select a suitable development well area for implementing combined injection and production;

[0009] Step 2: Determine the optimal injection volume and injection rate for water well pressure-driven water injection;

[0010] Step 3: Determine the optimal injection rate and huff / puff design for high-pressure expansion huff / puff in the oil well;

[0011] Step four: Implement coordinated displacement and injection production, and establish an effective and balanced displacement relationship.

[0012] Furthermore, in step one, based on the location, structural characteristics, oil layer characteristics, production level, and current development well network of the reservoir, sand bodies with relatively closed boundaries are selected, and the target development well area is determined by combining the dynamic effect of the oil wells in the well group.

[0013] Furthermore, in step two, using the material balance method, and considering the differences in sealing properties, sand body thickness, porosity, and oil-bearing area of ​​each sand layer group in the development well area, the water well forward pressure drive injection rate is designed differently based on various production conditions. The method for calculating the water well forward pressure drive injection rate is as follows:

[0014] Where Q is the water injection volume driven by water pressure. S is the porosity of the oil layer; S is the oil-bearing area; H is the sand body thickness; η is the sealing coefficient. The pressure difference before and after water injection in the reservoir; Ct is the comprehensive compressibility coefficient;

[0015] Ct=Co So+Cw Sw+CP, where So is the oil saturation; Sw is the water saturation; Co is the crude oil compressibility coefficient; Cw is the formation water compressibility coefficient; and CP is the rock pore compressibility coefficient.

[0016] Furthermore, in step three, the injection volume of the high-pressure expansion and injection of the oil well is determined by considering the oil well's production status and the formation deficit status.

[0017] Calculate using the following formula:

[0018] ;

[0019] Where V is the reverse pressure drive injection fluid volume; This represents the percentage of the corresponding layer thickness. To accumulate the amount of oil produced; To accumulate the extracted water volume; Density of crude oil; Density of formation water; Ct is the crude oil volume coefficient; Ct is the overall compressibility coefficient. This represents the formation deficit.

[0020] Furthermore, in step three, the high-pressure expansion of the oil well is carried out by adding active water with a total concentration of 0.2% permeate agent. During the injection process, a segmented plug variable concentration injection method is adopted, with the variable concentration being high at the beginning and low at the end.

[0021] When there is a dominant seepage channel formed by fracturing in the corresponding formation of the oil well, a temporary plugging agent is intermittently added during the high-pressure expansion and injection process of the oil well.

[0022] Furthermore, the oil well is provided with a technical casing, an intermediate pipe and a tubing in sequence from the outside to the inside. Packers are provided between the technical casing and the intermediate pipe, and at the top and bottom of any oil layer. A distribution mechanism is provided between two adjacent packers.

[0023] The distribution mechanism includes:

[0024] The distribution shell is connected to the middle tube by threads at its upper and lower ends.

[0025] An active water drain hole is radially opened near the upper part of the distribution shell. An active water opening and closing component is provided on the side wall of the distribution shell. The active water opening and closing component is used to control the opening and closing of the active water drain hole. Active water reaches the active water drain hole from the annulus between the oil pipe and the intermediate pipe.

[0026] The distribution cylinder is located inside the distribution housing. The upper and lower ends of the distribution cylinder are connected to the oil pipe by threads. The distribution cylinder is equipped with a formation fluid inlet pipe and a temporary plugging agent drain pipe arranged side by side. The formation fluid inlet pipe is equipped with a one-way valve that allows formation fluid to enter the distribution cylinder. An oil inlet sleeve is provided radially from the outside of the distribution housing to the formation fluid inlet pipe, and a drain sleeve is provided radially from the outside of the distribution housing to the temporary plugging agent drain pipe.

[0027] A mixing component, located on a distribution cylinder, is used to control the opening of the formation fluid inlet pipe or the temporary plugging agent outlet pipe.

[0028] Furthermore, the dispensing component includes:

[0029] The first baffle ring is located inside the distribution cylinder and can completely cover the formation fluid inlet pipe or the temporary plugging agent outlet pipe.

[0030] The rotating component includes a threaded cylinder threaded to the inner wall of a retaining ring, a hollowed-out portion two located at the lower end of the threaded cylinder, and a rotating cylinder located at the lower end of the hollowed-out portion two.

[0031] Intelligent drive structure one, which is installed on the distribution cylinder and is used to drive the rotating cylinder to rotate.

[0032] Furthermore, both the upper and lower ends of the rotating cylinder are provided with sealing edges, which seal against the distribution cylinder;

[0033] The outer circumference of the rotating cylinder is provided with a groove ring in the middle. The intelligent drive structure includes a helical tooth provided on the groove ring, a worm gear meshing on one side of the helical tooth, and a sealed motor installed on the distribution housing for driving the worm gear to rotate.

[0034] Furthermore, the active water opening and closing component includes a second retaining ring, which is axially and radially limited to a plane inside the distribution housing that is at the same height as the active water drain hole. A through hole is opened on the area of ​​the second retaining ring opposite to the active water drain hole. An intelligent drive structure second for controlling the angle required for the rotation of the second retaining ring is also installed inside the distribution housing.

