High-strength long-acting deep composite plugging method for reducing fracture conductivity

Abstract

The invention provides a high-strength long-acting deep composite plugging method for reducing fracture conductivity. The high-strength long-acting deep composite plugging method includes the following steps that firstly, water breakthrough types of all water breakthrough and water breakthrough types of water-flooded producing wells of well groups are judged; step 2, simplifying a fracture dominant channel into a rectangular equivalent model, and calculating the dosage of a plugging agent; 3, well group injection water injection test is carried out, a crack channel to be plugged is dredged and preprocessed, and a water injection well water absorption indication curve and a pressure drop curve corresponding to the well group to be subjected to profile control are recorded; step 4, squeezing and injecting the deep composite plugging agent; 5, in the plugging agent squeezing process, attention is paid to the injection pressure climbing change, and testing is conducted after the plugging agent designed injection amount is completed; and 6, testing is finished, and water injection production is recovered. According to the high-strength long-acting deep composite plugging control method capable of reducing the flow conductivity of the cracks, the problems that in the prior art, high-strength long-acting plugging of the deep portions of the stratum cracks is difficult to achieve, the plugging control effect of a water injection well is affected, and water logging capacity is released can be solved.

Description

Technical Field

[0001] The present invention relates to the technical field related to oilfield development, and in particular to a high-strength, long-acting, deep composite plugging method for reducing fracture conductivity. Background Art

[0002] Domestic onshore low- to ultra-low-permeability reservoirs are dense, highly heterogeneous, and rich in natural microfractures. They are generally developed using a "fracturing production + water injection" approach. As water injection development progresses, the injected water channels the natural microfractures within the reservoir itself, as well as the artificial fracture network in the oil wells, forming a dominant water drive channel. This leads to ineffective circulation of the subsequently injected water, exacerbating the heterogeneity of the injection well profile and causing premature and rapid water breakthrough and flooding in the main wells. This leads to a continuous waterline in the dominant direction of the oil and water wells within the well group, manifesting as obvious fracture-related water breakthrough (water flooding).

[0003] Practice has proven that using water injection wells to control the water drive channels in micro-fractures of the reservoir, reduce the conductivity of the fractures, and expand the subsequent water drive sweep volume is an important technical measure to improve the effectiveness of water drive development and achieve water control and oil stabilization in mature oil fields. However, conventional profile control materials, such as weak gels with high initial viscosity and large bulk particle size (close to centimeters), result in poor injectability and short migration distances; the system has weak temperature and salt resistance, is easily hydrolyzed and broken, and the profile control fails; the strength is low, it is not resistant to erosion, the retention stability is weak, and the effective period of profile control is short. In terms of profile control technology, due to the large scale, high viscosity, and low strength of the system, it can only achieve flow diversion in the near-wellbore area, making it difficult to achieve deep profile control in the reservoir, and the expansion of the water drive sweep range is limited, and the effect of multiple rounds of profile control deteriorates. Improper use of strong gels can easily cause the wellbore to be "stuffed with sausages", consolidating the tubing, and posing a high safety risk in construction. For example, the invention patent for a deep profile control method for fractured oil reservoirs with application number 201010262239.8 uses four plugs consisting of a high-strength curing system, inorganic gel, water drive flow direction changer (bulk-swelling particles, clay) + weak gel, and strong gel YQY plugging agent to adjust the water absorption profile near the wellbore of the injection well; the invention patent for a profile control method for sealing through cracks with a multi-plug combination with application number 201910733209.1 uses a water-swelling particle temporary plugging agent to bridge and temporarily plug the cracks, and seal the through cracks near the wellbore.

[0004] However, due to the performance 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 flooding production capacity, making it difficult to improve the recovery rate of oil reservoirs. Summary of the Invention

[0005] The main purpose of the present invention is to provide a high-strength, long-acting, deep composite plugging method for reducing fracture conductivity. The purpose is to seal the water breakthrough channel of the fracture through the synergistic enhancement effect of small-particle, high-strength, long-acting composite plugs, control water breakthrough in oil well fractures, promote matrix displacement of injected water, restore water breakthrough and water-flooding production capacity of oil wells, tap the potential of residual oil in the matrix, and improve the recovery rate of oil reservoirs.

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

[0007] Step 1: determine the water breakthrough type of each water breakthrough well and water-flooded oil production well in the well group;

[0008] Step 2: Simplify the fracture dominant channel into a rectangular equivalent model and calculate the plugging agent dosage;

[0009] Step 3: Test water injection into the well group to dredge and pre-treat the fracture channels to be blocked, and record the water absorption indicator curve and pressure drop curve of the injection wells corresponding to the planned profile control well group;

[0010] Step 4: deep compound plugging agent squeezing operation;

[0011] Step 5: Pay attention to the injection pressure rise during the plugging agent squeezing process and test after completing the designed plugging agent injection volume;

[0012] Step 6: The test is completed and water injection production is resumed.

