Well workover method for lost circulation well

Abstract

The present application relates to the technical field of well repair, in particular to a well repair method for lost circulation well, aiming at solving the technical problems of poor effect of plugging and safety hidden trouble in the existing well killing or plugging operation affecting the injection and production capacity of gas storage well. The well repair method for lost circulation well can realize wellbore composite temporary plugging, wellbore liquid level state dynamic monitoring and early warning and risk assessment, automatic liquid filling device liquid filling well killing, continuous oil pipe injection of slow-release strong acid and gel breaker composite deblocking and reservoir acidification reconstruction, and has the advantages of high operation technology integration, short operation cycle, low operation cost, safety and efficiency, and can effectively reduce reservoir pollution and energy loss, and is beneficial to the rapid recovery of formation injection and production capacity.

Description

Technical Field

[0001] This invention relates to the field of well workover technology, and more particularly to a well workover method for lost-circuit wells. Background Technology

[0002] During well completion operations for gas storage injection and production wells and other lost-circuit wells, the current practice is to supplement the construction with well control or leakage plugging operations to ensure well control safety during the tubing string running-in and running-out process. However, this has the following drawbacks:

[0003] Using large amounts of water to kill wells can contaminate the formation when large amounts of kill fluid are injected, easily causing a significant decrease in the injection and production capacity of gas wells, which is difficult to recover. Currently, most well-known technologies at home and abroad use solid-free chemical gel plugging. However, for lost circulation wells, existing methods such as "degradable chemical plugging fluid for oil and gas wells and its preparation method and application (CN201610408731.9)" and "chemical plugging fluid in pressurized tubing and its preparation method and application (CN201310755649.x)" have good laboratory test data, but in field applications, they are prone to high temperature sensitivity and difficulty in control (easy flash condensation and tubing blockage at high temperatures), insufficient temperature resistance (generally not exceeding 150℃), and short effective temporary plugging time. The aforementioned well-killing and workover fluids typically suffer from several drawbacks, including an effective plugging period of only a few days, difficulty in removing residual chemical plugging agents after treatment, and difficulty in restoring formation permeability. Furthermore, due to the lack of effective large-size solid temporary plugging materials in the fluids, problems such as plug breakage and detachment from the wellbore are common in high-temperature, high-leakage wells due to fluctuations in wellbore pressure and temperature. There is also a lack of supporting methods for real-time dynamic fluid level monitoring and wellbore pressure monitoring and assessment during long treatment periods. These methods often rely on on-site personnel's experience and inferences. In oilfields with complex formations or when well-killing fluid leakage occurs, the replenishment of workover fluid is often not timely or accurate, potentially leading to well kicks and blowouts, as well as the release of toxic and harmful gases from the wellhead, posing risks to personnel and equipment. Summary of the Invention

[0004] The purpose of this invention is to provide a well workover method for lost-flow wells, so as to alleviate the technical problems of existing well control or plugging operations affecting the injection and production capacity of gas storage wells, poor plugging effect, and safety hazards.

[0005] To solve the above-mentioned technical problems, the technical solution provided by the present invention is as follows:

[0006] The well workover method for lost-return wells provided by this invention includes the following steps:

[0007] S1: Ground equipment installation, pipeline connection and pressure testing, on-site material and liquid preparation equipment preparation;

[0008] S2: Configure the pre-gel;

[0009] S3: Pump in pre-pumped gel to temporarily plug the formation;

[0010] S4: Configured with post-positioned wellbore mesh gel;

[0011] S5: Pump in post-installed wellbore mesh gel and plugging balls to temporarily plug the perforation holes and wellbore;

[0012] S6: Use a liquid level monitoring device to monitor and assess the leakage rate under different pressure conditions, while continuously monitoring the tubing pressure and casing pressure and releasing pressure in a timely manner.

[0013] S7: After continuous monitoring shows a leakage rate of <90m / h and no pressure in the oil and casing, start and run the tubing string for well completion. During the operation, use the preferred matching automatic injection device to inject clean water or replenish the post-installed wellbore mesh gel according to the monitored leakage rate. Regularly monitor and evaluate the leakage rate and the pressure of the oil and casing.

[0014] S8: After the well completion operation of the tubing string is completed, a slow-release strong acid is injected through the coiled tubing to dissolve the plugging ball, and a gel breaker is injected to break the gel.

[0015] S9: Continuous tubing nitrogen injection lift to remove residual fluid in the wellbore, reduce fluid column pressure, and complete well injection and production.

[0016] Furthermore, in step S2, the pregel comprises a terpolymer, crosslinking agent A, crosslinking agent B, stabilizer, retarding crosslinking agent, and water;

[0017] The terpolymer has a concentration of 0.6 wt% and is formed by polymerization of acrylamide, methylpropanesulfonic acid and vinylpyrrolidine.

[0018] The crosslinking agent A is 0.6 wt% hexamethylenetetramine;

[0019] The crosslinking agent B is 0.6 wt% bisphenol A propane;

[0020] The stabilizer is 0.3 wt% ammonium chloride;

[0021] The retarded crosslinking agent is 0.3 wt% oxalic acid.

[0022] Furthermore, in step S3, before pumping in the pregel, calculate the amount of pregel used, Q1, where Q1 = 1 / 4π(D 2 -D2 2 )×H2Φ×1.2;

[0023] Where D is the diameter of the section to be injected into the formation, D2 is the outer diameter of the casing of the section to be injected into the formation, H2 is the cumulative thickness of the perforated section of the section to be injected into the formation, and Φ is the formation porosity.

[0024] Furthermore, in step S4, the post-installed wellbore mesh gel comprises a terpolymer, crosslinking agent A, crosslinking agent B, stabilizer, retarded crosslinking agent, and water;

[0025] The terpolymer has a concentration of 0.3 wt% and is formed by polymerization of acrylamide, methylpropanesulfonic acid and vinylpyrrolidine.

[0026] The crosslinking agent A is 0.3 wt% hexamethylenetetramine;

[0027] The crosslinking agent B is 0.3 wt% bisphenol A propane;

[0028] The stabilizer is 0.15 wt% ammonium chloride;

[0029] The retarded crosslinking agent is 0.15 wt% oxalic acid;

[0030] In step S5, the plugging ball is a porous high-purity active alumina ball, which is produced by calcination. The median particle size of the porous high-purity active alumina ball is 5-15 mm, and the aluminum oxide content is ≥93%.

