Completion process based on a thief zone
By installing packers and leakage prevention valves in the wellbore of oil and gas wells, and combining them with the use of protective fluid and nitrogen, the problem of well fluid loss in easily leaky reservoirs has been solved, achieving downhole pressure balance and ensuring the safety of oil and gas extraction.
Patent Information
- Authority / Receiving Office
- CN · China
- Patent Type
- Applications(China)
- Current Assignee / Owner
- PETROCHINA CO LTD
- Filing Date
- 2024-11-28
- Publication Date
- 2026-05-29
AI Technical Summary
When performing well completion operations in reservoirs prone to leakage, the kill fluid is easily lost in large quantities, leading to underground reservoir contamination and downhole pressure imbalance, which increases operational risks.
The first packer, leakage prevention valve, and completion string are installed in the wellbore of the oil and gas well. The packer and leakage prevention valve are used to seal the wellbore and the easily leaking reservoir. Protective fluid and nitrogen are pumped into the tubing and annulus to maintain downhole pressure balance.
It effectively prevents well-killing fluid loss, protects underground reservoirs, reduces operational risks, and maintains downhole pressure balance through changes in liquid and gas pressure, ensuring smooth oil and gas extraction.
Smart Images
Figure CN122106465A_ABST
Abstract
Description
Technical Field
[0001] This application relates to the field of oil and gas field development, and in particular to a well completion process based on easily lost reservoirs. Background Technology
[0002] In oil and gas field development, well completion is typically the final stage of drilling operations. Well completion refers to the process of connecting the wellbore and the oil and gas reservoir in a specific structure after drilling to the designed well depth. During well completion, kill fluid is usually used to balance downhole pressure and prevent production accidents such as blowouts and well kicks. However, if the oil and gas reservoir is located in a vulnerable, leaky reservoir, which typically has numerous fractures and caverns, it can lead to significant loss of kill fluid. This not only contaminates the underground reservoir but also causes downhole pressure imbalances, increasing the risk of production accidents and posing a high operational risk. Therefore, how to perform well completion based on vulnerable, leaky reservoirs is a technical problem that needs to be solved. Summary of the Invention
[0003] This application provides a well completion process based on easily lost circulation reservoirs, which can avoid contamination or well pressure imbalance caused by large-scale loss of kill fluid during well completion operations in easily lost circulation reservoirs, thereby reducing operational risks. The technical solution is as follows:
[0004] This application provides a coalbed methane horizontal well extraction process, the process including:
[0005] A first packer, a first set-in sub, and a leakage prevention valve are installed in the production casing of the oil and gas well. The first packer is used to seal the oil and gas well and the easily leaking reservoir at the corresponding set-in position. The upper end of the first set-in sub is connected to the first packer, and the lower end of the first set-in sub is connected to the leakage prevention valve.
[0006] A completion string is run into the production casing until the return pipe at the lower end of the completion string is inserted into the return sleeve at the upper end of the first packer. The completion string includes tubing and multiple downhole devices connected to the tubing.
[0007] In the case where the downhole equipment includes a second packer, the second packer is set, and the second packer is used to seal a first annular space and a second annular space at a corresponding setting position. The first annular space is the space between the outer wall of the tubing above the second packer and the inner wall of the production casing, and the second annular space is the annular space between the first packer and the second packer.
[0008] Protective fluid and nitrogen are pumped sequentially into the oil pipe and the first annular space to fill the oil pipe and the first annular space with the protective fluid and nitrogen in layers, with the nitrogen located above the protective fluid.
[0009] Open the anti-leakage valve to allow oil and gas in the easily leaking reservoir to flow into the gas production tree through the tubing. The gas production tree is the surface collection equipment for the oil and gas well.
[0010] In one possible implementation, the insertion of a first packer, a first landing sub, and a leakage prevention valve into the production casing within the oil and gas wellbore includes:
[0011] Inside the production casing of the oil and gas well, the first packer is lowered into the corresponding setting position, and the first packer is connected to the anti-leakage valve through the first setting sub.