[0035] The intelligent drive structure two includes a toothed part disposed on the inner wall of the retaining ring two, which avoids the through hole, a gear meshing on one side of the toothed part, and a sealed motor two installed in the distribution housing for controlling the rotation of the gear.

[0036] Furthermore, the wellhead of the oil well has an active water supply system that communicates with the annulus between the tubing and the intermediate pipe;

[0037] The wellhead of the oil well is equipped with a temporary plugging agent supply system that is connected to the tubing;

[0038] The wellhead of the oil well has a pipe that connects to the formation fluid delivery system;

[0039] The active water supply system, the temporary plugging agent supply system, and pipelines are integrated on the wellhead.

[0040] The present invention has the following beneficial effects:

[0041] (1) This bidirectional coupled pressure-driven injection-production development method implements slug-type pressure-driven water injection at the injection end to achieve the goals of increasing injection, building up displacement, and expanding wave coverage; at the same time, it simultaneously and collaboratively implements high-pressure expansion and spitting of active water at the production end to achieve synergistic expansion, energy replenishment, permeability enhancement, and improved oil washing efficiency and permeation capacity, thereby improving the oil washing efficiency at the production well end, balancing the pressure field, preventing water channeling in the pressure drop funnel, and avoiding the surge of pressure-driven injected water along the principal stress direction and the direction of historical displacement strength, as well as fracture channeling. Compared with pressure-driven development and group injection-spitting development methods, the combined development of displacement and spitting can establish a better and more balanced displacement relationship, improve the formation energy and production capacity of the oil well, reduce water consumption, increase the production capacity of the oil well by 30%, increase the oil well efficiency to 100%, and further increase the recovery rate by 5%-10%. Numerical simulation and stress simulation studies show that the combined development of displacement and spitting can achieve relative (flow field) equilibrium effect, change the pressure field, and further improve the production capacity of a single well.

[0042] (2) This bidirectional coupling pressure-driven injection-production development method strictly isolates different oil layers through a combination of a three-layer concentric tubing structure (technical casing, intermediate tubing, and oil tubing) and interlayer packers. Each oil layer is equipped with an independent distribution mechanism, which integrates an active water injection channel, a temporary plugging agent injection channel, and a formation fluid production channel. The independent opening, closing, and switching of each channel can be achieved through intelligent drive components. This allows a single oil well to simultaneously or alternately perform active water injection, temporary plugging agent injection, and crude oil production according to the different needs of each oil layer (such as low-permeability layers requiring energy replenishment and high-permeability layers requiring temporary plugging) without changing the wellbore structure, thus realizing a multi-functional intensive operation mode for a single well.

[0043] (3) This bidirectional coupled pressure-driven injection-production development method, through precise control of the distribution components, ensures that the temporary plugging agent is discharged only from the temporary plugging agent drain pipe of the target oil layer, while simultaneously closing the active water channel of that layer. This achieves "point-to-point" directional injection of the temporary plugging agent. When a temporary plugging operation is performed on a certain layer, the active water opening and closing components of other layers are kept open, allowing for continued injection of active water into other layers. This achieves coordinated operation of plugging one layer and injecting multiple layers, ensuring uninterrupted overall energy replenishment. This coordinated plugging and injection mode allows for simultaneous formation energy replenishment and high-permeability channel sealing, enabling the faster establishment of an effective equilibrium displacement pressure system. This forces subsequent injected fluids to be directed towards unused low-permeability areas, thereby significantly improving the overall reservoir utilization and oil recovery rate.

[0044] (4) This bidirectional coupling pressure-driven injection-production development method requires traditional fluid replacement operations involving ground pump shutdown and process switching, which is time-consuming and labor-intensive. This invention controls the intelligent drive structure one and intelligent drive structure two via ground commands to drive the downhole distribution component and active water on / off component, thus enabling the switching between three working modes: active water injection, temporary plugging agent injection, and oil production. No pump shutdown or tubing string tripping is required, significantly reducing non-productive time. Especially during multiple rounds of temporary plugging (e.g., 2-3 times per well), it is estimated that 1-2 days of operation time can be saved, increasing operational efficiency by more than 30%.

[0045] Of course, any product implementing this invention does not necessarily need to achieve all of the advantages described above at the same time. Attached Figure Description

[0046] Figure 1 This is a process flow diagram of the present invention;

[0047] Figure 2 This is a schematic diagram illustrating the calculation of forward pressure drive water volume using the material balance method of this invention.

[0048] Figure 3 This invention relates to the saturation field of pressure-driven water wells without inrush and outflow in oil wells.

[0049] Figure 4This invention relates to the saturation field of oil well synergistic throughput expansion water well pressure drive;

[0050] Figure 5 This invention is a schematic diagram of the coordinated development of the oilfield in the Karamay S5 Formation of the X35 well area in the western oilfield.

[0051] Figure 6 This invention provides a histogram of the permeability distribution in the S5 pore of the Karamay Formation in the X35 well area of ​​the Western Oilfield.