[0013] Furthermore, the basis for judging the water breakthrough type of each well group and water-flooded oil production well in step 1 includes the comprehensive water content of each oil production well in the well group, production dynamics after production, historical liquid production, water content rising trend and change characteristics, and reservoir fracture development, distribution and orientation.

[0014] Furthermore, the method used in step 1 to determine the water breakthrough and water-flooding type of oil wells in the well group is as follows: if the comprehensive water cut of one or several oil production wells in the well group is greater than 80%, the liquid production and comprehensive water cut rise rapidly and sharply, or even steeply, within a certain time period of the production dynamic curve, showing an obvious "step-like" feature, and then maintain high liquid volume, high water cut, and water-flooded production characteristics; combined with the distribution and orientation of the fractures, it can be determined that the water breakthrough and water-flooded well is connected to the main fracture, and is a main fracture direction oil production well, and the water breakthrough type of the oil well is fracture-induced water flooding; the oil well with a rapid increase in water cut, high liquid volume, and high water cut production is connected to the secondary fracture, and is a secondary fracture direction oil production well, and the water breakthrough type is fracture-induced water breakthrough.

[0015] Furthermore, the basis for judging the water breakthrough type of each well group and water-flooded oil production well in step 1 includes the comprehensive water content of each oil production well in the well group, production dynamics after production, historical liquid production, water content rising trend and change characteristics, and reservoir fracture development, distribution and orientation.

[0016] Furthermore, in step 2, when simplifying to a rectangular equivalent model, the fractures and secondary fracture channels are regarded as the same rectangular model, and the depth, width, and height of the primary 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 required amount of plugging agent is converted according to the characteristics of the plugging agent.

[0017] Furthermore, in step 2, the amount of plugging agent required to plug the dominant channel of the crack is calculated based on the rectangular equivalent model. The calculation formula is:

[0018]

[0019] Where:

[0020] V----the amount of plugging agent, in m 3 ;

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

[0022] h----crack height, in m;

[0023] l----crack sealing depth, in m;

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

[0025] M----coefficient of particle expansion when exposed to water;

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

[0027] m----solution preparation concentration;

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

[0029] Furthermore, in step three, the water absorption indication curve and pressure drop curve of the injection well corresponding to the proposed profile control well group are obtained, water is injected by pumping with different displacement rates, the wellhead pressure is recorded, and a displacement-wellhead pressure change relationship curve is drawn; when the pressure drop curve is recorded, water is pumped into the injection well, and the pump is stopped when the wellhead pressure reaches a stable state. The wellhead pressure value is recorded at fixed time intervals, and a time-wellhead pressure value relationship curve is drawn.

[0030] Furthermore, in step four, the plugging section is divided into two levels: millimeter-level flexible, elastic, high-strength and long-lasting granular main plugging section and micron-level high-strength single-phase microgel secondary filling plugging section; during injection, the millimeter-level flexible, elastic, high-strength and long-lasting granular main plugging section is injected first, and then the micron-level high-strength single-phase microgel secondary filling plugging section is injected.

[0031] Furthermore, the overall injection volume ratio of the primary plugging segment and the secondary filling plugging segment is controlled to be greater than or equal to 1 and less than or equal to 1.2.

[0032] Furthermore, in step five, if the injection pressure of the water injection well rises to more than 0.5 MPa, the water injection process is switched to inject water at an equal displacement rate to push the plugging agent to migrate deep into the formation. After the pressure drops and stabilizes, the plugging agent is switched to the plugging agent squeezing process to squeeze the plugging agent normally.

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

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

[0035] The technical solution of the present invention is applied:

[0036] 1. Through the combination of soft elastic particles and single-phase microgel, the synergistic enhancement effect of high-strength and long-lasting plugs is exerted to increase the pressure gradient in the deep formation, block the water drive channels through the fractures, have strong resistance to water injection erosion, increase the oil pressure of the water injection well, expand the low-permeability swept volume, activate the remaining oil in the low-permeability area of ​​the matrix, and improve the water drive effect of the reservoir.

[0037] 2. The "soft elastic particles plus single-phase microgel" high-strength and long-lasting deep composite plugging method proposed in the present invention has a small plugging agent particle size, large deformation ability, strong deep migration and plugging performance, and a large plugging radius. It is resistant to temperature, salt, and water injection erosion, has a long effective action time, and can reside for a long time in the advantageous channels of formation fractures, thereby extending the effective period of water injection well plugging.