[0012] At the setting position of the first packer, the first packer is set, and the setting is used to tightly fit the rubber sleeve of the first packer with the inner wall of the production sleeve.
[0013] In another possible implementation, the process further includes:
[0014] Pressure is applied inside the production sleeve;
[0015] Based on the decrease in pressure within the production casing during a first time period, it is determined whether the first packer has been successfully set.
[0016] In another possible implementation, the process further includes:
[0017] Before the first packer is inserted, a scraper is inserted into the production sleeve to remove foreign matter adhering to the inner wall of the production sleeve.
[0018] The setting positions of the first packer and the second packer are scraped using the scraper until the weight of the scraper does not change significantly.
[0019] The well is cleaned using a washing fluid until the injected washing fluid has the same liquid properties as the washing fluid discharged from the wellbore of the oil and gas well.
[0020] In another possible implementation, the completion string includes multiple connected tubing, and the step of running the completion string into the production casing until the back-in pipe at the lower end of the completion string is inserted into the back-in sleeve at the upper end of the first packer includes:
[0021] Multiple tubing units are sequentially run into the production casing, with adjacent tubing units being directly connected or connected through the downhole equipment. The downhole equipment includes at least one of a second landing sub, a sliding sleeve, a second packer, a flow joint, and a downhole safety valve.
[0022] During the installation of the multiple oil pipes, an airtightness test is performed at the joints of the multiple oil pipes.
[0023] In another possible implementation, the downhole equipment further includes a second landing section located below the second packer;
[0024] When the downhole equipment includes a second packer, setting the second packer includes:
[0025] A gauge is inserted into the oil pipe up to the second short section. The gauge is used to check whether the oil pipe is unobstructed.
[0026] With the oil pipe unobstructed, a sealing test is performed on the gas production tree and the oil pipe.
[0027] If the gas tree and the tubing pass the sealing test, a plug is inserted into the tubing up to the second landing section. The plug is used to seal the space above the second landing section and the space below the second landing section in the tubing.
[0028] The second packer is pressurized in the space above the second short section so that the rubber sleeve of the second packer fits tightly against the inner wall of the production sleeve;
[0029] Remove the plug located at the second short section.
[0030] In another possible implementation, the downhole equipment further includes a sliding sleeve located above the second packer;
[0031] With the oil pipe unobstructed, the sealing test of the gas production tree and the oil pipe includes:
[0032] A plug is inserted into the oil pipe up to the sliding sleeve. The plug is used to seal the space above the sliding sleeve and the space below the sliding sleeve within the oil pipe.
[0033] Pressurization is applied to the gas tree and the tubing to test their sealing performance.
[0034] If the sealing test is passed, remove the plug from the sliding sleeve.
[0035] In another possible implementation, the process further includes:
[0036] Pressure is applied within the first annular space;
[0037] Based on the decrease in pressure within the first annular space during the second time period, it is determined whether the second packer has been successfully set.
[0038] In another possible implementation, the downhole equipment further includes a sliding sleeve located above the second packer. The sliding sleeve includes a plurality of orifices for connecting the space inside the tubing with the first annular space through the plurality of orifices in the open state.
[0039] The step of sequentially pumping protective fluid and nitrogen into the oil pipe and the first annular space includes:
[0040] Open the sliding sleeve;
[0041] With the sliding sleeve in the open state, the protective fluid is pumped into the oil pipe to fill the oil pipe and the first annular space with the protective fluid.
[0042] The nitrogen gas is pumped into the oil pipe to fill the oil pipe with the protective liquid and nitrogen gas in two separate layers.
[0043] The nitrogen gas is pumped into the first annular space to fill the first annular space with the protective liquid and nitrogen gas in two layers.
[0044] Close the sliding sleeve.
[0045] In another possible implementation, the process further includes:
[0046] Pressure is applied within the first annular space;
[0047] Based on the decrease in pressure value within the first annular space during the third time period, it is determined whether the sliding sleeve has been successfully closed.
[0048] When the sliding sleeve is successfully closed, release part of the pressure in the first annular space until the pressure value at the sliding sleeve drops to the target value.