[0031] Furthermore, in step S5, before pumping in the post-installed wellbore mesh gel and plugging ball, calculate the required amounts of both:

[0032] The amount of the plugging ball used is Q2, where Q2 = 1 / 4πD1 2 ×(H1+h)×1.2, where D1 is the inner diameter of the casing of the section to be injected into the formation, H1 is the total thickness of the section to be injected into the formation, and h is the additional filling height above the perforated section, where h is 10-15m;

[0033] The amount of gel used in the post-installed wellbore mesh is Q3, where Q3 = Q0 - Q2, and Q0 = 1 / 4π(d1) 2 L1+d2 2 L2+d3 2 L3), where Q0 is the effective tubing space volume for plugging construction, d1 is the inner diameter of the tubing in the well, L1 is its total length, d2 is the inner diameter of the tubing from the bottom end of the tubing in the well to the hanger, L2 is its total length, d3 is the inner diameter of the tubing from the hanger in the well to the upper boundary of the perforation section, L3 is its total length.

[0034] Furthermore, in step S5, when pumping in the post-installed wellbore mesh gel and plugging balls, it is first pumped in at a speed of 0.2m... 3 Half of the total volume of the post-installed wellbore mesh gel is injected into the tubing at a flow rate of / min. Then, plugging balls of different sizes are dropped into the wellhead through a ball-dropping funnel, and pumped at 0.1m... 3 The remaining 1 / 2 of the total amount of post-installed wellbore mesh gel is injected into the tubing at a displacement of / min.

[0035] Furthermore, in step S6, if continuous monitoring for 6 hours shows a liquid level drop rate of <90 m / h and there is no pressure in the oil or casing, the temporary plugging is considered successful.

[0036] If the wellbore leakage rate is too fast, with a loss rate ≥90m / h, then pump in post-wellbore mesh gel and plugging balls according to the wellbore leakage situation until the liquid level drops at a rate <90m / h.

[0037] Furthermore, in step S7, if the well fluid level drops during construction, the well is shut in and clean water or post-installed well mesh gel is pumped in according to the well leakage rate. At the same time, the leakage rate and oil and casing pressure are monitored every 1 hour.

[0038] Furthermore, in step S8, potassium persulfate and sodium sulfite breaker are first injected through coiled tubing to break up the gel in the wellbore.

[0039] Secondly, acidic unblocking agent is injected through coiled tubing for spray flushing and targeted soaking to dissolve the plugging balls inside the wellbore;

[0040] Then, potassium persulfate and sodium sulfite breaker are injected through coiled tubing to break up the gel in the formation and clear the formation.

[0041] Furthermore, in step S9, the cavitation depth of the nitrogen gas lift is L4, where L4 = 100 × P / (1.25 × ρ);

[0042] Where P is the casing's resistance to external extrusion, in MPa, and ρ is the completion fluid mud density, in g / cm³. 3 .

[0043] In summary, the technical effects achieved by the well workover method for lost-return wells provided by this invention are as follows:

[0044] In this invention, steps S1 to S5 involve pumping pre-pumped gel, post-pumped wellbore mesh gel, and plugging ball into the well sequentially, achieving temporary plugging. The combined effect of these three components effectively extends the temporary plugging time. Furthermore, the plugging ball acts as a support, preventing the gel from breaking or detaching from the wellbore wall due to pressure and temperature fluctuations in the high-temperature, easily leaky wellbore. Moreover, the combined effect transforms the original wellbore kill fluid from a difficult-to-control tubing flow leakage state into a controllable micro-permeability flow, thereby improving the interaction between the wellbore fluid column, the wellbore plugging agent (the product of post-pumped wellbore mesh gel formation), the solid plugging ball, the formation plugging agent (the product of pre-pumped gel formation), and the formation fluid. A controllable dynamic pressure balance is formed, thus enabling subsequent low-permeability dynamic temporary plugging and wellbore fluid level control through water injection or replenishment of post-placed wellbore mesh gel. In steps S6 to S9, water injection or replenishment of post-placed wellbore mesh gel can be carried out in real time through auxiliary fluid level monitoring devices and preferred matching automatic injection devices to control the wellbore fluid level. This can effectively reduce wellbore fluid loss and prevent gas displacement overflow, achieving controllable temporary plugging of the wellbore, effective control of wellbore pressure and dynamic fluid level throughout the wellbore treatment and workover process. After the completion string is run in, the gel is directly broken with pressure-bearing rupture agent, and the wellbore and formation are dredged and cleared, realizing the workover of lost-return wells.

[0045] As can be seen from the above, this well workover method has the advantages of high integration of operational technology, short operation cycle, low operation cost, safety and efficiency, and can effectively reduce reservoir pollution and energy loss, and facilitate the rapid recovery of formation injection and production capacity. Attached Figure Description

[0046] To more clearly illustrate the specific embodiments of the present invention or the technical solutions in the prior art, the drawings used in the description of the specific embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of the present invention. For those skilled in the art, other drawings can be obtained from these drawings without creative effort.

[0047] Figure 1 A process flow diagram of a well workover method for lost-return wells provided in an embodiment of the present invention;

[0048] Figure 2 This is a schematic diagram of the temporary plugging process in this invention;

[0049] Figure 3 This is a microstructure diagram of the gel used in this invention;

[0050] Figure 4 This is a comparison chart of the relevant parameters of the two gels used in this invention;

[0051] Figure 5This is a schematic diagram of the layout of the ground equipment used in the composite leak sealing operation of this invention;

[0052] Figure 6 This is a schematic diagram of the layout of the ground equipment used for raising and lowering the tubular column in this invention.

[0053] Figure 7 This is a schematic diagram of the layout of the ground equipment used for acid injection unblocking and gas lift drainage commissioning in this invention.

[0054] Icons: 1-First mixing tank; 2-Second mixing tank; 3-Mixing funnel; 4-Pump truck; 5-Ball-dropping funnel; 6-Wellhead tree; 7-Fluid level monitoring device; 8-Chop manifold; 9-Oil nozzle manifold; 10-Heating furnace; 11-Separator; 12-Blowout pool; 13-Torch; 14-Workover rig; 15-Blowout preventer; 16-Kill manifold; 17-Follow-four-way valve below tree; 18-Nitrogen generator truck; 19-Coiled tubing; 20-Pre-installed gel; 21-Post-installed wellbore mesh gel; 22-Pluging ball. Detailed Implementation

[0055] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. The components of the embodiments of the present invention described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.