[0038] 3. The high-strength, long-lasting deep composite plugging method of "soft elastic particles plus single-phase microgel" proposed in the present invention uses a single system of plugging agents prefabricated in the factory. It is directly pumped on site according to construction requirements, without the need to carry other components or mix liquids. The construction is simple and easy to operate. BRIEF DESCRIPTION OF THE DRAWINGS

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

[0040] Figure 1 A flow chart of a high-strength, long-acting, deep composite plugging method for reducing fracture conductivity in this embodiment is shown;

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

[0042] Figure 3 A schematic diagram of a high-strength, long-acting, deep composite plugging method for reducing fracture conductivity in water injection wells is shown;

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

[0044] Figure 5 The water absorption indicator curve of B402-45 water injection well before and after profile adjustment is shown;

[0045] Figure 6 The production performance curve of the fractured water-seeping oil well B401-44 in the B402-45 well group is shown;

[0046] Figure 7 The production performance curve of the fractured water-flooded oil well B402-44 corresponding to the B402-45 well group is shown;

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

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

[0049] Figure 10 The water absorption indicator curve of C35-49 water injection well before and after profile adjustment is shown;

[0050] Figure 11 The production performance curve of the fractured water-flooded well C34-49 corresponding to the C35-49 well group is shown;

[0051] Figure 12 The production performance curve of the fractured water-flooded well C36-49 in the C35-49 well group is shown;

[0052] Figure 13 The production performance curves of the remaining five oil producing wells in the C35-49 well group are shown. DETAILED DESCRIPTION

[0053] It should be noted that, in the absence of conflict, the embodiments and features of the embodiments in this application can be combined with each other. The present invention will be described in detail below with reference to the accompanying drawings and in combination with the 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 ordinary technicians in the technical field to which this application belongs.

[0055] In the present invention, unless otherwise specified, the directional words used, such as "up, down, top, bottom", usually refer to the directions shown in the drawings, or to the components themselves in the vertical, perpendicular or gravity direction; similarly, for ease of understanding and description, "inside and outside" refer to the inside and outside relative to the outline of each component itself, but the above directional words are not used to limit the present invention.

[0056] In order to solve the problem in the prior art that it is difficult to achieve high-strength and long-term plugging of deep formation fractures, which affects the plugging effect of water injection wells and the release of water-flooding production capacity, the present invention provides a high-strength and long-term deep composite plugging method for reducing the conductivity of fractures. The purpose is to plug the water breakthrough channels in the fractures through the synergistic enhancement effect of small-particle high-strength and long-term composite plugs, control water breakthrough in oil well fractures, promote matrix displacement of injected water, restore water breakthrough and water-flooding production capacity of oil wells, tap the potential of residual oil in the matrix, and improve the recovery rate of oil reservoirs.

[0057] Example 1

[0058] like Figures 1 to 3 As shown, a high-strength, long-acting, deep composite plugging method for reducing fracture conductivity comprises the following steps:

[0059] Step 1: Determine the water breakthrough type of each water-breaking and water-flooded oil production well in the well group based on the comprehensive water content of each oil production well in the well group, production performance after commissioning, historical liquid production, water cut rising trend and change characteristics, reservoir fracture development, distribution and orientation, etc.

[0060] If the comprehensive water cut of one or more production wells within a well group exceeds 80%, the production performance curve will show a rapid and sharp increase in liquid production and comprehensive water cut within a certain period of time, even a steep rise, showing a clear "step-like" characteristic, and then maintain high liquid production, high water cut, and water-flooded production characteristics. Combined with the distribution and orientation of the fractures, it can be determined that the water-seeking (water-flooded) well is connected to the main fracture direction, indicating that it is a main fracture-directed production well and the water breakthrough type of the oil well is fracture-induced water flooding. Oil wells with a rapid increase in water cut, high liquid production, and high water cut are connected to secondary fractures and are secondary fracture-directed production wells and the water breakthrough type is fracture-induced water breakthrough.

[0061] Step 2: Simplify the dominant fracture channel into a rectangular equivalent model and calculate the plugging agent dosage.

[0062] Primary and secondary fracture channels are treated as identical rectangular models, with their depth, width, and height equivalent to the length, width, and height of the rectangle. If there are n dominant fracture channels within a well group, this is equivalent to n rectangular models. Calculate the volume of the fracture space to be plugged and convert the required plugging agent dosage based on its properties.

[0063] Considering factors such as the expansion ratio of the plugging agent system when it comes into contact with water, volume compression characteristics, and loss through the blasthole, the following formula is used to calculate the plugging agent dosage:

[0064]

[0065] Where: V----the amount of plugging agent, unit is m 3 ;

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

[0067] h----fracture height (the perforation thickness of the oil layer, generally 80% of the oil layer thickness), in meters;

[0068] l----fracture plugging depth (for deep plugging, take 1 / 4 to 1 / 3 of the distance between oil and water wells), unit is m;

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

[0070] M----the coefficient of expansion of particles when exposed to water, generally 3;

[0071] B----Volume compression coefficient, generally takes a value of 0.7;

[0072] m----solution preparation concentration;

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

[0074] Step 3: Test water injection for the well group. Test water injection of 30-50 cubic meters into the corresponding injection wells of the well group to dredge and pre-treat the fracture channels to be blocked. Record the water absorption indicator curve and pressure drop curve of the injection wells corresponding to the proposed profile control well group. Pump water at a displacement of 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, and 70 cubic meters per day, record the wellhead pressure, and draw a displacement-wellhead pressure change relationship curve. When recording the pressure drop curve, pump water into the injection well. Stop the pump 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 draw a time-wellhead pressure value relationship curve.