[0052] Figure 7 This is a schematic diagram showing the location of the distribution mechanism of the present invention within the oil well;

[0053] Figure 8 This is a schematic diagram of the distribution mechanism of the present invention;

[0054] Figure 9 This is a cross-sectional view of the dispensing housing 3 in the dispensing mechanism of the present invention;

[0055] Figure 10 For the present invention Figure 9 A schematic diagram of the structure of the distribution cylinder with a central section;

[0056] Figure 11 For the present invention Figure 10 A three-dimensional image;

[0057] Figure 12 This is a schematic diagram of the structure of the active water opening and closing component of the present invention;

[0058] Figure 13 This is a cross-sectional view of the dispensing cylinder of the present invention;

[0059] Figure 14 For the present invention Figure 13 A three-dimensional image;

[0060] Figure 15 This is an external view of the dispensing cylinder of the present invention;

[0061] Figure 16 For the present invention Figure 15 A schematic diagram showing the detachment of the inlet sleeve and the outlet sleeve from the distribution cylinder;

[0062] Figure 17 This is a three-dimensional cross-sectional view of the dispensing cylinder of the present invention;

[0063] Figure 18 This is a schematic diagram of the structure of the mixing component of the present invention.

[0064] In the diagram, 1. Tubing; 2. Intermediate tube; 3. Distribution shell; 31. Upper short section; 32. Middle short section; 33. Lower short section; 4. Inner distribution cylinder structure; 41. Distribution cylinder; 42. Formation fluid inlet pipe; 43. Oil inlet sleeve; 44. Drainage sleeve; 45. Temporary plugging agent drain pipe; 5. Mixing assembly; 51. Retaining ring one; 52. Threaded cylinder; 53. Hollowed-out section two; 54. Rotating cylinder; 541. Sealing edge; 542. Groove ring; 55. Intelligent drive structure one; 551. Helical gear; 552. Worm gear; 553. Sealing motor one; 6. Active water opening and closing assembly; 61. Retaining ring two; 611. Through hole; 62. Intelligent drive structure two; 621. Sealing motor two; 622. Gear; 623. Tooth section; 7. Active water drain hole; 8. Technical casing; 9. Packer. Detailed Implementation

[0065] 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. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0066] In the description of this invention, it should be understood that the terms "opening", "upper", "lower", "thickness", "top", "middle", "length", "inner", "around", etc., which indicate orientation or positional relationship, are only for the convenience of describing this invention and simplifying the description, and do not indicate or imply that the components or elements referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as limiting this invention.

[0067] The following is based on Figures 1-18 This invention describes a bidirectional coupled pressure-driven injection and production development method provided by an embodiment of the present invention.

[0068] Please refer to Figure 1 This invention provides a bidirectional coupled pressure-driven injection-production development method, comprising the following steps:

[0069] Step 1: Select a suitable development well area for implementing combined injection and production;

[0070] Step 2: Determine the optimal injection volume and injection rate for water well pressure-driven water injection;

[0071] Step 3: Determine the optimal injection rate and huff / puff design for high-pressure expansion huff / puff in the oil well;

[0072] Step four: Implement coordinated displacement and injection production, and establish an effective and balanced displacement relationship.

[0073] Preferably, in step one, based on the location, structural characteristics, reservoir characteristics, recovery level, and current development well network of the reservoir, sand bodies with relatively closed boundaries are selected, and the target development well area is determined by combining the dynamic effects of the production wells within the well group. General standards are as follows:

[0074] ①The oil reservoir connectivity rate is greater than 60%;

[0075] ②The reservoir is a porous reservoir with underdeveloped fractures;

[0076] ③ The oil reservoir's physical properties and permeability are greater than 1.0 × 10⁻⁶. -3 μm 2 (Low-permeability and ultra-low-permeability reservoirs);

[0077] ④ The oil layer to gross weight ratio is greater than 0.7;

[0078] ⑤ The well was not fracturing or was fracturing on a small scale;

[0079] ⑥ The distance between injection and production wells is greater than 150m.

[0080] Preferably, in step two, the method for determining the optimal injection rate of water in water well pressure drive includes: the changes in the volume of oil, gas, and water in the reservoir always follow the material balance equation; the material balance method is used to calculate the forward pressure drive water volume, referring to... Figure 2 As shown.

[0081] In step two, using the material balance method, and considering the differences in sealing properties, sand body thickness, porosity, and oil-bearing area of ​​each sand layer group in the well group of the scheme area, the water well forward pressure drive injection rate is designed differently based on various production conditions. The method for calculating the water well forward pressure drive injection rate is as follows: Where Q is the water injection volume of the water pressure drive, in m3; η is the porosity of the oil layer, in %; S is the oil-bearing area, in m2; H is the sand body thickness, in m; η is the sealing coefficient. The pressure difference before and after water injection in the reservoir is expressed in MPa; Ct is the comprehensive compressibility coefficient, expressed in MPa. -1 ;

[0082] Ct=Co So+Cw Sw+CP, where So is the oil saturation; Sw is the water saturation (in %); and Co is the crude oil compressibility coefficient (in MPa). -1 Cw is the formation water compressibility coefficient, in MPa. -1 CP is the rock porosity compressibility coefficient, in MPa. -1 .

