High-strength, long-lasting, deep composite plugging method to reduce crack conductivity

Abstract

This invention provides a high-strength, long-lasting, deep composite plugging method for reducing fracture conductivity, comprising the following steps: Step 1, determining the water breakthrough type of each water-bearing and water-flooded well in the well group; Step 2, simplifying the dominant fracture channel into a rectangular equivalent model and calculating the plugging agent dosage; Step 3, injecting water into the well group for testing, clearing and pre-treating the fracture channels to be plugged, and recording the water intake indicator curve and pressure drop curve of the corresponding injection well in the well group to be profiled; Step 4, deep composite plugging agent injection operation; Step 5, monitoring the injection pressure rise during the plugging agent injection process and testing after completing the designed injection volume of plugging agent; Step 6, completing the test and resuming water injection production. The high-strength, long-lasting, deep composite plugging method for reducing fracture conductivity provided by this invention can solve the problems in existing technologies that make it difficult to achieve high-strength, long-lasting plugging of deep formation fractures, affecting the plugging effect of injection wells and the release of water-flooded production capacity.

Description

Technical Field

[0001] This invention relates to the technical field of oilfield development, and more specifically, to a high-strength, long-lasting, deep composite plugging method for reducing fracture conductivity. Background Technology

[0002] Domestic onshore low-permeability to ultra-low-permeability oil reservoirs are dense and highly heterogeneous, with well-developed natural microfractures. The common development method is "fracturing for production + water injection for energy replenishment." As water injection development time increases, the injected water connects the naturally developed microfractures within the reservoir itself with the artificially constructed fracture network in the wells, forming a dominant water drive channel. This leads to ineffective circulation of subsequent injected water, exacerbating the heterogeneity of the injection well profile and causing premature and rapid water breakthrough and water flooding in the main directional wells. Furthermore, the water lines of oil and water wells in the dominant direction within the well group are connected, exhibiting obvious fractured water breakthrough (water flooding) characteristics.

[0003] Practice has proven that sealing water drive channels through microfractures in reservoirs by water injection wells, reducing fracture conductivity, and expanding the subsequent water drive sweep volume are important technical measures to improve water drive development effects and achieve water control and oil stabilization in old oilfields. However, conventional profile control suffers from several problems. For example, weak gels have high initial viscosity and large particle size (nearly centimeter level), resulting in poor injectability and short migration distance. The system also has weak temperature and salt resistance, making it prone to hydrolysis and gel breakage, leading to profile control failure. Furthermore, it has low strength, is not resistant to erosion, has weak retention stability, and a short effective period for profile control. In terms of profile control technology, the large system size, high viscosity, and low strength limit the ability to achieve fluid flow diversion in the near-wellbore zone, making it difficult to achieve deep reservoir profile control. This results in limited expansion of the water drive sweep range and deterioration of the effect after multiple rounds of profile control. Improper use of strong gels can easily cause "sausage filling" of the wellbore, solidifying the tubing string and posing significant construction safety risks. For example, the invention patent for a deep profile adjustment method for fractured reservoirs with application number 201010262239.8 uses a high-strength solidification system, inorganic gel, water drive flow direction change agent (bulk particles, clay) + weak gel, and strong gel YQY plugging agent in four slugs to adjust the near-wellbore water intake profile of the injection well; the invention patent for a multi-slug combination sealing and plugging method for profile adjustment with application number 201910733209.1 uses water-swellable particle temporary plugging agent to bridge and temporarily plug in the fractures, and seals the near-wellbore fractures.

[0004] However, due to the limitations of the system used, it is difficult to achieve high-strength and long-term sealing of deep formation fractures, which affects the plugging effect of water injection wells and the release of water-flooded production capacity, making it difficult to improve the oil reservoir recovery rate. Summary of the Invention

[0005] The main objective of this invention is to provide a high-strength, long-lasting, deep composite plugging method for reducing fracture conductivity. The aim is to block water-bearing channels in fractures through the synergistic enhancement effect of small-particle-size, high-strength, long-lasting composite plugs, thereby controlling water-bearing in oil wells, promoting the displacement of injected water matrix, restoring water-bearing and water-flooded production capacity, tapping the potential of residual matrix oil, and improving reservoir recovery.

[0006] To achieve the above objectives, the present invention adopts the following technical solution: a high-strength, long-lasting, deep composite plugging method for reducing the conductivity of cracks, comprising the following steps:

[0007] Step 1: Determine the water breakthrough type of each water-bearing and water-flooded well in the well group;

[0008] Step 2: The dominant channel of the crack is simplified into a rectangular equivalent model, and the amount of plugging agent is calculated;

[0009] Step 3: Inject water into the well group for testing, clear and pre-treat the fracture channels to be sealed, and record the water intake indicator curve and pressure drop curve of the corresponding injection well in the well group to be adjusted.

[0010] Step 4: Deep composite plugging agent injection operation;

[0011] Step 5: During the plugging agent injection process, monitor the changes in injection pressure and conduct tests after completing the designed injection volume of plugging agent;

[0012] Step six: The test is completed and water injection production is resumed.

[0013] Furthermore, the criteria for determining the water-bearing and water-flooded oil well types in step one include the comprehensive water cut of each oil well in the well group, production dynamics after commissioning, historical fluid production, water cut increase trend and change characteristics, and reservoir fracture development, distribution and orientation.