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

[0076] See also Figure 2 and Figure 3 , adopting the idea of ​​"combination of large and small, matching of strong and weak, and synergistic enhancement", the plugging sections are divided into two levels: millimeter-level (2-4mm) flexible, high-strength and long-lasting granular main plugging sections and micron-level (40-300 microns) high-strength single-phase microgel secondary filling plugging sections.

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

[0078] The main function of the millimeter-scale flexible, elastic, high-strength and long-lasting particles is to utilize their excellent flexible and elastic deformation ability and high compressive resistance to penetrate deep into the formation, form a "physical partition", and cut off the fracture water drive channel; the main function of the micron-scale high-strength single-phase microgel is to fill and plug the gaps between the particles of the former plug, supplement and strengthen the former plug, make the overall plugging plug more compact, improve the plugging strength, resist the impact of subsequent water drive, promote subsequent water drive turbulence, and expand the affected volume.

[0079] In order to avoid excessive displacement and water injection intensity, which may cause pressure surge in low water-cut oil wells in the well group and increase water cut, so that the plugging agent can enter the deep reservoir and the injection pressure can rise slowly, and in order to leave room for pressure increase for subsequent measures, the water injection test adopts low displacement (1.0-1.5m 3 / h) injection, and small slugs (50-100m 3 ), low displacement (1.0-1.5m 3 / h), the primary and secondary slugs are injected alternately in a cycle.

[0080] Millimeter-level flexible, high-strength, long-lasting granular plugging agent: 60% of thermoplastic vulcanized rubber TPV, 30% of thermoplastic elastomer TPES, and 10% of SEBS-g-MAH are added to a mixing machine by mass percentage. Mix at a mixing temperature of 175-185°C for 5-15 minutes, then hot-press at 155-165°C and a pressure of 5-10 MPa for 5-20 minutes. After natural cooling, the mixture is peeled and granulated, and then cooled physically by water cooling. The finished product is white columnar particles with a particle size of 2-4 mm and a density of 0.95-1.1 g / cm 3 , elastic modulus is 1.5~4.0MPa, deformation capacity (elongation at break) is 1000-1300%, heat resistance (above 80℃) and salt resistance (10×10 4 mg / L), compressive strength above 1.0 MPa, thermal stability up to 24 months (80℃, 10×10 4 mg / L sodium chloride environment). The plugging agent material has good toughness, high compressive strength, strong deformation ability and good chemical stability.

[0081] Among them: the thermoplastic vulcanized rubber is a block copolymer with a structure of (PBA)150(PMMA)100(PBA)150; the thermoplastic elastomer is a blend of a copolymer of isoprene and low-density polyethylene and the 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 the maleic anhydride is a thermoplastic elastomer obtained by hydrogenating a styrene-butadiene-styrene block copolymer.

[0082] Micron-sized, high-strength, single-phase microgel particle plugging agent: Using a reverse suspension polymerization method, the main agents are 35% AM (acrylamide) and 25% anionic monomer AA (acrylic acid), calculated by mass percentage. 20% of the temperature-resistant and salt-tolerant component AMPS (2-acrylamido-2-methylpropanesulfonic acid) is added. The mixture is stirred thoroughly at 200-500 rpm until the monomers are completely dissolved. 20% of MBA (NN-methylene acid acrylamide) is added as a crosslinker. The mixture is fully and stably reacted in a reactor at a temperature of 60-80°C to copolymerize into a single-phase gel with an interpenetrating network molecular structure. After grinding in a colloid mill and physical cooling, stably dispersed micron-sized gel particles are obtained. The high-strength, single-phase microgel has a wide particle size distribution (40-300 microns), controllable and adjustable size, and good deep migration and penetration. The system viscosity is 20-40 mPa·s, which provides good on-site injectability. It is temperature-resistant to over 80°C and salt-resistant to 10×10 4 mg / L, meeting the conditions of formation temperature and high salinity (formation temperature 60-80℃, formation water salinity of 5×10 4 mg / L), with stable and reliable performance and long validity period; expansion time of more than 7 days, expansion multiple of 3 times, and good water absorption and slow expansion; the interpenetrating network molecular structure design, the system compressive strength reaches 0.8MPa, which is higher than that of water-expanded particles (0.53MPa), and has excellent anti-scouring performance.

[0083] Among them: 2-acrylamide-2-methylpropanesulfonic acid (AMPS) copolymer has extremely high property stability and viscosity increasing properties under high temperature and high salinity conditions. Adding this component can meet the requirements of high temperature and high salinity oil fields for the system's temperature and salt resistance.

[0084] Step 5: Pay close attention to the injection pressure rise during the plugging agent injection process and complete the test after the designed plugging agent injection volume is completed.