[0049] This application provides a completion process for easily lost-flow reservoirs. During well completion operations in oil and gas wells, a first packer and a connected anti-leakage valve are first installed in the production casing within the wellbore to isolate the wellbore and the easily lost-flow reservoir. Subsequently, during the installation of the completion string in the production casing and the pumping of protective fluid and nitrogen into the tubing and annulus, the fluid in the wellbore will not leak into the underground reservoir, preventing contamination of the underground reservoir or pressure imbalance within the well, thereby reducing operational risks. The pumping of protective fluid and nitrogen not only protects the tubing and production casing from corrosion but also maintains downhole pressure balance through changes in fluid or gas pressure. Then, by opening the bottom-layer anti-leakage valve, oil and gas in the easily lost-flow reservoir can flow into the tubing under pressure, thus achieving oil and gas harvesting. Attached Figure Description
[0050] To more clearly illustrate the technical solutions in the embodiments of this application, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of the embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.
[0051] Figure 1 This is a flowchart of a well completion process for a leaky reservoir provided in an embodiment of this application;
[0052] Figure 2 This is a schematic diagram of a tubular column provided in an embodiment of this application. Detailed Implementation
[0053] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the implementation methods of this application will be further described in detail below with reference to the accompanying drawings.
[0054] It is understood that the terms "first," "second," etc., used in this application may be used to describe various concepts herein, but unless otherwise stated, these concepts are not limited by these terms. These terms are only used to distinguish one concept from another. For example, without departing from the scope of this application, a first packer may be referred to as a second packer, and similarly, a second packer may be referred to as a first packer.
[0055] Figure 1 This is a flowchart of a well completion process for a leaky reservoir provided in an embodiment of this application. See also... Figure 1 The process includes:
[0056] Step 101: Run a first packer, a first set-in sub, and a leakage prevention valve into the production casing of the oil and gas well. The first packer is used to seal the oil and gas well casing and the easily leaking reservoir at the corresponding set-in position. The upper end of the first set-in sub is connected to the first packer, and the lower end of the first set-in sub is connected to the leakage prevention valve.
[0057] In the drilling process of oil and gas wells, multiple drilling operations and casing runs are typically performed. For example, the first drilling operation (also called the first run) drills a relatively large diameter wellbore from the surface, and then runs in surface casing to establish a passage between the wellhead and the underground, providing stable wellhead conditions for subsequent drilling. Then, a second drilling operation is performed within the surface casing to drill a section of the well with a diameter smaller than the first run, and then runs in technical casing. Finally, a third drilling operation is performed within the technical casing to continue drilling to the predetermined depth, and then runs in production casing. Therefore, the production casing in the wellbore of an oil and gas well is the casing run after the third drilling operation; the production casing can also be called the reservoir casing. Reservoir casing is used to isolate the extracted oil and gas from the underground reservoir in the passage from the oil and gas to the surface.
[0058] In this step, after running the production casing and before drilling to the vulnerable reservoir, a first packer, a first landing sub, and a leakage prevention valve can be run into the production casing. The first packer can be a temporary packer. The leakage prevention valve is in the closed state. Through the temporary packer and the closed leakage prevention valve, the wellbore and the vulnerable reservoir of the oil and gas well can be isolated within the production casing, thereby temporarily closing the reservoir and preventing fluid leakage from the wellbore into the vulnerable reservoir. At the end of the completion phase, the leakage prevention valve can be broken to allow oil and gas in the vulnerable reservoir to flow into the wellbore. Correspondingly, since the leakage prevention valve is usually irreparable after being broken, a plug can be placed at the first landing sub during later replacement of the completion string, thereby temporarily closing the reservoir during the replacement process, i.e., temporarily isolating the wellbore and the vulnerable reservoir of the oil and gas well.
[0059] Figure 2 This is a schematic diagram of a tubular column provided in an embodiment of this application. Figure 2 As shown, production casing 206 is the casing installed after the third drilling operation. 213 is the open hole section without casing. The upper end of the first placement sub 210-1 is connected to the first packer 211, and the lower end of the first placement sub 210-1 is connected to the anti-leakage valve 212. In this step, casing can be installed simultaneously inside the production casing according to… Figure 2 The first packer 211, the first landing section 210-1, and the leak-proof valve 212 are connected in the manner shown.