[0014] Furthermore, the method used in step one to determine the water breakthrough and water flooding type of oil wells within the well group is as follows: If the overall water cut of one or more oil wells in the well group is greater than 80%, and the production dynamic curve shows a rapid and sharp increase in production volume and overall water cut during a certain period of time, even a steep increase, exhibiting a clear "step-like" characteristic, and then maintains high production volume, high water cut, and water flooding production characteristics; combined with the fracture distribution and orientation, it can be determined that the water breakthrough and water flooding well is connected to the main fracture direction and is a fracture main direction oil well, and the water breakthrough type of the oil well is fracture water flooding; if the water cut rises rapidly and the oil well with high production volume and high water cut is connected to the secondary fracture direction and is a secondary fracture direction oil well, the water breakthrough type is fracture water breakthrough.

[0015] Furthermore, the criteria for determining the water-bearing and water-flooded oil well types in step one include the comprehensive water cut of each oil well in the well group, production dynamics after commissioning, historical fluid production, water cut increase trend and change characteristics, and reservoir fracture development, distribution and orientation.

[0016] Furthermore, in step two, when simplifying to a rectangular equivalent model, the fracture and secondary fracture channels are regarded as the same rectangular model. The depth, width, and height of the main fracture and secondary fracture channels are equivalent to the length, width, and height of the rectangle. There are n dominant fracture channels in the well group, which are equivalent to n rectangular models. The volume of the fracture space that needs to be plugged is calculated, and the amount of plugging agent required is calculated according to the characteristics of the plugging agent.

[0017] Furthermore, in step two, the amount of sealant required to seal the dominant channel of the crack is calculated based on the rectangular equivalent model. The calculation formula is as follows:

[0018]

[0019] In the formula:

[0020] V----Dosage of plugging agent, in meters (m) 3 ;

[0021] c----crack width, in meters;

[0022] h----Crack height, in meters;

[0023] l----Crack sealing depth, in meters;

[0024] n----Number of fractures in the well group, in units of fractures;

[0025] M----Coefficient of particle swelling when exposed to water;

[0026] B----Volume compressibility coefficient;

[0027] m----solution concentration;

[0028] η----Loss through the blast hole.

[0029] Furthermore, in step three, the water intake indicator curve and pressure drop curve of the injection well corresponding to the proposed profile control well group are taken, and water is injected using pumps with different discharge capacities. The wellhead pressure is recorded, and the relationship curve between discharge capacity and wellhead pressure is plotted. When recording the pressure drop curve, water is injected into the injection well pump. When the wellhead pressure reaches a stable state, the pump is stopped. The wellhead pressure value is recorded at fixed time intervals, and the relationship curve between time and wellhead pressure value is plotted.

[0030] Furthermore, in step four, the plugging slugs are divided into two levels: millimeter-sized flexible, high-strength, long-lasting particle primary plugging slugs and micron-sized high-strength single-phase microgel secondary filling plugging slugs; during extrusion, the millimeter-sized flexible, high-strength, long-lasting particle primary plugging slugs are injected first, followed by the micron-sized high-strength single-phase microgel secondary filling plugging slugs.

[0031] Furthermore, the overall injection ratio of the main plugging slug and the secondary filling plugging slug should be greater than or equal to 1 and less than or equal to 1.2.

[0032] Furthermore, in step five, if the injection pressure in the injection well rises above 0.5 MPa, the injection process is switched to inject water at the same flow rate to push the plugging agent to move deeper into the formation. After the pressure drops and stabilizes, the process is switched to the plugging agent squeezing injection process for normal plugging agent injection.

[0033] Furthermore, in step five, after completing the designed injection volume of the plugging agent, the water absorption indicator curve and pressure drop curve after profile adjustment are tested to determine the water absorption and pressure changes, and to determine whether the crack channel is effectively sealed.

[0034] Furthermore, in step six, after the plugging agent injection, water absorption, and pressure drop tests are completed and the plugging target is achieved, there is no need to shut in the well and wait for it to solidify. The water injection process can be directly resumed, and water injection can be resumed according to the geological injection plan.

[0035] The technical solution of this invention is as follows:

[0036] 1. By combining two systems, flexible elastic particles and single-phase microgel, the synergistic enhancement effect of high-strength and long-lasting slugs is achieved, which increases the pressure gradient in the deep formation, seals the water drive channels in the fractures, has strong resistance to water injection scouring, increases the oil pressure in the injection well, expands the low-permeability swept volume, activates the remaining oil in the low-permeability zone of the matrix, and improves the water drive effect of the reservoir.

[0037] 2. The "flexible elastic particles plus single-phase microgel" high-strength long-lasting deep composite plugging method proposed in this invention has small particle size, large deformation capacity, strong deep migration and plugging performance, and large plugging radius; it is temperature resistant, salt resistant, water injection erosion resistant, and has a long effective time. It can stay in the dominant channel of formation fracture for a long time, thus extending the effective period of plugging in water injection wells.

[0038] 3. The "flexible elastic particles plus single-phase microgel" high-strength long-lasting deep composite plugging method proposed in this invention uses a single system of factory-prefabricated plugging agents, which can be directly pumped on-site according to construction requirements without the need for other components or liquid preparation. The construction is simple and easy to operate. Attached Figure Description

[0039] The accompanying drawings, which form part of this application, are used to provide a further understanding of the invention. The illustrative embodiments of the invention and their descriptions are used to explain the invention and do not constitute an undue limitation of the invention. In the drawings:

[0040] Figure 1 A flowchart of the high-strength, long-lasting, deep composite plugging method for reducing the flow conductivity of cracks in this embodiment is shown.