[0056] Therefore, the following detailed description of the embodiments of the invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the invention without inventive effort are within the scope of protection of the invention.

[0057] The following detailed description of some embodiments of the present invention is provided in conjunction with the accompanying drawings. Unless otherwise specified, the following embodiments and features can be combined with each other.

[0058] In the current construction phase, well control or leak plugging operations affect the injection and production capacity of gas storage wells and pose safety hazards.

[0059] In view of this, the present invention provides a well workover method for lost-return wells, comprising the following steps:

[0060] S1: Surface equipment installation, pipeline connection and pressure testing; preparation of on-site materials and fluid mixing equipment; S2: Preparation of pre-filled gel 20; S3: Pumping in pre-filled gel 20 to temporarily plug the formation; S4: Preparation of post-filled wellbore mesh gel 21; S5: Pumping in post-filled wellbore mesh gel 21 and plugging ball 22 to temporarily plug the perforation holes and wellbore; S6: Using fluid level monitoring device 7 for follow-up monitoring, assessing leakage rate under different pressure conditions, and continuously monitoring tubing pressure and casing pressure, releasing pressure as needed; S7: Waiting for continuous monitoring of leakage rate <90 After the flow rate reaches m / h and the oil and casing are depressurized, the well completion operation is carried out by running the tubing string. During the operation, clean water is injected in real time or the post-placed wellbore mesh gel 21 is replenished according to the monitored leakage rate using the preferred matching automatic injection device. The leakage rate and oil and casing pressure are monitored and evaluated regularly. S8: After the well completion operation is completed by running the tubing string, the slow-release strong acid acid dissolution plugging ball 22 is injected through the coiled tubing 19, and the gel breaker is injected to break the gel. S9: Nitrogen gas is injected into the coiled tubing 19 to lift out the residual fluid in the wellbore and reduce the liquid column pressure, and the well completion injection and production are carried out.

[0061] refer to Figure 1 and Figure 2 In steps S1 to S5, pre-pumped gel 20, post-pumped wellbore mesh gel 21, and plugging ball 22 are pumped into the well sequentially, achieving temporary plugging. With the cooperation of these three components, the temporary plugging time can be effectively extended. Furthermore, due to the support provided by the plugging ball 22, the gelled gel is less prone to breakage or detachment from the wellbore wall in high-temperature, easily leaky wells due to pressure and temperature fluctuations. Moreover, the cooperation of these three components transforms the original wellbore kill fluid from a difficult-to-control tubing flow leakage state to a controllable micro-permeability flow, thereby ensuring the proper functioning of the wellbore fluid column, the wellbore plugging agent (the product of post-pumped wellbore mesh gel 21 after gelation), the solid plugging ball 22, the formation plugging agent (the product of pre-pumped gel 20 after gelation), and the formation... A controllable dynamic pressure balance is formed between the fluids, thus achieving low-permeability dynamic temporary plugging and wellbore fluid level control by injecting clean water or replenishing the post-placed wellbore mesh gel 21. In steps S6 to S9, clean water can be injected in real time or the post-placed wellbore mesh gel 21 can be replenished to control the wellbore fluid level through the auxiliary fluid level monitoring device and the preferred matching automatic injection device. This can effectively reduce wellbore fluid loss and prevent gas displacement overflow, achieving controllable temporary plugging of the wellbore, effective control of wellbore pressure and dynamic fluid level throughout the wellbore treatment and workover process. After the completion string is run in, the gel is directly broken with pressure-bearing rupture agent, and the wellbore and formation are dredged and cleared, realizing the workover of lost return wells.

[0062] As can be seen from the above, this well workover method has the advantages of high integration of operational technology, short operation cycle, low operation cost, safety and efficiency, and can effectively reduce reservoir pollution and energy loss, and facilitate the rapid recovery of formation injection and production capacity.

[0063] The following combination Figures 1 to 6The structure and shape of the well workover method for lost-return wells provided in this embodiment are described in detail:

[0064] Furthermore, in step S2, the pregel 20 comprises a terpolymer, crosslinking agent A, crosslinking agent B, stabilizer, retarded crosslinking agent, and water; wherein the concentration of the terpolymer is 0.6 wt%, and it is formed by polymerization of acrylamide, methylpropanesulfonic acid, and vinylpyrrolidine; crosslinking agent A is 0.6 wt% hexamethylenetetramine; crosslinking agent B is 0.6 wt% bisphenol A propane; stabilizer is 0.3 wt% ammonium chloride; and retarded crosslinking agent is 0.3 wt% oxalic acid.

[0065] Specifically, the molecular weight of the terpolymer is 400–800 × 10⁻⁶. 4 The product, with a degree of hydrolysis of 10%–20%, is polymerized from monomers acrylamide, methylpropanesulfonic acid, and vinylpyrrolidine. The polymerization steps are as follows: A 25% monomeric acrylamide solution is prepared using deionized water. Then, functional monomers methylpropanesulfonic acid and vinylpyrrolidine (each accounting for approximately 12% of the acrylamide monomer mass) are added. After thorough dissolution, the pH of the system is adjusted to approximately 7 using a pH adjuster, and the temperature is lowered to 0°C. Nitrogen gas is first introduced to remove oxygen for 30 minutes, while a small amount of initiator ammonium persulfate or sodium bisulfite (approximately 0.05% of the total monomer mass) is added. The temperature during this process does not exceed 5°C, and nitrogen gas is continued to be introduced for another 30 minutes. The changes in the solution in the bottle are observed, and the temperature changes are recorded. When the temperature in the bottle drops to 40°C, the gel-like reaction product is removed, placed in a bag, and 15% granular sodium hydroxide is added. The bag is then sealed and placed in a 90°C oven for 4 hours. The reactant is then removed and dried at 60°C for 8 hours. After pulverization, a white powdery terpolymer sample is obtained.