[0060] In one possible implementation, during the aforementioned temporary reservoir closure process, a first packer can be lowered into the corresponding setting position within the production casing. The setting position of the first packer can be set according to actual production needs. For example, the first packer can be set at the bottom of the production casing. Then, the first packer is set at its setting position. Setting refers to applying pressure to the first packer to ensure a tight fit between the packer's sleeve and the inner wall of the production casing. By setting the first packer at the corresponding setting position, the space above the setting position and the easily leaking reservoir below the setting position can be isolated, thereby achieving temporary reservoir closure.
[0061] Optionally, if the first packer is lowered into the setting position via the drill pipe, the rubber sleeve of the first packer can be expanded and tightly fitted to the inner wall of the production casing by pressing into the drill pipe, thereby achieving temporary closure of the reservoir through the sealing performance of the rubber sleeve.
[0062] In one possible implementation, to ensure the sealing effect of the packers, the setting positions of multiple packers can be scraped using a scraper before the packers are installed in the production casing. First, a scraper is installed in the production casing via drill pipe. The scraper is used to remove foreign matter adhering to the inner wall of the production casing. Then, the setting positions of the first and second packers are repeatedly scraped using the scraper until the weight suspended on the scraper shows no significant change, indicating that scraping is complete. The second packer can be any packer installed in the production casing during well completion operations. Then, a well-washing fluid is injected into the production casing to clean the well until the injected well-washing fluid has the same liquid properties as the well-washing fluid discharged from the oil and gas wellbore, indicating that well-washing is complete. The well-washing fluid can be clean water. The liquid properties of the washing fluid include, but are not limited to, at least one of the following: density, viscosity, color, and turbidity. Optionally, the flow rate of the flushing fluid injected through the drill pipe is typically not less than 0.5 cubic meters per minute, thereby cleaning away foreign matter in the wellbore as much as possible and ensuring the flushing effect. By scraping the setting position on the inner wall of the production casing before running the packer, and then flushing the well to remove the scraped foreign matter, the setting position can be ensured to be smooth and flat, thus preventing foreign matter adhering to the inner wall of the casing from affecting the sealing effect of the packer.
[0063] Step 102: Pressurize the production casing. Based on the decrease in pressure within the production casing during the first time period, determine whether the first packer has been successfully set.
[0064] In this step, after setting the first packer, pressure is applied to the production casing, and the pressure value inside the production casing is monitored. Optionally, pressure can be applied to the production casing via the drill pipe to test the sealing performance of the first packer. If the pressure drop in the production casing within the first time period is less than a preset threshold, it indicates that the first packer has good sealing performance and the first packer has been successfully set. If the pressure drop in the production casing within the first time period is not less than the preset threshold, it indicates that the first packer has poor sealing performance and the first packer has failed to set. The preset threshold can be a pre-set value, such as 0.7 MPa, 1 MPa, etc. The first time period can be a time period set according to actual needs, such as 5 minutes, 10 minutes, etc. Using pressure testing to verify the sealing effect of the first packer can be done relatively quickly and accurately.
[0065] In one possible implementation, if the first packer fails to set, the first packer can be re-set at the same setting position, or another temporary packer can be set at the same setting position, or another temporary packer can be set at a different setting position. This application does not limit this.
[0066] Step 103: Run the completion string into the production casing until the back-insertion tube at the lower end of the completion string is inserted into the back-connecting tube at the upper end of the first packer. The completion string includes tubing and multiple downhole devices connected to the tubing.
[0067] In this step, the first packer has a return sleeve at its top. After the first packer is successfully set, the completion string is run into the production casing. It should be noted that during the running-in of the completion string, it should be lowered slowly as it approaches the first packer until the return tube at the lower end of the completion string smoothly inserts into the return sleeve at the top of the first packer. The completion string includes tubing and multiple downhole devices connected to the tubing. Optionally, all downhole devices and the tubing have the same diameter.