[0085] The injection pressure of the injection well is greater than 0.5MPa (100m 3 Plugging agent), switch the water injection process according to the equal displacement (1.0-1.5m 3 / h) water injection to push the plugging agent deeper into the formation. After the pressure drops and stabilizes, the plugging agent extrusion process is switched to normal injection. After the designed plugging agent injection volume is completed, the water absorption indicator curve and pressure drop curve after profile control are tested to determine the water absorption and pressure changes. If the overall pressure increase reaches more than 60% of the pressure increase space and the normal water injection pressure is no less than the wellhead pressure after profile control, the fracture channel can be considered effectively blocked and fracture water channeling is significantly suppressed.

[0086] Step 6: After the plugging agent squeezing, water absorption and pressure drop tests are completed, if it is determined that the plugging has achieved the target, there is no need to shut down the well and wait for solidification. The water injection process can be directly resumed according to the geological injection method.

[0087] Example 1: See Figures 4 to 8 , B402-45 well group, the average porosity of the reservoir is 12.1%, the average permeability is 0.38mD, the effective reservoir thickness is 12.8m, the oil layer temperature is 60-75℃, and the formation water salinity is 4.8×10 4 mg / L, developed using a 480m x 130m diamond-shaped inverted nine-spot pattern. Core drilling, imaging logging, and tracer testing revealed that the reservoir is located in a fracture-rich zone. Natural microfractures are multi-directional, primarily high-angle structural shear fractures, with a density of 0.76 fractures per meter. Fracture orientations are primarily NE 60°-90°, consistent with the direction of maximum principal stress. Fracture widths range from 2 to 5 mm, with an average of 4 mm (based on regional field geological outcrops and core drilling observations).

[0088] The B402-45 well group includes eight oil wells (B401-44, B402-44, B401-45, B401-46, B402-46, B403-44, B403-45, and B403-46). The daily fluid production before flooding was 17.4 m3. 3 , with a daily oil production of 4.2 tons and a water cut of 75.8%. In August 2017, conventional profile control was implemented, resulting in a pressure increase of 7.0 MPa, a cumulative increase in oil production of 240 tons, and a cumulative water reduction of 310 cubic meters. However, after nine months of effectiveness, the control failed, and the daily liquid production and comprehensive water cut increased again.

[0089] Among the oil wells in the well group, two have water penetration (B401-44 and B402-44), both of which are affected by the B402-45 water injection well. Well B401-44, which was put into production on September 15, 2009, maintained stable production with low liquid volume (1.24 cubic meters / day), low production (1.0 tons / day), and low water cut (approximately 20%) for 43 months. Starting in April 2013, the well began to see water, with liquid volume and water cut rapidly increasing. By July 2019, daily liquid production reached over 4 cubic meters, daily oil production was approximately 0.6 tons, and water penetration exceeded 80%. It has remained stable since then. Well B402-44, which was put into production on December 24, 2009, maintained stable production with low liquid volume (1.0 cubic meters / day), low production (0.88 tons / day), and low water cut (below 20%) for 57 months. In September 2014, the well's fluid volume and water breakthrough experienced a sudden, step-like rise, reaching 7 cubic meters and a water cut approaching 100%, demonstrating characteristics of "violent water flooding." The well group is located in an area with well-developed fractures. Based on the overall fracture development, distribution, and orientation, Well B401-44 experienced fracture-induced water breakthrough, while Well B402-44 experienced fracture-induced water flooding.

[0090] According to the calculation formula of plugging agent dosage Wherein the parameters are: fracture width c is 4 mm, fracture height h is 10.24 m (the perforated thickness of the oil layer is taken as the value, generally 80% of the oil layer thickness), fracture plugging depth l is 160 m (1 / 3 of the oil and water well spacing for deep plugging), number of fractures n in the well group is 2, particle water expansion coefficient M is 3, volume compression coefficient B is 0.7, solution concentration m is 0.5%, and through-hole loss η is 50%. The calculated amount of plugging agent required for profile control of the water injection wells in this well group is 2520 cubic meters, the main plugging segment of flexible, high-strength and long-lasting particles is 50%:50% of the secondary plugging segment of micron-sized, high-strength, single-phase microgel, and the injection volume of each segment is 1260 cubic meters.