[0066] An aqueous solution of the terpolymer is prepared (the amount of water is added proportionally according to the required gel concentration). Hexamethylenetetramine, bisphenol A, oxalic acid, and ammonium chloride are then added to the aqueous solution of the terpolymer, and the mixture is stirred to obtain a salt-resistant and high-temperature-resistant gel plugging agent. Before gelation, this gel plugging agent is a polymer solution with a viscosity of 247 mPa·s at ground conditions of 15°C. After gelation at 150°C for approximately 6 hours, the viscosity reaches 19500 mPa·s, achieving temporary plugging of the formation.

[0067] Furthermore, in step S3, before pumping in pre-gel 20, calculate the amount of pre-gel 20 used, Q1, where Q1 = 1 / 4π(D 2 -D2 2 )×H2Φ×1.2; where D is the diameter of the section to be injected into the formation, D2 is the outer diameter of the casing of the section to be injected into the formation, H2 is the cumulative thickness of the perforated section of the section to be injected into the formation, and Φ is the formation porosity.

[0068] The above calculations precisely determined the dosage of pre-gel 20, ensuring that the temporary plugging of the formation after pumping in the pre-gel 20 achieves the desired effect. It should be noted that during the pumping of the pre-gel 20, the casing is simultaneously injected with fluid at a rate 1.2 times that of the pre-gel 20 pumping rate, thus ensuring pressure balance in the wellbore.

[0069] Furthermore, in step S4, the post-installed wellbore mesh gel 21 comprises a terpolymer, crosslinking agent A, crosslinking agent B, stabilizer, retarding crosslinking agent, and water; wherein, the concentration of the terpolymer is 0.3wt%, formed by polymerization of acrylamide, methylpropanesulfonic acid, and vinylpyrrolidine; crosslinking agent A is 0.3wt% hexamethylenetetramine; crosslinking agent B is 0.3wt% bisphenol A propane; stabilizer is 0.15wt% ammonium chloride; and retarding crosslinking agent is 0.15wt% oxalic acid; in step S5, the plugging ball 22 is a porous high-purity active alumina ball, produced by calcination, wherein the median particle size of the porous high-purity active alumina ball is 5-15mm, and the content of aluminum oxide is ≥93%.

[0070] Specifically, when preparing the post-installed wellbore mesh gel 21, a low concentration of 0.3 wt% terpolymer is used, supplemented with a higher concentration of crosslinking agent A (0.3 wt% hexamethylenetetramine), crosslinking agent B (0.3 wt% bisphenol A), stabilizer (0.15 wt% ammonium chloride), and crosslinking retarder (0.15 wt% oxalic acid), with the balance being water. After thorough stirring, the ungelled post-installed wellbore mesh gel 21 is obtained. This gel has a viscosity of 93 mP at 15°C under surface conditions. The polymer solution of a·s gels after about 10 hours at 150℃ formation conditions, with a viscosity of up to 1170 mPa·s; the plugging ball 22 is mainly a porous high-purity active alumina ball with an aluminum oxide content of ≥93% produced by calcination. The preferred size combination is a combination of high-purity active alumina balls with a median particle size of 5 mm, 10 mm, and 15 mm. The above particle sizes are combined in a 1:1:1 ratio to maintain the permeability of the wellbore at 10000 mD under a high pressure of 30 MPa.

[0071] Furthermore, in step S5, before pumping in the post-wellbore mesh gel 21 and the plugging ball 22, the dosage of both is calculated:

[0072] The amount of plugging ball 22 used is Q2, where Q2 = 1 / 4πD1 2 ×(H1+h)×1.2, where D1 is the inner diameter of the casing in the section to be injected into the formation, H1 is the total thickness of the section to be injected into the formation, and h is the additional filling height above the perforated section, where h is 10-15m; the amount of gel 21 used in the post-installed wellbore mesh is Q3, Q3=Q0-Q2, Q0=1 / 4π(d1 2 L1+d2 2 L2+d3 2L3), where Q0 is the effective tubing space volume for plugging construction, d1 is the inner diameter of the tubing in the well, L1 is its total length, d2 is the inner diameter of the tubing from the bottom end of the tubing in the well to the hanger, L2 is its total length, d3 is the inner diameter of the tubing from the hanger in the well to the upper boundary of the perforation section, L3 is its total length.

[0073] The above calculations precisely determined the dosage of wellbore mesh gel and plugging ball 22, ensuring that the temporary plugging of perforations and wellbore after pumping them in achieves the desired effect. The method for combined application of wellbore mesh gel and plugging ball 22 is as follows:

[0074] First, pump truck 4 passes through at 0.2m 3 Half of the total volume of the post-installed wellbore mesh gel 21 is injected into the tubing at a flow rate of / min. Then, plugging balls 22 of different sizes are dropped into the wellhead through the ball-dropping funnel 5, and pumped by the pump truck 4 at a flow rate of 0.1m. 3 The remaining half of the total amount of post-installed wellbore mesh gel 21 is injected into the tubing at a flow rate of / min. At the same time, the casing is filled with fluid at a rate 1.2 times that of the temporary plugging agent injection rate. The displacement fluid volume must be sufficient to ensure that the wellbore fluid level is approximately 50m higher than the equilibrium formation pressure fluid level when the temporary plug reaches the bottom of the well.

[0075] It should be added that, to prevent the risk of formation gas intrusion and upward movement due to excessively slow leakage, the ideal leakage velocity of plugging ball 22 should be controlled at 10m. 3 / d (for a D88.9mm gas-tight injection and production tubing with an internal volume of 4.54L / m, the equivalent leakage velocity is approximately 92m / h). Through indoor evaluation tests, it was found that using a 1:1:1 filling combination of particle sizes (5mm, 10mm, 15mm) can maintain the permeability of the wellbore at 30MPa high pressure at 10000mD. The ideal leakage velocity can be effectively controlled by adjusting the length of the filling section of the plugging ball 22 at the top of the perforation section.

[0076] After pumping in the pre-pumped gel 20, the post-pumped wellbore mesh gel 21, and the plugging ball 22, the temporary plugging effect is as follows: Figure 2 As shown, the original wellbore kill fluid is transformed from a difficult-to-control tubing flow leakage state to a controllable micro-permeability state, thereby forming a controllable dynamic pressure balance among the wellbore fluid column, the wellbore plugging agent (the product of the post-placed wellbore mesh gel 21 after gelation), the solid plugging ball 22, the formation plugging agent (the product of the pre-placed gel 20 after gelation), and the formation fluid. In this way, low-permeability dynamic temporary plugging and wellbore fluid level control can be achieved by injecting clean water or supplementing the post-placed wellbore mesh gel 21.