[0083] In step two, considering factors such as basin differences (compressional arching / tensional-fault depression), stress transmission (rock physical properties), compaction degree, pore throat type and structural dip angle, oil-gas ratio, and formation degassing, the calculated water injection ratio can be adjusted by 10%-20%. To promote water flow from fractures to pores and prevent fracture channeling, multi-segment injection is adopted, generally using a 3+1 segment injection, with each segment spaced 5-7 days apart. Based on fracturing simulation software, the injection rate and displacement are optimized and determined according to the well spacing.

[0084] Preferably, in step three, the optimal injection volume for high-pressure expansion and injection of the oil well should comprehensively consider factors such as the oil well's production status and formation deficit. Based on multiple simulation results and understanding, the injection volume should be designed to be approximately 130% of the production volume of the corresponding layer in the oil and water wells; specifically, it should be calculated according to the following formula:

[0085] ;

[0086] Where V is the reverse pressure drive injection fluid volume, in m³. 3 ; This represents the percentage of the corresponding layer thickness, in % . Cumulative oil recovery is expressed in kg. Cumulative water extraction volume, in kg; Crude oil density, in kg / m³ 3 ; This refers to the density of formation water, expressed in kg / m³. 3 ; Ct is the crude oil volume coefficient; Ct is the comprehensive compressibility coefficient, in MPa. -1 ; This represents the formation void difference, expressed in MPa.

[0087] To improve the efficiency of oil-water percolation and replacement, high-pressure expansion of oil wells involves adding activated water with an average total concentration of 0.2% percolating agent. The percolating agent must be formation water with an oil-water interfacial tension of less than 10⁻³ nN / m and an oil washing efficiency greater than 30%. During injection, a segmented, variable-concentration injection method (high concentration at the beginning, low concentration at the end) is adopted. The injection rate is determined based on the reservoir properties and the scale of fracturing stimulation, generally ranging from 1.0 to 2.0 m. 3 / min.

[0088] To address the issue of uneven flow profiles in oil wells (horizontal wells) caused by fracturing, specifically when dominant flow channels exist in corresponding formations due to fracturing, a temporary plugging agent is intermittently added during the high-pressure expansion and injection process of the oil well. This aims to limit flow to easily accessible fluid zones, divert flow, and prevent excessive injection into individual zones. High-strength, water-soluble plugging rope knots can be used as the plugging material, with 2-3 plugging applications per well.

[0089] In step four, water wells are used to implement pressure-driven water injection to achieve the goals of increased injection, flooding, and wave expansion. Simultaneously, high-pressure expansion and injection of active water are implemented at the oil wellhead to achieve synergistic expansion, energy replenishment, and improved oil displacement efficiency and wave status, thereby improving the oil washing efficiency at the oil wellhead; balancing the pressure field, preventing water channeling in the pressure drop funnel, establishing a better and more balanced displacement relationship, improving formation energy and production capacity of the oil well, and reducing water consumption rate.

[0090] The following is a specific example of applying the present invention.

[0091] Step 1: Select a suitable development well area for implementing combined injection and production.

[0092] The Karamay rare earth reservoir in the X35 well area of ​​the Western Oilfield was put into development in 1992. Due to reservoir characteristics and development methods, the recovery rate is only 11.13%, and the current production rate is 0.5%. The oil-bearing layers in this block are extremely heterogeneous and have extremely poor permeability; both ultra-low permeability and general low permeability coexist. Figure 5 , Figure 6 The area contains relatively high-permeability layers and sections, with a biaxial stress difference of approximately 5-10 (high stress difference), a low brittleness index (40%–50%), and low complexity of artificial fractures. During vertical well water injection development, the water injection effect was poor, and the development effect was not significant, with a recovery rate of only 6.1% at the end of the stage. All oil and water wells experienced backflow. Since 2019, a phased fracturing development approach has been implemented for long-section horizontal wells. Due to elastic exhaustion-type extraction, initial production was high, but decline was significant, with recovery rates below 20%. Numerical simulation studies confirm that residual oil is enriched between horizontal well sections (300 meters), between long-section horizontal well sections, between clusters, and at the toe of the well. Therefore, a combined development approach of flooding and absorption is necessary.

[0093] Step Two: Taking into account the oil layer thickness, interlayer thickness, vertical location of horizontal wells, scale of fracturing and sand injection, the possibility of cross-layer penetration, and the perforation status of vertical wells, the development zone is determined to be: Group S5 (S5... 1 +S5 2 (Layer): The locations of wells 1309 and 1313 are relatively reasonable with the current horizontal well network, exhibiting lateral water injection and being structurally located in a low position, making their positions optimal. The two well groups are calculated based on open boundaries, with an effective water injection coefficient of 0.70 for unidirectional boundaries and 0.82 for bidirectional boundaries.

[0094] Table 1 Injection-Production Well Spacing in the Test Well Area

[0095]

[0096] The porosity compressibility was calculated to be 28.38 × 10⁻⁶, based on pressure analysis data from well W28. -4 MPa -1 .

[0097] Table 2 Crude Oil Compression Coefficient

[0098]

[0099] Based on pressure measurement data, the average formation pressure of the vertical principal stress oil wells is taken as 8.6 MPa; water well data shows 12.11 MPa, and these wells have been shut down for a long time. It is predicted that the formation pressure of the oil wells in the principal stress direction will be similar to that of the water wells. The average formation pressure of the reservoir is taken as 10.1 MPa.