[0041] Figure 2 A schematic diagram of a rectangular equivalent model for calculating the amount of plugging agent needed to seal cracks is shown;

[0042] Figure 3 A schematic diagram of a high-strength, long-lasting, deep composite plugging method for reducing fracture conductivity is shown.

[0043] Figure 4 The pressure drop curves before and after profile adjustment of injection well B402-45 are shown;

[0044] Figure 5 The water intake indicator curves of the B402-45 water injection well before and after profile adjustment are shown;

[0045] Figure 6 The production dynamic curves of well B401-44, a fractured water-bearing oil well corresponding to well group B402-45, are shown.

[0046] Figure 7 The production dynamic curve of well B402-44, a fractured water-flooded oil well corresponding to well group B402-45, is shown.

[0047] Figure 8 The production dynamic curves of the remaining 6 oil production wells corresponding to the B402-45 well group are shown;

[0048] Figure 9 The pressure drop curves before and after profile adjustment of the C35-49 water injection well are shown;

[0049] Figure 10 The water intake indicator curves of the C35-49 water injection well before and after profile adjustment are shown;

[0050] Figure 11 The production dynamic curves of well C34-49, a fractured water-flooded well in the C35-49 well group, are shown.

[0051] Figure 12 The production dynamic curves of well C36-49, a fractured water-flooded well in the C35-49 well group, are shown.

[0052] Figure 13 The production dynamic curves of the remaining 5 oil wells in the C35-49 well group are shown. Detailed Implementation

[0053] It should be noted that, unless otherwise specified, the embodiments and features described in this application can be combined with each other. The present invention will now be described in detail with reference to the accompanying drawings and embodiments.

[0054] It should be noted that, unless otherwise specified, all technical and scientific terms used in this application have the same meaning as commonly understood by one of ordinary skill in the art to which this application pertains.

[0055] In this invention, unless otherwise stated, directional terms such as "upper," "lower," "top," and "bottom" are generally used in relation to the direction shown in the accompanying drawings, or in relation to the vertical, perpendicular, or gravitational direction of the component itself; similarly, for ease of understanding and description, "inner" and "outer" refer to the inner and outer contours of each component itself, but the above directional terms are not intended to limit this invention.

[0056] To address the challenges of achieving high-strength, long-lasting sealing of deep formation fractures in existing technologies, which affects the effectiveness of water injection well plugging and the release of water-flooded production capacity, this invention provides a high-strength, long-lasting, deep composite plugging method to reduce fracture conductivity. The aim is to utilize the synergistic enhancement effect of small-particle-size, high-strength, long-lasting composite slugs to seal water-bearing channels in fractures, control water breakthrough in oil wells, promote matrix displacement by injected water, restore water breakthrough and water-flooded production capacity, tap into remaining matrix oil, and improve reservoir recovery.

[0057] Example 1

[0058] like Figures 1 to 3 As shown, a high-strength, long-lasting, deep composite plugging method for reducing the conductivity of fractures includes the following steps:

[0059] Step 1: Based on the comprehensive water cut of each well in the well group, the production dynamics after commissioning, historical fluid production, water cut increase trend and change characteristics, reservoir fracture development, distribution and orientation, etc., determine the water breakage type of each water-bearing and water-flooded well in the well group.

[0060] If the overall water cut of one or more wells in a well group exceeds 80%, and the production dynamic curve shows a rapid and sharp increase in both fluid production and overall water cut within a certain time period, exhibiting a distinct "step-like" characteristic, followed by a sustained high fluid production, high water cut, and water-flooded production pattern, then, based on the fracture distribution and orientation, it can be determined that the water-bearing (water-flooded) well is connected to the main fracture direction and is a fracture-direction oil well, with the water breakthrough type being fracture-induced water flooding. Conversely, if the well with rapidly increasing water cut, high fluid production, and high water cut is connected to secondary fractures and is a secondary fracture-direction oil well, with the water breakthrough type being fracture-induced water breakthrough.

[0061] Step 2: Simplify the dominant channel of the crack into a rectangular equivalent model and calculate the amount of plugging agent needed.

[0062] The primary and secondary fracture channels are considered as identical rectangular models. The depth, width, and height of the primary and secondary fracture channels are equivalent to the length, width, and height of a rectangle. There are n dominant fracture channels within the well group, which are equivalent to n rectangular models. The volume of the fracture space requiring plugging is calculated, and the required amount of plugging agent is calculated based on the characteristics of the plugging agent.

[0063] Considering factors such as the water expansion ratio, volumetric compressibility, and loss through the borehole, the following formula is used to calculate the amount of plugging agent required:

[0064]

[0065] In the formula: V----dosage of plugging agent, in m³ 3 ;

[0066] c----crack width, in meters;

[0067] h----fracture height (taken as the thickness of the oil layer that has been perforated, generally 80% of the oil layer thickness), in meters;

[0068] l----Deep crack sealing (for deep crack sealing, take 1 / 4 to 1 / 3 of the distance between oil and water wells), in meters;

[0069] n----Number of fractures in the well group, in units of fractures;

[0070] M----The coefficient of particle expansion when exposed to water, which is generally taken as 3;

[0071] B----Volume compressibility coefficient, typically taken as 0.7;

[0072] m----solution concentration;

[0073] η----Loss through the blast hole, generally taken as 50%.