[0077] In step S6, the liquid level monitoring device 7 is a dynamic liquid level monitoring device equipped with two sound generation methods (high / low pressure) (using a dual sound source channel with nitrogen cylinder sound generation and casing gas sound generation; casing gas sound generation is used when the pressure at the wellhead is above 3MPa, and nitrogen cylinder sound generation is used when the pressure is below 3MPa or there is no pressure). This device is used to monitor and evaluate the leakage rate under different pressure conditions during the pumping of the temporary plugging section, and to continuously monitor the tubing pressure and the annulus pressure.

[0078] If continuous monitoring for 6 hours (formation gelation time) shows a fluid level drop rate of <90m / h and no pressure in the oil or casing, the temporary plugging is successful. If the wellbore leakage rate is too fast and the leakage rate is ≥90m / h, then according to the wellbore leakage situation, timely injection of post-installed wellbore mesh gel 21 and plugging balls 22 of different sizes will reduce the wellbore fluid level leakage rate to below 90m / h.

[0079] Once the fluid level drop rate is controlled to <90m / h, the tubing string should be run in and out. If the fluid level in the wellbore drops during construction, the well should be shut in and clean water should be injected or wellbore mesh gel 21 should be installed in a timely manner according to the wellbore leakage rate to stabilize the fluid level. The leakage rate and oil and casing pressure should be monitored every 1 hour to assess well control risks and take appropriate countermeasures in a timely manner.

[0080] In step S8, potassium persulfate and sodium sulfite breaker are first injected through coiled tubing 19 to break the gel in the wellbore; then, acidic unblocking agent is injected through coiled tubing 19 for spray flushing and targeted soaking to dissolve the plugging ball 22 in the wellbore; then, potassium persulfate and sodium sulfite breaker are injected through coiled tubing 19 to break the gel in the formation and clear the formation.

[0081] In step S9, the cavitation depth of the nitrogen gas lift is L4, where L4 = 100 × P / (1.25 × ρ); where P is the casing's resistance to external extrusion in MPa, and ρ is the density of the completion fluid mud in g / cm³. 3 .

[0082] The working process of the well workover method for lost-return wells provided in this embodiment is as follows:

[0083] Taking the construction of Well A in the gas storage facility of North China Oilfield as an example, the well encountered problems such as continuous annular pressure, wellhead uplift, and natural gas leakage during production. Testing revealed that the H2S content was 16.5 mg / m³. 3 There are safety hazards; the well was tested using conventional injection well fluid, with a total of 150m³ of fluid injected during three well-killing operations. 3The measured fluid level depth inside the tubing at a displacement of 150-400 L / min ranged from 120-258 m. The pump pressures for three well-killing operations were 35-0 MPa, 22-0 MPa, and 16-0 MPa, respectively, while the casing pressures varied from 16-6.2 MPa, 16-17 MPa, and 16-15.5 MPa, generally showing pressure recovery after about 2 hours of well-killing. The formation temperature of this well was 154℃, with a high pressure coefficient, rapid leakage rate, fast gas return rate, and a narrow operational safety window, making effective well control difficult with conventional temporary plugging or fluid injection.

[0084] The specific construction steps for using this well workover method are as follows:

[0085] Step 1: Prepare pre-gel 20;

[0086] Based on the formula Q1=1 / 4π(D) 2 -D2 2 )×H2Φ×1.2, in well A, D=3m, D2=127mm, there are 15 layers of Class I fractures totaling 52.4m with an average effective porosity of 2.3%, 29 layers of Class II fractures totaling 83.2m with an average effective porosity of 1.16%, and 12 layers of Class III fractures totaling 29.3m with an average effective porosity of 0.82%. H2=112.5m. Therefore, the calculated amount of pre-coated gel 20 is 20m³. 3 The composition includes 120 kg of terpolymer, 120 kg of crosslinking agent A (hexamethylenetetramine), 120 kg of crosslinking agent B (bisphenol A propane), 60 kg of stabilizer (ammonium chloride), 60 kg of retarded crosslinking agent (oxalic acid), and 19.52 mg of water. 3 .

[0087] Step 2: Prepare the post-installed wellbore mesh gel 21 and the plugging ball 22;

[0088] Based on the formula Q2=1 / 4πD1 2 ×(H1+h)×1.2, in well A, D1=108.62mm, H1=166.4m, h=15m, therefore the amount of plugging ball 22 used is calculated to be 2m. 3 The dosage is approximately 1400 kg, and dissolving it requires about 4 tons of 10% hydrochloric acid; based on the formula Q3 = Q0 - Q2, Q0 = 1 / 4π(d1) 2 L1+d2 2 L2+d3 2 In well A, d1 = 62 mm, L1 = 4505.6 m, d2 = 154.78 mm, L2 = 60.8 m, and d3 = 108.62 mm, L3 = 460.6 m. Based on this, the calculated amount of gel 21 used for the post-installed wellbore mesh is 17 m³. 3 .

[0089] Based on the previous well-killing injection where the pump pressure was 0, this temporary plugging operation used a depth of 0.2m. 3 When injecting pre-gel 20 at a flow rate of / min, the wellhead pressure is predicted to not exceed 10MPa. After inserting plugging ball 22 into the ball-feeding funnel 5, at a flow rate of 0.2m... 3 When injecting 21% of the post-wellbore mesh gel at a flow rate of / min, the wellhead pressure is predicted not to exceed 20MPa.

[0090] Step 3: Prepare the gel;

[0091] Using a first mixing tank 1 and a second mixing tank 2, both with a specification of 15m3, pre-gel 20 was prepared in two batches. Each mixing tank prepared 10m3 of temporary plugging agent each time, injected 9.76m3 of water, and added 60Kg of terpolymer, 60Kg of crosslinking agent A (hexamethylenetetramine), 60Kg of crosslinking agent B (bisphenol A propane), 30Kg of stabilizer (ammonium chloride), and 30Kg of retarding crosslinking agent (oxalic acid).