[0100] Table 3. Formation pressure test results in vertical wells

[0101]

[0102] The porosity under a pore pressure of 30 MPa is 5.93% higher than that under a pore pressure of 0.72 MPa. Under normal circumstances, the porosity increase rate is taken as 5%.

[0103] Table 4. Evolution of oil reservoir properties in physical model experiments

[0104]

[0105] Table 5 Target Formation Pressure Design Table for Pressure Flooding Scheme

[0106]

[0107] Using the material balance method, the pressure-driven water injection volume is designed differently based on the different sealing properties, sand body thickness, porosity, and oil-bearing area of ​​each sand layer group in the well group of the scheme area, taking into account various production conditions.

[0108] Considering the large well spacing (500m) at point A, and taking into account the well network, well spacing, starting pressure gradient, water injection volume, etc., the oil-bearing area of ​​point C (the middle point of the horizontal well) is selected as the pressure drive range.

[0109] Considering the differences in basin types (compressional arching-tightening-fault depression) between the west and east, stress transmission (rock physical properties), degree of compaction, pore throat type and structural dip angle, oil-gas ratio, formation degassing, etc., the water injection volume will increase by about 10%-20%.

[0110] Table 6 Optimization Design of Pressure-Driven Injection Rate

[0111]

[0112] Step 3: Taking into account factors such as the production status of the oil well, the scale of fracturing, the formation void, the injection-production well spacing, and the stress direction, it was decided to carry out hydraulic injection and huff-and-puff in horizontal wells with a large amount of produced fluid. Drawing on the practice and understanding of horizontal well injection and huff-and-puff in other parts of China, the design was based on a void volume of 130%.

[0113] Table 7 High-voltage capacity expansion throughput optimization design

[0114]

[0115] To enhance the permeation effect, permeation agent is injected simultaneously with the energy increase, with a total concentration of 0.2%. The slug design consists of the first 10% liquid (0.4%), the middle 80% liquid (0.2%), and the last 10% liquid (without chemical additives). When there are dominant seepage channels formed by fracturing in the corresponding formation of the oil well, temporary plugging agent is intermittently added during the high-pressure expansion and injection process of the oil well.

[0116] Step 4: Due to the low formation pressure, injected water is prone to channeling along the principal stress and low-pressure zones during pressure drive. Therefore, asymmetric coupling of injection and production is implemented to balance the flow field and adjust streamlines. When injecting water into the water well for pressure drive, the production well is shut off to avoid water flooding and channeling, thus promoting balanced operation. After injection is stopped, the coupling time of the production well is determined based on the pressure diffusion to achieve balanced displacement.

[0117] After pressure drive is completed, dynamic adjustments are made based on monitoring of oil wells (pressure monitoring) and water wells (water drive front monitoring). Wells with weak energy recovery are opened first, while those with strong energy recovery are opened later.

[0118] Implementation Results: When the average formation pressure coefficient remains at 1.4 after pressure drive, the expected average formation pressure coefficient of the oil wells is around 1.0 (one-way effect), and the production pressure differential is 10.2 MPa. Due to pressure sensitivity and degassing issues, the oil production index in this area had previously decreased significantly. Based on well test data, the oil production index in this area is 0.0191 t / d.MPa.m. After the pressure drive of 12 wells in 2 well groups became effective, the production capacity increased by 69 t / d in the first year, with an estimated increase of 10,510 tons of oil produced in the first year.

[0119] Table 8. Productivity Results of Test Well Groups

[0120]

[0121] It is projected that the recovery rate will reach 32.4% in 15 years, with a phased increase of 16.8%, resulting in a significant improvement in development effectiveness.

[0122] To ensure that oil discharge, active water ingestion, and temporary plugging agent ingestion in oil wells can proceed without interference, such as Figure 7 As shown, in the oil well, from the outside to the inside, there are technical casing 8, intermediate pipe 2 and tubing 1. Packers 9 are installed between technical casing 8 and intermediate pipe 2, and at the top and bottom of any oil layer. That is, at the top and bottom of each target oil layer, there are packers 9 between technical casing 8 and intermediate pipe 2 to isolate different oil layers and prevent fluid cross-flow. There is a distribution mechanism between two adjacent packers 9. The distribution mechanism is the core component for realizing the coordinated drive and swallowing. It is set for each oil layer and is used to control the switching of active water injection, temporary plugging agent injection and formation fluid production.

[0123] The distribution agency, such as Figures 8-18 As shown, it includes the following structure:

[0124] like Figures 8-11 As shown, firstly, there is a distribution shell 3, which is formed by an upper short section 31, a middle short section 32, and a lower short section 33 connected sequentially from top to bottom by threads. An intermediate pipe 2 is threaded to the upper end of the upper short section 31, and another intermediate pipe 2 is threaded to the lower end of the lower short section 33. The distribution shell 3 serves as a shell, accommodating internal components (inner distribution cylinder structure 4 and mixing component 5) and forming an active water flow channel (active water gradually flows downward from the annulus between the oil pipe 1 and the intermediate pipe 2 to the target oil layer where the distribution shell 3 is located).