[0068] In one possible implementation, the completion string includes multiple connected tubing sections. During the running-in of the completion string, multiple tubing sections can be sequentially run into the production casing. Adjacent tubing sections are directly connected or connected via downhole equipment. Downhole equipment includes, but is not limited to, at least one of: a second placement sub, a sliding sleeve, a second packer, a flow joint, and a downhole safety valve. The second placement sub is typically located below the second packer and is used to place a plug to pressure-set the second packer within the enclosed space above the plug. The second packer can be a completion packer. The sliding sleeve is typically located above the second packer and, in the open state, connects the space inside the tubing with the annular space outside the tubing. The annular space outside the tubing is the space between the outer wall of the tubing and the inner wall of the production casing. During the running-in of multiple tubing sections, the sliding sleeve is in the closed state. Additionally, during the running-in of multiple tubing sections, gas tightness testing can be performed at the joints to verify the sealing performance of the joints.
[0069] Optionally, during the installation of multiple oil pipes, a target gas, such as helium, can be injected into each pipe. Then, a gas detector is used to check for the presence of the target gas at the connection point between any two oil pipes. If the target gas is not detected, it indicates that there is no gas leakage at the connection point and that the connection is well-sealed.
[0070] Step 104: If the downhole equipment includes a second packer, set the second packer, which is used to seal the first annular space and the second annular space at the corresponding setting position.
[0071] In this step, if the downhole equipment includes a second packer, after the completion string is run, the second packer is set at its setting position. Successful setting of the second packer seals both the first and second annular spaces. The first annular space is the space between the outer wall of the tubing above the second packer and the inner wall of the production casing, while the second annular space is the annular space between the first and second packers. As described above. Figure 2 As shown, 209 is the second packer, and 207 is the tubing. The first annular space is the annular space located above the second packer 209, between the outer wall of the tubing 207 and the inner wall of the production casing 206. The second annular space is the annular space located between the second packer 209 and the first packer 211, between the outer wall of the tubing 207 and the inner wall of the production casing 206.
[0072] In one possible implementation, when the downhole equipment includes a second packer, the return pipe at the lower end of the completion string does not require a sealing or anchoring device. The absence of a sealing device is to prevent the return pipe from forming a completely sealed space within the second annular space after it is inserted into the return sleeve at the top of the first packer. If such a completely sealed space exists, the gas or liquid within it may expand due to heat during subsequent oil and gas production, leading to an increase in pressure within the second annular space and affecting the sealing performance of both the first and second packers. The absence of an anchoring device is to avoid the inability to accurately control equipment requiring unanchoring. Since the second packer typically has an anchoring device, if the return pipe also has an anchoring device, unanchoring by rotating the completion string may simultaneously unanchor both the second packer and the return pipe, resulting in inaccurate control of the equipment requiring anchoring.
[0073] In one possible implementation, the downhole equipment further includes a second placement sub for placing the plug to pressure-set the second packer within the enclosed space above the plug. As described above. Figure 2 As shown, the second mounting section 210-2 is typically located below the second packer 209. The process of mounting the second packer is described below through steps 1041-1045.
[0074] Step 1041: Lower a gouge gauge into the tubing up to the second landing section. The gouge gauge is used to check if the tubing is unobstructed. Lowering the gouge to the second landing section allows for verification of the flow of the tubing from the wellhead to the second landing section.
[0075] Step 1042: With the tubing unobstructed, perform a sealing test on the gas tree and tubing. The gas tree is the surface-mounted gas collection equipment for oil and gas wells. By performing a sealing test on the gas tree and tubing, oil and gas leaks can be prevented, thus ensuring oil and gas production while avoiding environmental pollution.
[0076] In one possible implementation, the downhole equipment also includes a sliding sleeve. As described above. Figure 2As shown, the sliding sleeve 208 is located above the second packer 209. A plug is inserted into the tubing up to the sliding sleeve, sealing the space above and below the sliding sleeve within the tubing. Then, pressure is applied to the gas tree and tubing to test their sealing performance. Optionally, after pressure testing, the sealing performance of the gas tree and tubing can be tested based on the pressure drop over a period of time. For example, if the pressure is applied to the gas tree and tubing at 70 MPa, and the pressure drop is less than 0.7 MPa after 10 minutes, the gas tree and tubing pass the sealing test. After passing the sealing test, the pressure in the gas tree and tubing can be released, and the plug at the sliding sleeve can be removed.