[0092] Similarly, the post-wellbore mesh gel 21 was prepared in two batches, with each mixing tank preparing 8.5m³ of gel per batch. 3 Temporary plugging agent, 8.4m of water injected. 3 Add 25.5 kg of terpolymer, 25.5 kg of crosslinking agent A (hexamethylenetetramine), 25.5 kg of crosslinking agent B (bisphenol A propane), 12.75 kg of stabilizer (ammonium chloride), and 12.75 kg of retardant crosslinking agent (oxalic acid).

[0093] Prepare 50 kg of potassium persulfate and 25 kg of sodium sulfite for use in breaking up the adhesive after construction.

[0094] Step 4: Temporary blocking construction procedures;

[0095] Ground equipment installation and pipeline installation Figure 4 The connection is made, and the relevant equipment, injection pipeline, return pipeline and wellhead gas production tree 6 are fully connected through high-pressure tees and oil connectors. After the connection is completed, a pressure test of 20MPa is performed. The surface equipment includes the first liquid preparation tank 1, the second liquid preparation tank 2, the liquid preparation funnel 3, the pump truck 4, the ball-dropping funnel 5, the wellhead gas production tree 6, the liquid level monitoring device 7, the choke manifold 8, the oil nozzle manifold 9, the heater 10, the separator 11, the blowout pool 12 and the torch 13.

[0096] First, the pump truck 4 is greater than 0.5m. 3 / min displacement to inject clean water into the tubing until water is seen in the casing (annulus and tubing volume approximately 60m³). 3 Secondly, pump truck 4 with a height of 0.2m 3 Inject 20m of oil into the pipeline at a displacement of / min. 3 The pre-gel 20, while at 14.4m 3 / h to inject fluid into the annulus of the oil jacket, pumping time approximately 100 minutes; then, pump truck 4 at 0.2m 3 Injecting 8.5m of oil into the tubing at a displacement of / min 3 The post-installed wellbore mesh gel 21, at a depth of 14.4m 3 Fluid was injected into the annulus of the oil casing at a rate of / h, with a pumping time of approximately 42.5 minutes; finally, 1400 kg of plugging balls 22 were dropped into the wellhead via the self-dumping funnel 5, while simultaneously, the pump truck 4 moved at a speed of 0.1 m... 3 Injecting 8.5m of oil into the tubing at a displacement of / min 3 The post-installed wellbore mesh gel 21, at a depth of 14.4m 3 / h of fluid is injected into the annulus of the oil jacket, and the ball throwing and pumping time is 85min.

[0097] A dynamic fluid level monitoring device 7, equipped with two sound generation methods (using nitrogen cylinder and casing gas for sound generation; casing gas is used for high pressure above 3MPa at the wellhead, and nitrogen cylinder is used for low pressure or no pressure below 3MPa), is used to monitor and evaluate the leakage rate under different pressure conditions during the pumping of fluid into the temporary plugging section. Simultaneously, the tubing pressure and casing annulus pressure are continuously monitored. If there is pressure in the tubing or casing, the tubing and casing are depressurized through the throttling manifold 8. If natural gas is released, it is ignited through the liquid-gas separator 11 to the torch 13.

[0098] If the fluid level drops to less than 90 m / h after continuous monitoring for 6 hours (formation gelation time) and there is no pressure in the oil and casing, the temporary plugging is considered successful. If the wellbore leakage rate is too fast and the leakage rate is ≥90 m / h, then the post-installed wellbore mesh gel 21 and plugging balls 22 of different sizes are injected in a timely manner according to the wellbore leakage situation to reduce the wellbore fluid level leakage rate to below 90 m / h.

[0099] Step 5: Well repair and well completion treatment construction;

[0100] After the liquid level drop rate is controlled to <90m / h, proceed according to... Figure 5 The surface equipment used for setting up and lowering tubing strings is deployed, and the injection pipeline, return pipeline, workover equipment, and wellhead gas tree 6 are fully connected via high-pressure tees and augers to carry out tubing string setting up and lowering, workover, and well completion treatment operations. This surface equipment includes a first mixing tank 1, a second mixing tank 2, a mixing funnel 3, a pump truck 4, a fluid level monitoring device 7, a workover rig 14, a blowout preventer 15, a kill manifold 16, a four-way valve below the gas tree 17, a choke manifold 8, an oil nozzle manifold 9, a heater 10, a separator 11, a blowout pool 12, and a torch 13.

[0101] If the fluid level in the wellbore drops during construction, the well should be shut in and clean water or wellbore mesh gel 21 should be injected in a timely manner according to the leakage rate to stabilize the fluid level. The leakage rate and oil and casing pressure should be monitored every 1 hour to assess well control risks and take corresponding countermeasures in a timely manner.

[0102] Step 6: Relieve congestion and commence production;

[0103] After the gas well workover operation is completed, according to Figure 6 The surface equipment used for unblocking the coiled tubing 19 and for gas lift drainage and commissioning was set up. The injection line, return line, unblocking equipment, and wellhead gas tree 6 were fully connected via high-pressure tees and augers. The entire coiled tubing system was pressure tested at 40 MPa and stabilized for 10 minutes; the pressure drop was 0, which was acceptable, and there was no leakage at the sealing points. The vent line at the front end of the liquid-gas separator 11 was pressure tested at 10 MPa and stabilized for 10 minutes; the pressure drop was 0, which was acceptable. This surface equipment includes a first liquid preparation tank 1, a pump truck 4, a nitrogen generator 18, the coiled tubing 19 unit, the wellhead gas tree 6, a liquid level monitoring device 7, a choke manifold 8, an oil nozzle manifold 9, a heater 10, a separator 11, a vent pool 12, and a torch 13.