[0074] Step 3: Test injection of water into the well group. Inject 30-50 cubic meters of clean water into the corresponding injection wells in the well group to clear and pre-treat the fracture channels to be sealed. Record the water intake indicator curve and pressure drop curve of the corresponding injection wells in the well group to be adjusted. Inject water at a discharge rate of 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, and 70 cubic meters per day, record the wellhead pressure, and plot the discharge rate-wellhead pressure change curve. When recording the pressure drop curve, inject water into the injection wells. Stop pumping when the wellhead pressure reaches a stable state. Record the wellhead pressure values ​​at 2, 4, 6, 8, 10, 12, 14, 16, 18, 20, 22, and 24 hours, and plot the time-wellhead pressure value relationship curve.

[0075] Step 4: Deep composite plugging agent injection operation.

[0076] See Figure 2 and Figure 3 The approach adopts the concept of "combining large and small sizes, matching strong and weak elements, and synergistic enhancement". The plugs are divided into two levels: millimeter-level (2-4mm) flexible, high-strength, long-lasting particle primary plugs and micron-level (40-300 microns) high-strength single-phase microgel secondary filling plugs.

[0077] During the injection process, millimeter-sized flexible, high-strength, long-lasting particle primary plugs are injected first, followed by micron-sized high-strength single-phase microgel secondary filling and plugging plugs. To ensure high-strength and long-lasting sealing of the fracture channel, the overall injection ratio of primary plugs to secondary filling and plugging plugs is controlled at 50%-60%:40%-50%.

[0078] The main function of millimeter-sized flexible high-strength long-lasting particles is to utilize their excellent flexible deformation ability and high compressive strength to penetrate deep into the formation, forming a "physical partition" and cutting off the water drive channel in the fracture. The main function of micron-sized high-strength single-phase microgel is to fill and seal the gaps between the former slug particles, supplement and strengthen the former slug, making the overall sealing slug more compact and dense, improving the sealing strength, resisting the impact of subsequent water drive, promoting subsequent water drive turbulence, and expanding the swept volume.

[0079] To avoid excessive injection rate and intensity, which could cause pressure surges and increase water cut in low-water-cut oil wells, allowing the plugging agent to penetrate deeper into the reservoir, the injection pressure will gradually increase. Simultaneously, to allow for pressure increases in subsequent measures, a low injection rate (1.0-1.5 m³ / h) will be adopted for the initial water injection test. 3 / h) injection, plugging agent injection using a small slug (50-100m) 3 Low displacement (1.0-1.5m) 3 / h), with primary and secondary slugs injected alternately in a cycle.

[0080] Millimeter-scale flexible, high-strength, long-lasting granular plugging agent: By mass percentage, 60% thermoplastic vulcanized rubber (TPV), 30% thermoplastic elastomer (TPES), and 10% SEBS-g-MAH are added separately to a mixer and mixed at 175–185℃ for 5–15 minutes. Then, it is hot-pressed at 155–165℃ and a pressure of 5–10 MPa for 5–20 minutes. After natural cooling, it is rotary-cut into granules and physically cooled using water cooling. This process is prefabricated in a factory. The finished product is white columnar granules with a particle size of 2–4 mm and a density of 0.95–1.1 g / cm³. 3 Its elastic modulus is 1.5–4.0 MPa, its deformation capacity (elongation at break) is 1000–1300%, and it is heat resistant (above 80℃) and salt resistant (10×10⁻⁶). 4 (mg / L or higher), compressive strength ≥ 1.0 MPa, and thermal stability up to 24 months (80℃, 10×10) 4 (Under sodium chloride concentration of mg / L). The plugging material exhibits good toughness, high compressive strength, strong deformation ability, and good chemical stability.

[0081] Among them: thermoplastic vulcanized rubber is a block copolymer with (PBA)150(PMMA)100(PBA)150 structure; thermoplastic elastomer is a blend of isoprene and low-density polyethylene copolymer with inorganic ion Nano-CaCO3; SEBS-g-MAH is a hydrogenated styrene-butadiene block copolymer grafted with maleic anhydride, with a grafting rate of 1.0%, wherein maleic anhydride is a thermoplastic elastomer obtained by hydrogenation of styrene-butadiene-styrene block copolymer.