[0077] Step 1043: After the gas source tree and tubing pass the sealing test, a plug can be inserted into the tubing up to the second landing section. The plug seals off the space above the second landing section and the space below the second landing section within the tubing. (As described above) Figure 2 As shown, by placing a plug at the second location stub 210-2, the space above the second location stub 210-2 in the oil pipe can be sealed off by the plug.
[0078] Step 1044: Pressurize the second packer in the space above the second mounting section. Under pressure, the rubber sleeve of the second packer fits tightly against the inner wall of the production sleeve, thereby setting the second packer. Since the space below the second mounting section was sealed by the plug in step 1043, pressurizing the second packer in the space above the second mounting section can prevent pressure loss, thus ensuring sufficient pressure to set the second packer.
[0079] Step 1045: After setting the second packer, the plug at the second short section can be removed.
[0080] In one possible implementation, after setting the second packer, pressure can be applied to the first annular space. The pressure value within the first annular space is then monitored. Based on the pressure drop within the first annular space over a second time period, it is determined whether the second packer has been successfully set. Optionally, pressure can be applied to the gas tree and tubing at 10 MPa; if the pressure drop is less than 0.7 MPa after 10 minutes, the second packer has been successfully set.
[0081] Step 105: Pump protective fluid and nitrogen into the oil pipe and the first annular space in sequence, so that the oil pipe and the first annular space are filled with protective fluid and nitrogen in layers, with the nitrogen located above the protective fluid.
[0082] In this step, after the second packer is successfully set, protective fluid and nitrogen can be pumped sequentially into the tubing and the first annular space, filling both the tubing and the first annular space with stratified nitrogen and protective fluid. The protective fluid and nitrogen not only inhibit corrosion of downhole equipment such as the tubing and production casing, but also maintain downhole pressure balance through changes in liquid or gas pressure.
[0083] In one possible implementation, as described above Figure 2 As shown, the downhole equipment includes a sliding sleeve 208, which has multiple orifices. The sliding sleeve 208, when open, connects the space inside the tubing with the first annular space through these orifices. The process of pumping in protective fluid and nitrogen is described below through steps 1051-1055.
[0084] Step 1051: Open the sliding sleeve. Optionally, a sliding sleeve repositioning tool can be inserted into the oil pipe to open the sliding sleeve, and then the sliding sleeve repositioning tool can be removed. After opening the sliding sleeve, the space inside the oil pipe and the first annular space can be connected through the multiple holes on the sliding sleeve, so that the space inside the oil pipe and the first annular space can form a U-shaped space.
[0085] Step 1052: With the sliding sleeve in the open position, pump protective fluid into the tubing through the pumping device at the wellhead. Once the protective fluid reaches the sliding sleeve, it flows into the first annular space through the orifices on the sleeve. By continuously pumping protective fluid into the tubing from the wellhead, the tubing and the first annular space are filled with protective fluid. Step 1052 is also the process of replacing the protective fluid. "Replacing" refers to replacing the tubing with fluid or gas.
[0086] Step 1053: After replacing the protective fluid, pump nitrogen into the tubing at the wellhead to fill the tubing with the protective fluid and nitrogen in two separate layers.
[0087] Step 1054: Pump nitrogen gas into the first annular space at the wellhead to fill the first annular space with stratified protective fluid and nitrogen gas. Step 1054 is also the process of nitrogen gas replacement. Here, replacement refers to replacing the fluid or gas into the first annular space. Optionally, by replacing the nitrogen gas, a nitrogen gas level of about 100 meters can be maintained above the first annular space.
[0088] Step 1055: After replacing the nitrogen, close the sliding sleeve. Optionally, the sliding sleeve repositioning tool can be lowered back into the oil pipe to close the sliding sleeve, and then the tool can be removed. After removing the tool, the successful closure of the sliding sleeve can be verified by checking the release pin on the tool.