[0091] This well group underwent a high-strength, long-lasting, deep composite profile control operation in May 2021, and the wells were completed in June 2021. The initial injection pressure was 15.0 MPa, and the post-profiling injection pressure reached 21.0 MPa, resulting in a 6.0 MPa pressure increase, a 63.0% increase (9.5 MPa of headroom). The pressure drop slowed, and the water absorption indicator curve tilted leftward, indicating improved water absorption. The well performance before and after the profile control operation showed a significant improvement in the production performance of the wells within the group. Among them, the daily liquid production of water well B401-44 decreased by 0.9 cubic meters (3.5 cubic meters ↓ 2.6 cubic meters), the daily oil production increased by 0.77 tons (0.76 tons ↑ 1.53 tons), and the comprehensive water content decreased by 37.6% (78.3% ↓ 40.7%); the daily liquid production of flooded well B402-44 decreased by 1.83 cubic meters (6.59 cubic meters ↓ 4.76 cubic meters), the daily oil production increased by 1.14 tons (0.43 tons ↑ 1.57 tons), and the comprehensive water content decreased by 37.6% (78.3% ↓ 40.7%). The total water cut decreased by 26.5% (93.5% down to 67.0%). The remaining six low-yielding wells saw daily fluid production increase by 1.23 cubic meters (6.32 cubic meters up to 7.55 cubic meters), daily oil production by 0.97 tons (3.38 tons up to 4.35 tons), and a 4.1% decrease in the overall water cut (46.5% down to 42.4%). Key treatment wells achieved significant results in water control and oil production increases. Wells within the well group that had been ineffective with long-term water flooding improved their water flooding, resulting in significant results in fluid and oil production increases. As of January 2023, the well group had increased daily oil production by 2.88 tons, and the overall water cut had decreased by 19.8%. The group has maintained normal production for 20 months (with sustained effectiveness), with a cumulative increase of 510 tons of oil production and a cumulative reduction of 730 cubic meters of water.

[0092] Compared with the previous conventional profile adjustment, the pressure climb dropped by 1.0MPa after profile adjustment, and the water injection pressure continued to remain above 20.0MPa (normal water injection is 13-15MPa). The effective period of profile adjustment was extended by more than 11 months, and the effect of increasing oil production and reducing water consumption was significantly improved. The characteristics of deep migration and plugging, high strength and long-term plugging were obvious.

[0093] Example 2: See Figures 9 to 13 , C35-49 well group, the average porosity of the reservoir is 10.5%, the average permeability is 0.36mD, the effective reservoir thickness is 15.2m, the oil layer temperature is 55-70℃, and the formation water salinity is 5.2×10 4 mg / L, developed using a 480m x 150m diamond-shaped inverted nine-spot pattern. Core sampling and imaging logging revealed multi-directional natural microfractures throughout the reservoir, with a density of 0.98 fractures per meter. Fracture orientations are primarily NE70°, NE90°, and NE10°, with widths ranging from 2 to 5 mm, averaging 4.5 mm (based on regional field geological outcrops and core sampling).

[0094] The C35-49 well group includes seven oil wells (C34-49, C36-49, C34-48, C34-50, C35-48, C35-50, and C36-48). The daily liquid production before flooding was 36.04 m3. 3, daily oil production is 5.96t, with a water content of 83.46%.

[0095] Among the oil wells in the well group, two (C34-49 and C36-49) have water production. Their locations align with the fracture trends, and the injection-production relationship is clearly aligned. Well C34-49, which began production on November 5, 2014, maintained stable production with high liquid volumes (8.2 cubic meters per day), high production (2.9 tons per day), and a moderate water cut (approximately 55%) for 55 months. After June 2019, the well experienced water production, with a sharp increase in water cut (54.9% to 86.6%) and a significant decrease in oil production (3.25 tons to 1.2 tons). Five months after production, the liquid volume increased sharply (7.8 cubic meters to 12.9 cubic meters), slowly rising to approximately 14 cubic meters, with a water cut exceeding 90%, resulting in sudden waterlogging. Well C36-49: Commissioned on October 14, 2013, it maintained stable production for 33 months, with high liquid volume (8.24 cubic meters / day), high production (5.1 tons / day), and a medium water cut (43%). From July 2016 to February 2020, the well experienced water breakthrough, resulting in a slight decrease in liquid volume (8.24 cubic meters down to 7.86 cubic meters), an increase in oil production (5.1 tons down to 3.86 tons), and an increase in water cut (43.8% up to 55.6%).

[0096] In March 2020, the well experienced sudden waterlogging, with the water cut rising sharply to 100% in a "step-like" pattern, with liquid volumes reaching 10-15 cubic meters. Two wells in the corresponding well group that experienced waterlogging were located in the same direction as the fractures, and showed a clear injection-production response, indicating that production dynamics were characterized by sudden waterlogging related to the fractures.

[0097] According to the calculation formula of plugging agent dosage Wherein the parameters are: fracture width c is 4.5 mm, fracture height h is 8.16 m (the perforated thickness of the oil layer is taken as the value, generally 80% of the oil layer thickness), fracture plugging depth l is 160 m (1 / 3 of the oil and water well spacing for deep plugging), number of fractures n in the well group is 2, particle water expansion coefficient M is 3, volume compression coefficient B is 0.7, solution concentration m is 0.6%, and through-hole loss η is 50%. The calculation results show that the required plugging agent dosage for profile control of the water injection wells in this well group is 2780 cubic meters, the ratio of the flexible, high-strength, long-lasting granular primary plugging slug to the micron-sized, high-strength, single-phase microgel secondary filling plugging slug is 60:40, the injection volume of the flexible, high-strength, long-lasting granular slug is 1670 cubic meters, and the injection volume of the micron-sized, high-strength, single-phase microgel slug is 1110 cubic meters.