[0104] First, coiled tubing 19 is run in with forward circulation. While circulating, 0.3 wt% of a breaker (ammonium persulfate: sodium sulfite = 2:1, mass ratio) is injected to a depth of 4686 m (at the top of the plugging ball 22). This breaks the gel in the post-installed wellbore mesh gel 21 within the wellbore. After pulling out coiled tubing 19, the well is shut off for 24 hours to allow the post-installed wellbore mesh gel 21 to fully break down. Next, coiled tubing 19 is run in with forward circulation. While circulating, clean water is injected to flush the well to a depth of 4686 m. The top of the plugging ball 22 is re-examined to displace the broken post-installed wellbore mesh gel 21. The water absorption index is measured at 10 MPa, 15 MPa, and 20 MPa for 10 minutes, with an injection volume of 0.18 m³. 3 0.09m 3 0.3m 3 Then, acidic unblocking agent is injected through coiled tubing 19 for jet flushing and targeted soaking to dissolve the plugging ball 22 in the wellbore. Simultaneously, further acidizing of the perforated reservoir is achieved. The unblocking agent is unblocked with 10% hydrochloric acid (with 0.3% corrosion inhibitor), and approximately 4m³ of acid is injected. 3 Replace with 6.3m of clean water 3 Finally, the pump was stopped, and coiled tubing 19 was pulled to the wellhead. After 12 hours of observation, the oil pressure rose from 2.5 MPa to 15 MPa.

[0105] Coiled tubing 19 was run into the well via positive circulation. While circulating, clean water was injected to flush the well to a depth of approximately 5020m, displacing residual acid and undissolved plugging ball 22 residue. Then, 0.6wt% gel breaker (ammonium persulfate: sodium sulfite = 2:1, mass ratio) was injected through coiled tubing 19 to break up gels of varying concentrations within the formation, further clearing the formation. The pump was stopped, and coiled tubing 19 was pulled to the wellhead. After 12 hours of observation, the oil pressure rose from 15MPa to 31MPa. After shutting in the well and observing that the oil pressure did not drop, a blowout ignition was performed. During the drop in oil pressure from 31MPa to 17MPa, 8m of fluid returned from the outlet. 3 After that, the fluid output gradually decreased, the oil pressure stopped dropping, and the well was shut in at an oil pressure of 20 MPa.

[0106] The coiled tubing 19 was used for nitrogen gas lift to reduce the gas column pressure in the wellbore, and the well was completed and put into production. The maximum allowable caving depth for nitrogen gas lift was calculated using the formula: L4 = 100 × P / (1.25 × ρ). In well A, P = 58.8 MPa and ρ = 1.0 g / cm³, thus the maximum allowable caving depth was calculated to be 4704 m. Based on this safe gas lift depth, coiled tubing 19 was run in with positive circulation, and clean water was injected to flush the well to 2500 m while circulating. The liquid column pressure was reduced by nitrogen gas lift, and 8 m of liquid returned from the outlet during this process. 3 The pump was stopped, and coiled tubing 19 was run to the wellhead. After 12 hours of observation, the oil pressure rose to 34.5 MPa, and the casing pressure reached 9 MPa. This demonstrates that good communication between the wellbore and the formation was achieved, and the reservoir was well restored.

[0107] In the above, the coiled tubing 19 includes, from top to bottom, a slip-type external connector, a double-valve check valve, a safety release connector, a two-way circulation valve, a filter, and a rotary nozzle.

[0108] The well workover method of this invention can achieve composite temporary plugging of the wellbore, dynamic monitoring and early warning of the wellbore fluid level and risk assessment, injection of hydraulic well fluid by an automatic injection device and injection of slow-release strong acid and gel breaker into the coiled tubing 19 for composite unblocking, and reservoir acidizing. Through the composite temporary plugging technology of the wellbore, the original wellbore kill fluid is transformed from a difficult-to-control tubing flow leakage state to a controllable micro-permeability state, thereby forming a controllable dynamic pressure balance between the wellbore fluid column, wellbore plugging rubber plug, solid plugging ball 22, formation plugging agent and formation fluid, so as to achieve low-permeability dynamic temporary plugging and control of the wellbore fluid level by injecting clean water or supplementing the post-placed wellbore mesh gel 21. By using auxiliary high / low pressure dual-channel dynamic fluid level and pressure monitoring equipment for follow-up monitoring, and with the preferred matching automatic injection device, clean water is injected in real time or the post-placed wellbore mesh gel 21 is added to control the wellbore fluid level. This can effectively reduce wellbore fluid loss and prevent gas displacement overflow. It can realize the controllable temporary plugging of the wellbore, the effective control of wellbore pressure and dynamic fluid level throughout the wellbore treatment and workover process. Moreover, after the completion string is run in, the gel breaking agent is directly used to break the gel under pressure, acidize and dredge the wellbore and formation. This invention has the advantages of high integration of operation technology, short operation cycle, low operation cost, safety and efficiency, and can effectively reduce reservoir pollution and energy loss, and facilitate the rapid recovery of formation injection and production capacity.

[0109] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, and not to limit them; although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some or all of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the embodiments of the present invention.