[0125] Second, the active water drain hole 7 is radially opened near the upper part of the distribution shell 3, and is used to drain active water from the annulus into the target oil layer.

[0126] Third, the activated water opening and closing component 6 is installed on the inner wall of the dispensing housing 3 and is used to control the opening and closing of the activated water drain hole 7; specifically, the structure of the activated water opening and closing component 6 (as shown in the figure) Figure 12 As shown, the device includes a second retaining ring 61, which is axially and radially confined within the distribution housing 3 to a plane at the same height as the active water drain hole 7. This means that the second retaining ring 61 can only rotate within the distribution housing 3. A through hole 611 is provided on the second retaining ring 61 in the area opposite to the active water drain hole 7. The distribution housing 3 is also equipped with a second intelligent drive structure 62 for controlling the angle required for the rotation of the second retaining ring 61. When the second intelligent drive structure 62 is working, the second retaining ring 61 can rotate, thereby making the through hole 611 opposite to or not opposite to the active water drain hole 7. When the through hole 611 is opposite to the active water drain hole 7, the active water can be discharged from the annulus to the target oil layer. Conversely, when they are not opposite, the active water cannot enter the target oil layer, and the formation fluid will not flow back into the annulus between the intermediate pipe 2 and the oil pipe 1.

[0127] Preferably, the intelligent drive structure 62 includes a tooth 623 disposed on the inner wall of the retaining ring 61, which avoids the through hole 611, a gear 622 meshing on one side of the tooth 623, and a sealed motor 621 installed in the distribution housing 3 for controlling the rotation of the gear 622; the sealed motor 621 drives the gear 622 to rotate, thereby driving the retaining ring 61 to rotate through the tooth 623.

[0128] The wellhead control module adjusts the opening of the active water drainage hole 7 through the intelligent drive structure 262 based on the downhole pressure sensor data.

[0129] Reference Figures 9-11 as well as Figures 13-17As shown, fourth, the inner distribution cylinder structure 4 includes a distribution cylinder 41, which is located inside the distribution shell 3. The upper and lower ends of the distribution cylinder 41 are connected to the oil pipe 1 by threads. The distribution cylinder 41 is provided with a formation fluid inlet pipe 42 and a temporary plugging agent outlet pipe 45 arranged vertically. That is, during the oil well's oil discharge stage, when the oil pump is operating, the formation fluid corresponding to the oil layer enters the distribution cylinder 41 from the formation fluid inlet pipe 42 and is lifted upwards. When it is necessary to inject temporary plugging agent into the oil layer, the temporary plugging agent is transported downwards from the upper end of the oil pipe and discharged from the oil pipe 1 by threads. The distribution cylinder 41 is provided with a formation fluid inlet pipe 42 and a temporary plugging agent outlet pipe 45 arranged vertically.

[0130] Preferably, a one-way valve is provided in the formation fluid inlet pipe 42 to allow formation fluid to enter the distribution cylinder 41, so that during the upward phase of the pump, formation fluid can enter the distribution cylinder 41 from the oil layer, and conversely, during the downward phase of the pump, formation fluid will not flow back into the oil layer. In addition, in order to achieve communication between the formation fluid inlet pipe 42 and the oil layer, and between the temporary plugging agent drain pipe 45 and the oil layer, an inlet sleeve 43 is provided radially from the outside of the distribution housing 3 to the formation fluid inlet pipe 42, and a drain sleeve 44 is provided radially from the outside of the distribution housing 3 to the temporary plugging agent drain pipe 45 (perforations are reserved on the distribution housing 3 for the inlet sleeve 43 and the temporary plugging agent drain pipe 45). Furthermore, the inlet sleeve 43 and the temporary plugging agent drain pipe 45 are widened at one end near the outer circumference of the distribution housing 3, and a sealing ring is added at this position.

[0131] Fifth, the mixing component 5, located on the distribution cylinder 41, is used to control the switching between formation fluid entry and temporary plugging agent discharge, that is, to control the formation fluid entry pipe 42 to open and the temporary plugging agent discharge pipe 45 to close, or to control the formation fluid entry pipe 42 to close and the temporary plugging agent discharge pipe 45 to open.

[0132] Specifically, the adjustment component 5 includes a retaining ring 51, a rotating component, and an intelligent drive structure 55.

[0133] A retaining ring 51 is installed inside the distribution cylinder 41. The retaining ring 51 can completely cover the formation fluid inlet pipe 42 or the temporary plugging agent outlet pipe 45. Figure 13 and Figure 14 The state is such that the baffle ring 51 covers and closes the formation fluid inlet pipe 42. In this state, when the baffle ring 51 moves downward, it can cover and close the temporary plugging agent drain pipe 45.

[0134] To enable the retaining ring 51 to move up and down, the rotating component includes a threaded cylinder 52 threaded to the inner wall of the retaining ring 51, a hollow part 53 located at the lower end of the threaded cylinder 52, and a rotating cylinder 54 located at the lower end of the hollow part 53. The intelligent drive structure 55 is installed on the distribution cylinder 41 to drive the rotating cylinder 54 to rotate.