[0082] Micron-sized high-strength single-phase microgel particles as a plugging agent: A reverse suspension polymerization method is used, with 35% AM (acrylamide) and 25% AA (acrylic acid) as the main agents (by mass percentage), and 20% AMPS (2-acrylamido-2-methylpropanesulfonic acid), a temperature- and salt-resistant component, added. The mixture is stirred thoroughly at 200-500 rpm until all monomers are completely dissolved. Then, 20% MBA (NN-methylene acrylamide) is added as a crosslinking agent. The reaction is carried out fully and stably in a reactor at 60-80℃, copolymerizing to form a single-phase gel with an interpenetrating network molecular structure. After grinding with a colloid mill and physical cooling, stable and dispersed micron-sized gel particles are obtained. The high-strength single-phase microgel has a wide particle size distribution (40-300 micrometers), controllable and adjustable size, and good deep migration and penetration; the system viscosity is 20-40 mPa·s, with good on-site injection properties; temperature resistance reaches above 80℃, and salt resistance reaches 10×10⁻⁶. 4 mg / L, meeting the requirements of formation temperature and high salinity (formation temperature 60-80℃, formation water salinity 5×10 mg / L). 4 It has a concentration of approximately mg / L, stable and reliable performance, and a long shelf life; the expansion time is more than 7 days, the expansion ratio is 3 times, and it has good water absorption and slow expansion properties; the molecular structure design of the interpenetrating network makes the system compressive strength reach 0.8MPa, which is higher than that of water-swellable particles (0.53MPa), and it has excellent erosion resistance.

[0083] Among them, the 2-acrylamido-2-methylpropanesulfonic acid (AMPS) copolymer has extremely high property stability and thickening properties under high temperature and high salinity conditions. The addition of this component solves the requirements of high temperature and high salinity oil fields for the system's temperature and salt resistance performance.

[0084] Step 5: Closely monitor the changes in injection pressure during the plugging agent injection process and conduct tests after completing the designed injection volume of plugging agent.

[0085] The injection pressure rise of the water injection well exceeds 0.5 MPa (100m injection). 3 (Pluging agent), switch the water injection process according to the equal discharge rate (1.0-1.5m). 3 / h) Inject water to propel the plugging agent deeper into the formation. After the pressure drops and stabilizes, switch to the plugging agent injection process for normal plugging agent injection. After completing the designed injection volume of plugging agent, test the water absorption indicator curve and pressure drop curve after profile control to determine the water absorption and pressure changes. If the overall pressure rise reaches more than 60% of the pressure increase space, and the normal water injection pressure is not lower than the wellhead pressure after profile control, it can be considered that the fracture channel has been effectively sealed and fracture water channeling has been significantly suppressed.

[0086] Step Six: After the plugging agent injection, water absorption, and pressure drop tests are completed, and it is determined that the plugging has achieved its target, there is no need to shut in the well and wait for it to solidify. The water injection process can be resumed directly, and water injection can be resumed according to the geological injection plan.

[0087] Example 1: See Figures 4 to 8 The B402-45 well group has an average porosity of 12.1%, an average permeability of 0.38 mD, an effective reservoir thickness of 12.8 m, a reservoir temperature of 60-75℃, and a formation water salinity of 4.8 × 10⁻⁶. 4 The well pattern is a 480m x 130m diamond-shaped inverted nine-spot well pattern. Through core sampling, imaging logging, and tracer testing, it was found that the reservoir is located in a fractured zone with multidirectional natural microfractures, mainly "high-angle structural shear fractures". The fracture density is 0.76 fractures / meter, and the fracture orientation is mainly NE60°-90°, consistent with the direction of the maximum principal stress. The fracture width is 2-5 mm, with an average of 4 mm (statistics from regional geological outcrops, core sampling, etc.).

[0088] Well group B402-45 corresponds to 8 oil wells (B401-44, B402-44, B401-45, B401-46, B402-46, B403-44, B403-45, and B403-46), with a daily fluid production of 17.4 m³ before the adjustment and displacement. 3 The daily oil production was 4.2 tons with a water content of 75.8%. In August 2017, conventional profile control was adopted, which increased the pressure by 7.0 MPa, resulting in a cumulative increase of 240 tons of oil and a cumulative reduction of 310 cubic meters of water. However, the effect failed after 9 months, and the daily liquid production and overall water content increased again.

[0089] Of the oil wells in the well group, two wells (B401-44 and B402-44) encountered water, both affected by the B402-45 water injection well. Specifically: ① Well B401-44 was put into production on September 15, 2009, and maintained stable production for 43 months with low fluid production (1.24 cubic meters / day), low production (1.0 ton / day), and low water cut (around 20%). Starting in April 2013, water began to appear in the well, and the fluid production and water cut rapidly increased. By July 2019, daily fluid production reached over 4 cubic meters, daily oil production was around 0.6 tons, and water production exceeded 80%, after which it remained stable. ② Well B402-44 was put into production on December 24, 2009, and maintained stable production for 57 months with low fluid production (1.0 cubic meters / day), low production (0.88 tons / day), and low water cut (below 20%). In September 2014, the oil well fluid volume and water breakthrough increased sharply in a "step-like" manner, with the fluid volume reaching 7 cubic meters and the water cut approaching 100%, exhibiting characteristics of "sudden water flooding". The well group is located in a fractured area. Judging from the overall fracture development, distribution and orientation, well B401-44 is a fractured water breakthrough, and well B402-44 is a fractured water flood.

[0090] Based on the formula for calculating the dosage of plugging agent The parameters in the formula are as follows: fracture width c is 4 mm, fracture height h is 10.24 m (taken as the thickness of the oil layer perforation, generally 80% of the oil layer thickness), fracture plugging depth l is 160 m (for deep plugging, take 1 / 3 of the distance between oil and water wells), number of fractures n in the well group is 2, particle expansion coefficient M is 3, volume compressibility coefficient B is 0.7, solution concentration m is 0.5%, and loss through the perforation η is 50%. The calculated plugging agent dosage for the water injection well profile adjustment of this well group is 2520 cubic meters. The ratio of flexible high-strength long-lasting particle main plugging slug to micron-level high-strength single-phase microgel secondary filling plugging slug is 50%:50%, and the injection volume of each slug is 1260 cubic meters.