Claims

1. A well workover method for lost-circuit wells, characterized in that, Includes the following steps: S1: Ground equipment installation, pipeline connection and pressure testing, on-site material and liquid preparation equipment preparation; S2: Preparation of a pregel; the pregel comprises a terpolymer, crosslinking agent A, crosslinking agent B, stabilizer, retarding crosslinking agent, and water; wherein, the concentration of the terpolymer is 0.6 wt%, formed by polymerization of acrylamide, methylpropanesulfonic acid, and vinylpyrrolidine; the crosslinking agent A is 0.6 wt% hexamethylenetetramine; the crosslinking agent B is 0.6 wt% bisphenol A propane; the stabilizer is 0.3 wt% ammonium chloride; the retarding crosslinking agent is 0.3 wt% oxalic acid; the pregel gels after approximately 6 hours at 150°C in the formation, with a viscosity reaching 19500 mPa•s; S3: Pump in pre-pumped gel to temporarily plug the formation; S4: Configuring post-installed wellbore mesh gel; the post-installed wellbore mesh gel comprises a terpolymer, crosslinking agent A, crosslinking agent B, stabilizer, retarded crosslinking agent, and water; wherein, the concentration of the terpolymer is 0.3 wt%, formed by polymerization of acrylamide, methylpropanesulfonic acid, and vinylpyrrolidine; the crosslinking agent A is 0.3 wt% hexamethylenetetramine; the crosslinking agent B is 0.3 wt% bisphenol A propane; the stabilizer is 0.15 wt% ammonium chloride; the retarded crosslinking agent is 0.15 wt% oxalic acid; the wellbore mesh gel solidifies after approximately 10 hours at 150°C formation conditions, reaching a viscosity of 1170 mPa•s; S5: Pump in post-installed wellbore mesh gel and plugging balls to temporarily plug the perforations and wellbore; the plugging balls are porous high-purity active alumina balls, produced by calcination, wherein the median particle size of the porous high-purity active alumina balls is 5-15mm, and the aluminum oxide content is ≥93%; S6: Use a liquid level monitoring device to monitor and assess the leakage rate under different pressure conditions. Simultaneously monitor the tubing pressure and casing pressure, and release pressure as needed. If continuous monitoring for 6 hours shows a liquid level drop rate of <90m / h, and there is no pressure in the tubing or casing, the temporary plugging is successful. If the wellbore leakage rate is too fast, with a loss rate ≥90m / h, pump in post-installed wellbore mesh gel and plugging balls according to the wellbore leakage situation until the liquid level drop rate is <90m / h. S7: Once the continuous monitoring leakage rate is <90m / h and there is no pressure in the oil and casing, proceed with the running-in and running-out of the tubing for well completion. During the operation, inject clean water or replenish the post-installed wellbore gel using the matching automatic injection device according to the monitored leakage rate. Regularly monitor and evaluate the leakage rate and the pressure in the oil and casing. If the wellbore fluid level drops during the operation, shut in the well and pump in clean water or post-installed wellbore gel according to the wellbore leakage rate. At the same time, monitor the leakage rate and the pressure in the oil and casing every 1 hour. S8: After the well completion operation with the tubing string is completed, a slow-release strong acid is injected through the coiled tubing to dissolve the plugging ball, and a gel breaker is injected to break the gel. First, potassium persulfate and sodium sulfite gel breaker are injected through the coiled tubing to break the gel in the wellbore. Second, an acidic unblocking agent is injected through the coiled tubing for spray flushing and targeted soaking to dissolve the plugging ball in the wellbore. Finally, potassium persulfate and sodium sulfite gel breaker are injected through the coiled tubing to break the gel in the formation and clear the formation. S9: Continuous tubing nitrogen lift to remove residual fluid from the wellbore, reduce fluid column pressure, and complete well injection and production; the cavitation depth of the nitrogen lift is L4, L4=100×P / (1.25×ρ); where P is the casing's resistance to external extrusion in MPa, and ρ is the completion fluid mud density in g / cm3.

2. The well workover method for lost-return wells according to claim 1, characterized in that, In step S3, before pumping in the pregel, calculate the amount of pregel used, Q1, where Q1 = π (D) 2 -D2 2 ) × H2Φ × 1.2; Where D is the diameter of the section to be injected into the formation, D2 is the outer diameter of the casing of the section to be injected into the formation, H2 is the cumulative thickness of the perforated section of the section to be injected into the formation, and Φ is the formation porosity.

3. The well workover method for lost-return wells according to claim 2, characterized in that, In step S5, before pumping in the post-installed wellbore mesh gel and plugging ball, calculate the required amounts of both: The amount of the plugging ball used is Q2, Q2= πD1 2 × (H1 + h) × 1.2, where D1 is the inner diameter of the casing of the section to be injected into the formation, H1 is the total thickness of the section to be injected into the formation, and h is the additional filling height above the perforated section, where h is 10-15m; The amount of gel used in the post-installed wellbore mesh is Q3, where Q3 = Q0 - Q2, and Q0 = π(d1) 2 L1+d2 2 L2+d3 2 L3), where Q0 is the effective tubing space volume for plugging construction, d1 is the inner diameter of the tubing in the well, L1 is its total length, d2 is the inner diameter of the tubing from the bottom end of the tubing in the well to the hanger, L2 is its total length, d3 is the inner diameter of the tubing from the hanger in the well to the upper boundary of the perforation section, L3 is its total length.

4. The well workover method for lost-return wells according to claim 3, characterized in that, In step S5, a combination of high-purity active alumina balls with median particle sizes of 5mm, 10mm, and 15mm is selected. The above particle sizes are filled in a 1:1:1 ratio to maintain the permeability of the wellbore at 10,000 mD under a high pressure of 30MPa. With the cooperation of the three, the original wellbore kill fluid is transformed from a difficult-to-control tubing flow leakage state to a controllable micro-permeability, thereby forming a controllable dynamic pressure balance between the wellbore fluid column, wellbore plugging plug, solid plugging balls, formation plugging agent, and formation fluid.

5. The well workover method for lost-return wells according to claim 4, characterized in that, In step S5, when pumping in the post-installed wellbore mesh gel and plugging ball, it is first pumped in at a speed of 0.2m... 3 Half of the total volume of the post-installed wellbore mesh gel is injected into the tubing at a flow rate of / min. Then, plugging balls of different sizes are dropped into the wellhead through a ball-dropping funnel, and pumped at 0.1m... 3 The remaining 1 / 2 of the total amount of post-wellbore mesh gel is injected into the tubing at a displacement of / min. Simultaneously, the casing is injected with fluid at a rate 1.2 times that of the temporary plugging agent. The amount of displacement fluid used must meet the requirement that the fluid level in the wellbore is about 50m higher than the equilibrium formation pressure fluid level when the temporary plug reaches the bottom of the well.

6. The well workover method for lost-return wells according to claim 1, characterized in that, In step S2, the gel plugging agent obtained from the pre-gel is a polymer solution with a viscosity of 247 mPa•s at ground conditions of 15°C before gelation.

7. The well workover method for lost-return wells according to claim 1, characterized in that, In step S2, the molecular weight of the terpolymer is (400-800) × 10 4 The degree of hydrolysis is 10%–20%.

8. The well workover method for lost-return wells according to claim 1, characterized in that, In step S6, the liquid level monitoring device is a dynamic liquid level monitoring device equipped with two sound generation methods: high and low pressure. It adopts a dual sound source channel with nitrogen cylinder sound generation and casing gas sound generation. When the pressure at the wellhead is above 3MPa, casing gas sound generation is used, and when the pressure is below 3MPa or there is no pressure, nitrogen cylinder sound generation is used.

9. The well workover method for lost-return wells according to claim 1, characterized in that, The continuous tubing includes, from top to bottom, a slip-type external connector, a double-valve check valve, a safety release connector, a two-way circulation valve, a filter, and a rotary nozzle.

10. The well workover method for lost-return wells according to claim 1, characterized in that, In step S8, the acidic unblocking agent is 10% hydrochloric acid with a mass concentration of 0.3% added.

Images