[0135] Preferably, such as Figure 18 As shown, a grooved ring 542 is provided in the middle of the outer circumference of the rotating cylinder 54. The intelligent drive structure 55 includes a helical tooth 551 provided on the grooved ring 542, a worm gear 552 meshing on one side of the helical tooth 551, and a sealed motor 553 installed on the distribution housing 3 for driving the worm gear 552 to rotate. The inner diameter of the middle short section 32 of the distribution housing is 150-200mm. The sealed motor 553 should be a motor with a sealed housing and an outer diameter of 80-100mm. The sealed motor 553 is connected to the ground control module through a cable.

[0136] A sealing design was also implemented: the upper and lower ends of the rotating cylinder 54 are equipped with sealing flanges 541 (sealed with the distribution cylinder 41) to prevent fluid leakage.

[0137] Formation fluid entry: The baffle ring 51 covers the temporary plugging agent drain pipe 45, and the formation fluid enters the distribution cylinder 41 through the one-way valve of the formation fluid entry pipe 42;

[0138] Temporary plugging agent discharge: The retaining ring 51 covers the formation fluid inlet pipe 42, and the temporary plugging agent is discharged from the oil pipe 1 into the oil layer through the temporary plugging agent discharge pipe 45.

[0139] The aforementioned sealing motor 553 and sealing motor 621 are connected to the control module of the surface production tree via cables. The control module can receive data from downhole sensors (such as pressure sensors and flow sensors) in real time and automatically adjust the motor rotation direction (opening / closing the corresponding channel) and rotation degree (corresponding opening degree). When a sudden increase in the production of a certain oil layer is detected (indicating the formation of a dominant channel), the control module automatically sends a command to close the active water drainage hole 7 of that oil layer, open the temporary plugging agent drainage pipe 45, and inject the temporary plugging agent.

[0140] In addition, the wellhead of the oil well has an active water supply system that is connected to the annulus between tubing 1 and intermediate tubing 2; the wellhead of the oil well has a temporary plugging agent supply system that is connected to tubing 1; the wellhead of the oil well has a pipeline that is connected to the formation fluid delivery system; the active water supply system, the temporary plugging agent supply system, and the pipeline are integrated on the Christmas tree.

[0141] It should be noted that the temporary plugging agent is a soluble knot, and its carrier is also active water. That is, the temporary plugging agent supplied by the temporary plugging agent supply system is a mixture of soluble knot and active water. During use, active water is injected into the annulus between oil pipe 1 and intermediate pipe 2, and all active water drain holes 7 on the distribution mechanism are in the open state, but their opening degree is determined by the water volume required by the oil layer. When a dominant channel is detected in an oil layer (this oil layer is called the target oil layer), the temporary plugging agent is injected into oil pipe 1, directly opening the temporary plugging agent drain pipe 45 in the target oil layer, and then closing... Close the active water drainage hole 7 corresponding to the target oil layer (the active water drainage holes 7 of the other oil layers continue to work, that is, the other oil layers continue to enter the active water, and the temporary plugging agent will not reach the other oil layers). At this time, the temporary plugging agent (a mixture of soluble knot and active water) is discharged into the formation from the temporary plugging agent drainage pipe 45 of the target oil layer. In this way, on the one hand, there is no need to stop the pump to change the fluid, which reduces the operation time (if a single well is temporarily plugged 2-3 times, it can save 1-2 days of operation time). On the other hand, when the temporary plugging agent is injected into the target oil layer, the other oil layers continue to expand and replenish energy without stopping the machine, which improves the operation efficiency.

[0142] During the oil well discharge phase, all active water drainage holes 7 in the oil layer are closed, all temporary plugging agent drainage pipes 45 are closed, and the formation fluid inlet pipe 42 is opened. At this time, the oil pump works and can extract the formation fluid.

Claims

1. A method for developing a bidirectional coupling pressure flooding injection and production, characterized in that, Includes the following steps: Step 1: Select a suitable development well area for implementing combined injection and production; Step 2: Determine the optimal injection volume and injection rate for water well pressure-driven water injection; Step 3: Determine the optimal injection rate and huff / puff design for high-pressure expansion huff / puff in the oil well; Step 4: Implement coordinated displacement and injection production to establish an effective and balanced displacement relationship; In step one, based on the location, structural features, oil layer features, production level, and current development well network of the reservoir, sand bodies with relatively closed boundaries are selected, and the target development well area is determined by combining the dynamic effect of the oil wells in the well group. In step two, using the material balance method, and considering the differences in sealing properties, sand body thickness, porosity, and oil-bearing area of ​​each sand layer group in the development well area, the water injection rate for forward hydraulic injection of the water well is designed differently based on various production conditions. The method for calculating the water injection rate for forward hydraulic injection of the water well is as follows: Q = 1 / η × φ × S × H × ΔP × Ct; where Q is the water injection rate for water injection pressure drive; φ is the porosity of the oil layer; S is the oil-bearing area; H is the sand body thickness; η is the sealing coefficient; ΔP is the pressure difference before and after water injection in the reservoir; and Ct is the comprehensive compressibility coefficient. Ct = Co × So + Cw × Sw + CP, where So is the oil saturation; Sw is the water saturation; Co is the crude oil compressibility coefficient; Cw is the formation water compressibility coefficient; and CP is the rock pore compressibility coefficient. In step three, the injection volume of the high-pressure expansion huff and puff in the oil well is calculated according to the following formula, taking into account the oil well production status and formation deficit: ； Where V is the reverse pressure drive injection fluid volume; is the corresponding layer thickness percentage; is the cumulative oil production; is the cumulative water production; is the crude oil density; is the formation water density; is the crude oil volume coefficient; Ct is the comprehensive compression coefficient; ΔP is the formation voidage difference.