[0091] The well group underwent high-intensity, long-term, deep composite profile control in May 2021 and was completed in June 2021. The initial injection pressure after profile control was 15.0 MPa, increasing to 21.0 MPa, a pressure rise of 6.0 MPa, representing a 63.0% increase (with a pressure rise potential of 9.5 MPa). The pressure drop slowed, the water absorption indicator curve tilted to the left, and the water absorption situation improved. The well dynamics before and after profile control showed a significant improvement in the production dynamics of the wells within the well group. Among them, the daily fluid production of the water-bearing well B401-44 decreased by 0.9 cubic meters (3.5 cubic meters ↓ 2.6 cubic meters), while the daily oil production increased by 0.77 tons (0.76 tons ↑ 1.53 tons), and the overall water cut decreased by 37.6% (78.3% ↓ 40.7%); the daily fluid production of the water-flooded well B402-44 decreased by 1.83 cubic meters (6.59 cubic meters ↓ 4.76 cubic meters), while the daily oil production increased by 1.14 tons (0.43 tons ↑ 1.57 tons), and the overall water cut decreased by 37.6% (78.3% ↓ 40.7%). The overall water cut decreased by 26.5% (93.5% ↓ 67.0%); the remaining 6 low-yield wells saw an increase of 1.23 cubic meters of daily fluid production (6.32 cubic meters ↑ 7.55 cubic meters) and 0.97 tons of daily oil production (3.38 tons ↑ 4.35 tons), with an overall water cut decrease of 4.1% (46.5% ↓ 42.4%). The wells targeted for water control showed significant oil production increases, and wells that had previously shown no effect from water drive saw improvements in water drive performance, resulting in significant fluid and oil production increases. As of January 2023, the well group had achieved a daily oil production increase of 2.88 tons and a 19.8% decrease in overall water cut, maintaining normal production for 20 months (continuously effective), with a cumulative oil production increase of 510 tons and a cumulative water cut reduction of 730 cubic meters.

[0092] Compared with the previous conventional profile control, the pressure rise decreased by 1.0 MPa after profile control, the water injection pressure remained above 20.0 MPa (normal water injection is 13-15 MPa), the profile control period was extended by more than 11 months, the oil production and water reduction effects were significantly improved, and the deep migration and plugging, high strength and long-term plugging characteristics were obvious.

[0093] Example 2: See Figures 9 to 13 The C35-49 well group has an average porosity of 10.5%, an average permeability of 0.36 mD, an effective reservoir thickness of 15.2 m, a reservoir temperature of 55-70℃, and a formation water salinity of 5.2 × 10⁻⁶. 4 mg / L, the well pattern is a 480m x 150m diamond-shaped inverted nine-spot well pattern. Through core sampling and imaging logging, it was found that the reservoir has multi-directional natural microfractures with a fracture density of 0.98 fractures / meter. The fracture orientations are mainly NE70°, NE90°, and NE110°, and the fracture width is 2-5 mm, with an average of 4.5 mm (based on statistics from regional geological outcrops, core sampling, etc.).

[0094] The C35-49 well group corresponds to 7 oil wells (C34-49, C36-49, C34-48, C34-50, C35-48, C35-50, and C36-48), with a daily fluid production of 36.04 m³ before the hydraulic displacement adjustment. 3It produces 5.96 tons of oil per day, with a water content of 83.46%.

[0095] Of the oil wells in the well group, two wells (C34-49 and C36-49) encountered water. Their locations aligned with the fracture orientation, and the injection-production relationship was clear. Specifically: ① Well C34-49 was put into production on November 5, 2014. For the first 55 months, it maintained stable production with high fluid volume (8.2 cubic meters / day), high yield (2.9 tons / day), and medium water cut (around 55%). After June 2019, water was encountered in this well, causing a sharp increase in water cut (54.9% ↑ 86.6%) and a significant decrease in oil production (3.25 tons ↓ 1.2 tons). After five months of production, fluid volume surged again (7.8 cubic meters ↑ 12.9 cubic meters), slowly rising to around 14 cubic meters, with water cut exceeding 90%. This well experienced sudden water flooding. ② Well C36-49: Put into production on October 14, 2013, it maintained stable production for 33 months with high fluid volume (8.24 cubic meters / day), high yield (5.1 tons / day), and medium water cut (43%). From July 2016 to February 2020, the well encountered water, and the fluid volume (8.24 cubic meters ↓ 7.86 cubic meters) decreased slightly, while the oil yield (5.1 tons ↓ 3.86 tons) and water cut increased (43.8% ↑ 55.6%).

[0096] In March 2020, the well experienced a sudden water flooding, with the water cut rising sharply to 100% in a "step-like" manner, and the fluid volume reaching 10-15 cubic meters. Among the oil wells in the corresponding well group, the locations of the two water-bearing wells were consistent with the fracture orientation, and the injection and production responses were obvious, with the production dynamics showing fracture-induced sudden water flooding.