[0089] In one possible implementation, after closing the sliding sleeve, pressure can be applied within the first annular space. Then, based on the pressure drop within the first annular space over a third time period, it is determined whether the sliding sleeve has successfully closed. For example, if 10 MPa is applied to the first annular control, and the pressure drop is less than 0.7 MPa after 30 minutes, the sliding sleeve has successfully closed. If the sliding sleeve has successfully closed, a portion of the pressure within the first annular space is released until the pressure at the sliding sleeve drops to a target value. This target value can be a preset value, such as 4 MPa, 5 MPa, etc., and this embodiment does not impose any limitations on this.
[0090] Step 106: Open the anti-leakage valve to allow oil and gas in the easily leaking reservoir to flow into the gas production tree through the oil pipe.
[0091] In this step, a breaking tool is lowered and used to break the bottom leak-proof valve. After the leak-proof valve is broken, the leaky reservoir is connected to the tubing. Then, the wellhead gate is opened, allowing oil and gas in the leaky reservoir to flow into the surface wellhead through the tubing under the pressure difference.
[0092] As mentioned above Figure 2 As shown, 201 is the gas production tree, 202 is the tubing head, and 203 is the casing head. The casing head is an important connection between the casing and the wellhead equipment, used to suspend and seal each layer of casing, and to provide support for the installation of the tubing head, gas production tree, and other wellhead equipment. The tubing head is installed above the casing head, used to suspend the tubing string, seal the annular space between the tubing and the casing, and provide a transition connection for the installation of the gas production tree and other wellhead equipment. 204 is a flow joint, and 205 is a downhole safety valve. The downhole safety valve is an important safety device, mainly used to automatically close the fluid passage in the well in emergencies to prevent blowouts, leaks, and other accidents.
[0093] This application provides a completion process for easily lost-flow reservoirs. During well completion operations in oil and gas wells, a first packer and a connected anti-leakage valve are first installed in the production casing within the wellbore to isolate the wellbore and the easily lost-flow reservoir. Subsequently, during the installation of the completion string in the production casing and the pumping of protective fluid and nitrogen into the tubing and annulus, the fluid in the wellbore will not leak into the underground reservoir, preventing contamination of the underground reservoir or pressure imbalance within the well, thereby reducing operational risks. The pumping of protective fluid and nitrogen not only protects the tubing and production casing from corrosion but also maintains downhole pressure balance through changes in fluid or gas pressure. Then, by opening the bottom-layer anti-leakage valve, oil and gas in the easily lost-flow reservoir can flow into the tubing under pressure, thus achieving oil and gas harvesting.
[0094] The above are merely optional embodiments of the present application and are not intended to limit the present application. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present application should be included within the protection scope of the present application.
Claims
1. A well completion process based on easily lost-flow reservoirs, characterized in that, The process includes: A first packer, a first set-in sub, and a leakage prevention valve are installed in the production casing of the oil and gas well. The first packer is used to seal the oil and gas well and the easily leaking reservoir at the corresponding set-in position. The upper end of the first set-in sub is connected to the first packer, and the lower end of the first set-in sub is connected to the leakage prevention valve. A completion string is run into the production casing until the return pipe at the lower end of the completion string is inserted into the return sleeve at the upper end of the first packer. The completion string includes tubing and multiple downhole devices connected to the tubing. In the case where the downhole equipment includes a second packer, the second packer is set, and the second packer is used to seal a first annular space and a second annular space at a corresponding setting position. The first annular space is the space between the outer wall of the tubing above the second packer and the inner wall of the production casing, and the second annular space is the annular space between the first packer and the second packer. Protective fluid and nitrogen are pumped sequentially into the oil pipe and the first annular space to fill the oil pipe and the first annular space with the protective fluid and nitrogen in layers, with the nitrogen located above the protective fluid. Open the anti-leakage valve to allow oil and gas in the easily leaking reservoir to flow into the gas production tree through the tubing. The gas production tree is the surface collection equipment for the oil and gas well.