2. The bidirectional coupled pressure-driven injection-production development method according to claim 1, characterized in that, In step three, the high-pressure expansion of the oil well is carried out by adding active water with a total concentration of 0.2% permeate agent. During the injection process, a segmented plug variable concentration injection method is adopted, with the variable concentration being high at the beginning and low at the end. When there is a dominant seepage channel formed by fracturing in the corresponding formation of the oil well, temporary plugging agent is added intermittently during the high-pressure expansion and injection process of the oil well.

3. The bidirectional coupled pressure-driven injection-production development method according to claim 2, characterized in that, The oil well is provided with a technical casing (8), an intermediate pipe (2) and a tubing (1) in sequence from the outside to the inside. Packers (9) are provided between the technical casing (8) and the intermediate pipe (2) and at the top and bottom of any oil layer. A distribution mechanism is provided between two adjacent packers (9). The distribution mechanism includes: The upper and lower ends of the distribution shell (3) are connected to the intermediate tube (2) by threads; An active water drain hole (7) is radially opened on the upper part of the distribution shell (3). An active water opening and closing assembly (6) is provided on the side wall of the distribution shell (3). The active water opening and closing assembly (6) is used to control the opening and closing of the active water drain hole (7). Active water reaches the active water drain hole (7) from the annulus between the oil pipe (1) and the intermediate pipe (2). The distribution cylinder (41) is located inside the distribution housing (3). The upper and lower ends of the distribution cylinder (41) are connected to the oil pipe (1) by threads. The distribution cylinder (41) is provided with a formation fluid inlet pipe (42) and a temporary plugging agent drain pipe (45) arranged side by side. The formation fluid inlet pipe (42) is provided with a one-way valve that allows the formation fluid to enter the distribution cylinder (41). An oil inlet sleeve (43) is provided radially from the outside of the distribution housing (3) to the formation fluid inlet pipe (42), and a drain sleeve (44) is provided radially from the outside of the distribution housing (3) to the temporary plugging agent drain pipe (45). The mixing component (5) is located on the distribution cylinder (41) and is used to control the opening of the formation fluid inlet pipe (42) or the temporary plugging agent outlet pipe (45).

4. The bidirectional coupled pressure-driven injection-production development method according to claim 3, characterized in that, The mixing component (5) includes: A first baffle ring (51) is installed inside the distribution cylinder (41). The first baffle ring (51) can completely cover the formation fluid inlet pipe (42) or completely cover the temporary plugging agent outlet pipe (45). The rotating component includes a threaded cylinder (52) threaded to the inner wall of the retaining ring (51), a hollow part (53) located at the lower end of the threaded cylinder (52), and a rotating cylinder (54) located at the lower end of the hollow part (53). Intelligent drive structure 1 (55) is installed on the distribution cylinder (41) and is used to drive the rotating cylinder (54) to rotate.

5. The bidirectional coupled pressure-driven injection-production development method according to claim 4, characterized in that, The rotating cylinder (54) is provided with sealing edges (541) at both the upper and lower ends, and the sealing edges (541) are sealed with the distribution cylinder (41); The outer peripheral surface of the rotating cylinder (54) is provided with a groove ring (542). The intelligent drive structure (55) includes a helical tooth (551) provided on the groove ring (542), a worm gear (552) meshing on one side of the helical tooth (551), and a sealed motor (553) installed on the distribution housing (3) for driving the worm gear (552) to rotate.

6. A bidirectional coupled pressure-driven injection-production development method according to any one of claims 3-5, characterized in that, The active water opening and closing component (6) includes a second retaining ring (61). The second retaining ring (61) is axially and radially limited to a plane inside the distribution housing (3) that is at the same height as the active water drain hole (7). A through hole (611) is opened on the area of ​​the second retaining ring (61) opposite to the active water drain hole (7). The distribution housing (3) is also equipped with a second intelligent drive structure (62) for controlling the angle required for the rotation of the second retaining ring (61). The intelligent drive structure 2 (62) includes a tooth (623) that avoids the through hole (611) and is set on the inner wall of the retaining ring 2 (61), a gear (622) that meshes on one side of the tooth (623), and a sealed motor 2 (621) installed in the distribution housing (3) for controlling the rotation of the gear (622).

7. A bidirectional coupled pressure-driven injection-production development method according to any one of claims 3-5, characterized in that, The wellhead of the oil well has an active water supply system that is connected to the annulus between the oil pipe (1) and the intermediate pipe (2); The wellhead of the oil well has a temporary plugging agent supply system connected to the tubing (1); The wellhead of the oil well has a pipe that connects to the formation fluid delivery system; The active water supply system, the temporary plugging agent supply system, and pipelines are integrated on the Christmas tree; The temporary plugging agent is a mixture of soluble knots and active water.

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