[0097] Based on the formula for calculating the dosage of plugging agent The parameters in the formula are as follows: fracture width c is 4.5 mm, fracture height h is 8.16 m (taken as the thickness of the oil layer perforation, generally 80% of the oil layer thickness), fracture plugging depth l is 160 m (for deep plugging, take 1 / 3 of the distance between oil and water wells), number of fractures n in the well group is 2, particle expansion coefficient M is 3, volume compressibility coefficient B is 0.7, solution concentration m is 0.6%, and loss through the perforation η is 50%. The calculated plugging agent dosage for the water injection well profile adjustment of this well group is 2780 cubic meters. The ratio of flexible high-strength long-lasting particle main plugging slug to micron-level high-strength single-phase microgel secondary filling plugging slug is 60%:40%. The injection volume of flexible high-strength long-lasting particle slug is 1670 cubic meters, and the injection volume of micron-level high-strength single-phase microgel slug is 1110 cubic meters.

[0098] This well group underwent high-intensity, long-term, deep composite profile control in October 2021 and was completed in November 2021. The initial injection pressure after profile control was 10.0 MPa, increasing to 15.0 MPa, a pressure increase of 5.0 MPa (62.5% increase, with a potential pressure increase of 8.0 MPa). The pressure drop slowed, the water absorption indicator curve tilted to the left, and after the dominant channel was blocked, the matrix was effectively displaced, improving water absorption. From the well dynamics before and after profile control, the key treated wells showed significant water control and oil production enhancement effects, wells within the well group that had previously shown no effect from water drive saw improvement in water drive performance, and the fluid extraction and oil production enhancement effects were significant, indicating improved displacement of oil wells within the well group. Among them, the daily fluid production of water-flooded well C34-49 decreased by 1.4 cubic meters (14.7 cubic meters ↓ 13.3 cubic meters), the daily oil production increased by 1.79 tons (0.98 tons ↑ 2.77 tons), and the overall water cut decreased by 14.1% (93.3% ↓ 79.2%); the daily fluid production of water-flooded well C36-49 decreased by 1.91 cubic meters (10.42 cubic meters ↓ 8.51 cubic meters), the daily oil production increased by 2.59 tons (0 tons ↑ 2.59 tons), and the overall water cut decreased by 30.4% (100% ↓ 69.6%); the remaining 5 low-yield wells saw a daily fluid production increase of 5.33 cubic meters (5.81 cubic meters ↑ 11.14 cubic meters), a daily oil production increase of 3.22 tons (4.88 tons ↑ 8.1 tons), and an overall water cut decrease of 3.2% (16.0% ↓ 12.8%). As of January 2023, the well group had increased oil production by 7.6 tons per day, with a 21.7% decrease in overall water cut. It had been in normal production for 16 months (continuously effective), with a cumulative increase of 610 tons of oil and a cumulative water reduction of 780 cubic meters.

[0099] Compared with the conventional profile control in the same block in the early stage, the pressure rise after profile control decreased by 1.5 MPa, the water injection pressure remained above 15.0 MPa (normal water injection is 9-10 MPa), the effective period of profile control was extended by more than 10 months, the oil production and water reduction effects were significantly improved, and the deep migration and plugging, high strength and long-term plugging characteristics were obvious.

[0100] As can be seen from the above description, the embodiments of the present invention achieve the following technical effects:

[0101] 1. By combining two systems, flexible elastic particles and single-phase microgel, the synergistic enhancement effect of high-strength and long-lasting slugs is achieved, which increases the pressure gradient in the deep formation, seals the water drive channels in the fractures, has strong resistance to water injection scouring, increases the oil pressure in the injection well, expands the low-permeability swept volume, activates the remaining oil in the low-permeability zone of the matrix, and improves the water drive effect of the reservoir.

[0102] 2. Conventional "weak gel plus water-swellable particles" composite plugging method is mainly used for adjusting the near-wellbore water intake profile of injection wells. Its adjustment distance is short, and it cannot effectively block the dominant water drive channels. The system also has weak temperature and salt resistance, is easily hydrolyzed and broken, resulting in a short effective time and short plugging period. In contrast, the "flexible elastic particles plus single-phase microgel" high-strength, long-lasting deep composite plugging method proposed in this invention has small plugging particle size (micrometers, millimeters), large deformation capacity (flexible elastic particle plugging agent elongation at break reaches 1000-1300%), strong deep migration and plugging performance, and a large plugging radius. It is temperature resistant (>80℃), salt resistant (fluid salinity >10×10⁴ mg / L), resistant to water injection erosion, and has a long effective time (good chemical stability >12 months, compressive strength >0.8 MPa). It can remain in the dominant channels of formation fractures for a long time, extending the effective period of water injection well plugging.

[0103] Table 1 Comparison of key performance indicators of major plugging agents used in different plugging methods

[0104]

[0105] Note: " / " indicates that this performance evaluation index is not available due to different system types.

[0106] 3. The "flexible elastic particles plus single-phase microgel" high-strength long-lasting deep composite plugging method proposed in this invention uses a single system of factory-prefabricated plugging agents, which can be directly pumped on-site according to construction requirements without the need for other components or liquid preparation. The construction is simple and easy to operate.

[0107] Obviously, the embodiments described above are merely some, not all, embodiments of the present invention. All other embodiments obtained by those skilled in the art based on the embodiments of the present invention without inventive effort should fall within the scope of protection of the present invention.