[0098] This well group underwent a high-strength, long-lasting, deep composite profile control in October 2021, and was completed in November 2021. The initial injection pressure for the profile control was 10.0 MPa, and the injection pressure after the profile control reached 15.0 MPa. The pressure climbed by 5.0 MPa, a 62.5% increase (with 8.0 MPa of headroom), with a slowing pressure drop and a leftward tilt in the water absorption curve. After the dominant channel was blocked, the matrix was effectively displaced, and water absorption improved. Judging from the well performance before and after the profile control, the key treatment wells achieved significant water control and oil production increases. Wells within the group where long-term water flooding had failed saw improvements in water flooding, and significant results were achieved in fluid injection and oil production increases. The displacement of the wells within the group improved. Among them, the daily liquid production of 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 comprehensive water cut decreased by 14.1% (93.3% ↓ 79.2%); the daily liquid production of 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 comprehensive water cut decreased by 30.4% (100% ↓ 69.6%); the daily liquid production of the remaining five low-yield wells increased by 5.33 cubic meters (5.81 cubic meters ↑ 11.14 cubic meters), the daily oil production increased by 3.22 tons (4.88 tons ↑ 8.1 tons), and the comprehensive water cut decreased by 3.2% (16.0% ↓ 12.8%). As of January 2023, the well group has increased its daily oil production by 7.6 tons and its comprehensive water content has decreased by 21.7%. It has been in normal production for 16 months (continuously effective), with a cumulative increase of 610 tons in oil production and a cumulative reduction of 780 cubic meters in water content.

[0099] Compared with the conventional profile control in the same block in the early stage, the pressure climb dropped by 1.5MPa after profile control, and the water injection pressure continued to remain above 15.0MPa (normal water injection is 9-10MPa). The effective period of profile control was extended by more than 10 months, the effect of increasing oil production and reducing water consumption was significantly improved, and the characteristics of deep migration and plugging, high strength and long-term plugging were obvious.

[0100] From the above description, it can be seen that the above embodiments of the present invention achieve the following technical effects:

[0101] 1. Through the combination of soft elastic particles and single-phase microgel, the synergistic enhancement effect of high-strength and long-lasting plugs is exerted to increase the pressure gradient in the deep formation, block the water drive channels through the fractures, have strong resistance to water injection erosion, increase the oil pressure of the water injection well, expand the low-permeability swept volume, activate the remaining oil in the low-permeability area of ​​the matrix, and improve the water drive effect of the reservoir.

[0102] 2. Conventional "weak gel plus water-expanded particles" composite plugging method is mainly used to adjust the water absorption profile near the wellbore of water injection wells. The profile adjustment range is short and it cannot effectively block the dominant water drive channel. The system has weak temperature and salt resistance, is easily hydrolyzed and broken, and has a short effective action time and a short effective period of water drive. In comparison, the "soft elastic particles plus single-phase microgel" high-strength and long-lasting deep composite plugging method proposed in this invention has a small plugging agent particle size (micrometer and millimeter levels), a large deformation capacity (the elongation at break of the soft elastic particle plugging agent reaches 1000-1300%), strong deep migration and plugging performance, and a large plugging radius. It is also heat-resistant (>80°C) and salt-resistant (fluid salinity>10×104mg / L), resistant to water injection erosion, and has a long effective action time (good chemical stability>12 months, compressive strength>0.8MPa). It can reside in the dominant channel of the formation fracture for a long time, extending the effective period of water injection well plugging.

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

[0104]

[0105] Note: “ / ” indicates that there is no performance evaluation index due to different system types.

[0106] 3. The high-strength, long-lasting deep composite plugging method of "soft elastic particles plus single-phase microgel" proposed in the present invention uses a single system of plugging agents prefabricated in the factory. It is directly pumped on site according to construction requirements, without the need to carry other components or mix liquids. The construction is simple and easy to operate.

[0107] Obviously, the embodiments described above are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative efforts should fall within the scope of protection of the present invention.

[0108] It should be noted that the terms used herein are only for describing specific embodiments and are not intended to limit the exemplary embodiments according to the present application. As used herein, unless the context clearly indicates otherwise, the singular form is also intended to include the plural form. In addition, it should be understood that when the terms "comprise" and / or "include" are used in this specification, they indicate the presence of features, steps, tasks, devices, components and / or combinations thereof.

[0109] It should be noted that the terms "first," "second," and the like in the specification and claims of this application and the accompanying drawings are used to distinguish similar objects and are not necessarily used to describe a specific order or precedence. It should be understood that the terms used in this manner are interchangeable where appropriate, so that the embodiments of the present application described herein can be implemented in an order other than that illustrated or described herein.

[0110] The foregoing description is merely a preferred embodiment of the present invention and is not intended to limit the present invention. Those skilled in the art will readily appreciate that various modifications and variations of the present invention are possible. Any modifications, equivalent substitutions, or improvements made within the spirit and principles of the present invention are intended to be within the scope of protection of the present invention.