2. The process according to claim 1, characterized in that, The process of installing a first packer, a first landing sub, and a leakage prevention valve into the production casing of an oil and gas well includes: Inside the production casing of the oil and gas well, the first packer is lowered into the corresponding setting position, and the first packer is connected to the anti-leakage valve through the first setting sub. At the setting position of the first packer, the first packer is set, and the setting is used to tightly fit the rubber sleeve of the first packer with the inner wall of the production sleeve.
3. The process according to claim 2, characterized in that, The process also includes: Pressure is applied inside the production sleeve; Based on the decrease in pressure within the production casing during a first time period, it is determined whether the first packer has been successfully set.
4. The process according to claim 1, characterized in that, The process also includes: Before the first packer is inserted, a scraper is inserted into the production sleeve to remove foreign matter adhering to the inner wall of the production sleeve. The setting positions of the first packer and the second packer are scraped using the scraper until the weight of the scraper does not change significantly. The well is cleaned using a washing fluid until the injected washing fluid has the same liquid properties as the washing fluid discharged from the wellbore of the oil and gas well.
5. The process according to claim 1, characterized in that, The completion string includes multiple connected tubing. The process of running the completion string into the production casing until the return pipe at the lower end of the completion string is inserted into the return sleeve at the upper end of the first packer includes: Multiple tubing units are sequentially run into the production casing, with adjacent tubing units being directly connected or connected through the downhole equipment. The downhole equipment includes at least one of a second landing sub, a sliding sleeve, a second packer, a flow joint, and a downhole safety valve. During the installation of the multiple oil pipes, an airtightness test is performed at the joints of the multiple oil pipes.
6. The process according to claim 1, characterized in that, The downhole equipment also includes a second placement section, which is located below the second packer; When the downhole equipment includes a second packer, setting the second packer includes: A gauge is inserted into the oil pipe up to the second short section. The gauge is used to check whether the oil pipe is unobstructed. With the oil pipe unobstructed, a sealing test is performed on the gas production tree and the oil pipe; If the gas tree and the tubing pass the sealing test, a plug is inserted into the tubing up to the second landing section. The plug is used to seal the space above the second landing section and the space below the second landing section in the tubing. The second packer is pressurized in the space above the second short section so that the rubber sleeve of the second packer fits tightly against the inner wall of the production sleeve; Remove the plug located at the second short section.
7. The process according to claim 6, characterized in that, The downhole equipment also includes a sliding sleeve, which is located above the second packer; With the oil pipe unobstructed, the sealing test of the gas production tree and the oil pipe includes: A plug is inserted into the oil pipe up to the sliding sleeve. The plug is used to seal the space above the sliding sleeve and the space below the sliding sleeve within the oil pipe. Pressurization is applied to the gas tree and the tubing to test their sealing performance. If the sealing test is passed, remove the plug from the sliding sleeve.
8. The process according to claim 6, characterized in that, The process also includes: Pressure is applied within the first annular space; Based on the decrease in pressure within the first annular space during the second time period, it is determined whether the second packer has been successfully set.
9. The process according to claim 1, characterized in that, The downhole equipment also includes a sliding sleeve, which is located above the second packer. The sliding sleeve includes multiple holes, and the sliding sleeve is used to connect the space inside the tubing with the first annular space through the multiple holes when the device is open. The step of sequentially pumping protective fluid and nitrogen into the oil pipe and the first annular space includes: Open the sliding sleeve; With the sliding sleeve in the open state, the protective fluid is pumped into the oil pipe to fill the oil pipe and the first annular space with the protective fluid. The nitrogen gas is pumped into the oil pipe to fill the oil pipe with the protective liquid and nitrogen gas in two separate layers. The nitrogen gas is pumped into the first annular space to fill the first annular space with the protective liquid and nitrogen gas in two layers. Close the sliding sleeve.
10. The process according to claim 9, characterized in that, The process also includes: Pressure is applied within the first annular space; Based on the decrease in pressure value within the first annular space during the third time period, it is determined whether the sliding sleeve has been successfully closed. When the sliding sleeve is successfully closed, release part of the pressure in the first annular space until the pressure value at the sliding sleeve drops to the target value.