[0108] It should be noted that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments according to this application. As used herein, the singular form is intended to include the plural form as well, unless the context clearly indicates otherwise. Furthermore, it should be understood that when the terms "comprising" and / or "including" are used in this specification, they indicate the presence of features, steps, operations, devices, components, and / or combinations thereof.

[0109] It should be noted that the terms "first," "second," etc., used in the specification, claims, and accompanying drawings of this application are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments of this application described herein can be implemented in sequences other than those illustrated or described herein.

[0110] The above description is merely a preferred embodiment of the present invention and is not intended to limit the invention. Various modifications and variations can be made to the present invention by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A high-strength, long-lasting, deep composite plugging method for reducing the conductivity of fractures, characterized in that, Includes the following steps: Step 1: Determine the water breakage type of each water-bearing and water-flooded oil well in the well group. The determination criteria include the overall water cut of each oil well in the well group, production dynamics after commissioning, historical fluid production, water cut increase trend and change characteristics, and reservoir fracture development, distribution and orientation. Step 2: The dominant channel of the crack is simplified into a rectangular equivalent model, and the amount of plugging agent is calculated; Step 3: Inject water into the well group for testing, clear and pre-treat the fracture channels to be sealed, and record the water intake indicator curve and pressure drop curve of the corresponding injection well in the well group to be adjusted. Step 4: Deep composite plugging agent injection operation; Step 5: During the plugging agent injection process, monitor the changes in injection pressure and conduct tests after completing the designed injection volume of plugging agent; Step six: The test is completed and water injection production is resumed; The method used in step one to determine the water breakthrough and water flooding type of oil wells in the well group is as follows: If the overall water cut of one or more oil wells in the well group is greater than 80%, and the production dynamic curve shows a rapid and sharp increase in production volume and overall water cut during a certain period, followed by a sustained high production volume, high water cut, and water flooding production characteristic; combined with the fracture distribution and orientation, it can be determined that the water breakthrough and water flooding well is connected to the main fracture and is a fractured main direction oil well, and the water breakthrough type of the oil well is fractured water flooding; if the water cut rises rapidly and the oil well with high production volume and high water cut is connected to the secondary fracture and is a secondary fracture direction oil well, the water breakthrough type is fractured water breakthrough; In step two, when simplifying to a rectangular equivalent model, fractures and secondary fracture channels are regarded as the same rectangular model. The depth, width, and height of the main fracture and secondary fracture channels are equivalent to the length, width, and height of a rectangle. There are n dominant fracture channels in the well group, which are equivalent to n rectangular models. The volume of the fracture space that needs to be plugged is calculated, and the amount of plugging agent required is calculated based on the characteristics of the plugging agent. In step four, the plugging slugs are divided into two levels: millimeter-sized flexible, high-strength, long-lasting particle primary plugging slugs and micron-sized high-strength single-phase microgel secondary filling plugging slugs. During extrusion, the millimeter-sized flexible, high-strength, long-lasting particle primary plugging slugs are injected first, followed by the micron-sized high-strength single-phase microgel secondary filling plugging slugs. The millimeter-sized flexible, high-strength, long-lasting particles are used to form physical baffles to cut off the water-drive channels of the cracks. The micron-sized high-strength single-phase microgel is used to fill and seal the gaps between the particles of the former plugging slugs, supplementing and reinforcing the former plugging slugs.

2. The high-strength, long-lasting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that, In step two, the amount of sealant required to seal the dominant channel of the crack is calculated based on the rectangular equivalent model. The calculation formula is as follows: ； In the formula: V----Dosage of plugging agent, in meters 3 ; c----crack width, in meters; h----Crack height, in meters; l----Crack sealing depth, in meters; n----Number of fractures in the well group, in units of fractures; M----Coefficient of particle swelling when exposed to water; B----Volume compressibility coefficient; m----solution concentration; η----Loss through the blast hole.

3. The high-strength, long-lasting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that, In step three, the water intake indicator curve and pressure drop curve of the injection well corresponding to the proposed profile control well group are taken, and water is injected using pumps with different discharge rates. The wellhead pressure is recorded, and the relationship curve between discharge rate and wellhead pressure is plotted. When recording the pressure drop curve, water is injected into the injection well pump. When the wellhead pressure reaches a stable state, the pump is stopped. The wellhead pressure value is recorded at fixed time intervals, and the relationship curve between time and wellhead pressure value is plotted.

4. The high-strength, long-lasting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that, The ratio of the total injection volume of the main plugging segment to the secondary filling plugging segment is controlled to be greater than or equal to 1 and less than or equal to 1.

2.

5. The high-strength, long-lasting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that, In step five, if the injection pressure in the injection well rises above 0.5 MPa, the injection process is switched to inject water at the same rate to push the plugging agent to move deeper into the formation. After the pressure drops and stabilizes, the process is switched back to the plugging agent squeezing injection process for normal plugging agent injection.

6. The high-strength, long-lasting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that, In step five, after completing the designed injection volume of the plugging agent, the water absorption indicator curve and pressure drop curve after profile adjustment are tested. Based on the changes in water absorption and pressure, it is determined whether the crack channel is effectively sealed.

7. The high-strength, long-lasting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that, In step six, after the plugging agent injection, water absorption, and pressure drop tests are completed and the plugging target is achieved, there is no need to shut in the well and wait for it to solidify. The water injection process can be directly resumed, and water injection can be resumed according to the geological injection plan.

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