Claims

1. A high-strength, long-acting, deep composite plugging method for reducing fracture conductivity, characterized in that: The following steps are involved: Step 1, determining the water breakthrough type of each water breakthrough and water-flooded oil production well in the well group; Step 2: simplify the fracture dominant channel into a rectangular equivalent model and calculate the plugging agent dosage; Step 3: Test water injection into the well group to dredge and pre-treat the fracture channels to be blocked, and record the water absorption indicator curve and pressure drop curve of the injection wells corresponding to the proposed profile adjustment well group; Step 4: deep composite plugging agent squeezing operation; Step 5: Pay attention to the injection pressure rise during the plugging agent squeezing process and test after completing the designed injection volume of the plugging agent; Step six: End the test and resume water injection production.

2. The high-strength, long-acting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that: The basis for judging the water breakthrough type of each well group and water-flooded oil production well in step 1 includes the comprehensive water content of each oil production well in the well group, the production dynamics after production, the historical liquid production, the rising trend and change characteristics of water content, and the development, distribution and orientation of reservoir fractures.

3. The high-strength, long-acting, deep composite plugging method for reducing fracture conductivity according to claim 2, characterized in that: The method for determining the water breakthrough and water flooding types of oil wells in the well group in the step 1 is as follows: if the comprehensive water content of one or several oil production wells in the well group is greater than 80%, the liquid production and the comprehensive water content rise rapidly and sharply within a certain period of time on the production performance curve, and then maintain high liquid volume, high water content and water flooding production characteristics; combined with the distribution and orientation of the fractures, it can be determined that the water breakthrough and water flooding well is connected to the main fracture, and is a main fracture oil production well, and the water breakthrough type of the oil well is fracture water flooding; the oil well with rapid water content rise, high liquid volume and high water content production is connected to the secondary fracture, and is a secondary fracture direction oil production well, and the water breakthrough type is fracture water breakthrough.

4. The high-strength, long-acting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that: In the step 2, when simplified to a rectangular equivalent model, the fractures and secondary fracture channels are regarded as the same rectangular model, and the depth, width and height of the primary fractures and secondary fracture channels are equivalent to the length, width and height of the rectangle. There are n fracture dominant channels in the well group, which are equivalent to n rectangular models. The volume of the fracture space to be blocked is calculated, and the amount of the blocking agent required is converted according to the characteristics of the blocking agent.

5. The high-strength, long-acting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that: In the step 2, the amount of plugging agent required to plug the dominant channel of the crack is calculated based on the rectangular equivalent model. The calculation formula is: Where: V----Amount of plugging agent, unit: m 3 ; c----crack width, unit: m; h----crack height, unit: m; l----crack sealing depth, unit: m; n----Number of fractures in the well group, unit: fracture; M----particle expansion coefficient when exposed to water; B----Volume compression coefficient; m----solution preparation concentration; η----Loss through the blast hole.

6. The high-strength, long-acting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that: In the step three, the water absorption indication curve and the pressure drop curve of the water injection well corresponding to the proposed profile adjustment well group are obtained, water is injected by using displacement pumps with different displacements, the wellhead pressure is recorded, and a displacement-wellhead pressure change relationship curve is drawn; when the pressure drop curve is recorded, water is pumped into the water injection well, and the pump is stopped when the wellhead pressure reaches a stable state, and the wellhead pressure value is recorded at fixed time intervals, and a time-wellhead pressure value relationship curve is drawn.

7. The high-strength, long-acting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that: In the step 4, the plugging section is divided into two levels: millimeter-level soft elastic high-strength long-acting granule main plugging section and micron-level high-strength single-phase microgel secondary filling plugging section; during the extrusion injection, the millimeter-level soft elastic high-strength long-acting granule main plugging section is injected first, and then the micron-level high-strength single-phase microgel secondary filling plugging section is injected.

8. The high-strength, long-acting, deep composite plugging method for reducing fracture conductivity according to claim 7, characterized in that: The overall injection volume ratio of the primary plugging segment and the secondary filling plugging segment is controlled to be greater than or equal to 1 and less than or equal to 1.

2.

9. The high-strength, long-acting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that: In the step 5, if the injection pressure of the water injection well rises to more than 0.5 MPa, the water injection process is switched to inject water at an equal displacement rate to push the plugging agent to migrate deep into the formation. After the pressure drops and stabilizes, the plugging agent is switched to the plugging agent squeezing process to squeeze the plugging agent normally.

10. The high-strength, long-acting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that: In the step 5, after the designed injection amount of the plugging agent is completed, the water absorption indication curve and the pressure drop curve after profile adjustment are tested, and whether the fracture channel is effectively blocked is determined based on the water absorption and pressure changes.

11. The high-strength, long-acting, deep composite plugging method for reducing fracture conductivity according to claim 1, characterized in that: In step six, after the plugging agent squeezing, water absorption and pressure drop tests are completed and the plugging reaches the target, there is no need to shut down the well and wait for solidification, and the water injection process can be directly resumed according to the geological injection.

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