Circulating valve, drilling pipe string and drilling circulation pressure control method

Abstract

The application discloses a circulating valve, a drilling pipe column and a drilling circulating pressure control method, and relates to the technical field of drilling equipment. The circulating valve comprises a valve body, at least a first end and a second end are arranged on the valve body, a first channel is arranged in the valve body and is communicated with the first end and the second end, a valve piece is arranged in the first channel, a packer capable of being compressed and expanded is arranged on the valve body, a piston capable of sliding and extruding the packer is arranged on the valve body, and a second channel is arranged on the valve body above the packer. In a conducting state of the valve piece, the first channel is conducted, and the piston blocks the second channel. In a disconnecting state of the valve piece, the valve piece blocks the first channel, and pressure in the valve body above the valve piece drives the piston to slide to a position where the second channel is conducted, so that an external space of the valve body above the packer is communicated. The application solves the technical problem of low well control safety in the drilling process by using the existing method and device.

Description

TECHNICAL FIELD

[0001] The present application relates to the field of oilfield drilling engineering, and particularly relates to a circulating valve, a drilling pipe string and a drilling circulating pressure control method. BACKGROUND

[0002] During oil exploitation, complex deep formations are drilled. If the window between the pore pressure and the fracture pressure of the formation is relatively small, problems such as well kick, well leakage, harmful gas leakage, and sticking and tripping for too long time often occur, which not only prolongs the drilling time, but also causes safety and pollution problems. If the downhole pressure can be effectively controlled during drilling, the above problems can be alleviated.

[0003] Managed pressure drilling is a technology for controlling the wellbore pressure in time during drilling, and is gradually widely used in oil exploitation. The managed pressure drilling is to accurately control the wellbore pressure, so that the bottom hole pressure is always in a stable state. The operator controls the wellhead back pressure through the managed pressure drilling device to realize real-time adjustment and ensure that the bottom hole pressure is always within a reasonable range. At present, the wellbore pressure can be controlled in the following ways:

[0004] I. Wellhead back pressure control. The opening of the throttle valve at the wellhead is adjusted to adjust the wellhead back pressure, so that the wellbore pressure is always maintained within a reasonable range. Through accurate control of the bottom hole pressure, the managed pressure drilling can effectively prevent well leakage and avoid well control accidents such as overflow that may occur during drilling.

[0005] II. Constant bottom hole pressure method. Balanced drilling is usually carried out with a lower drilling fluid density than the conventional drilling method. The bottom hole pressure during circulation is equal to the static column pressure plus the annular pressure loss. When the well is closed and the drill pipe is connected, the circulation pressure loss disappears at the same time, so that the bottom hole pressure is in an unbalanced state. Then, the back pressure is added at the wellhead to balance the bottom hole pressure, so that the problem of formation fluid invasion can be avoided.

[0006] III. Pressurized mud cap method. This technology mainly applies a positive pressure at the wellhead when the annular fluid density in the well is small. Under normal circumstances, this technology can effectively control the problem of well leakage. If the reservoir pressure is less than the net water pressure head, the mud cap drilling technology (without pressure) needs to be used, and clean water is pumped into the annulus during drilling fluid leakage. At this time, the wellbore gas will be pressed back into the leakage formation by the annular clean water, so that the construction work can continue. If the reservoir pressure is greater than the static water pressure head, the pressurized mud cap drilling technology needs to be used, and the wellbore pressure is balanced by using the weighted drilling fluid. In addition, before the pressurized mud cap drilling technology is implemented, the mud cap needs to be weighted and thickened, and the drilling fluid needs to be slowly injected into the annulus to prevent oil and gas from entering the annulus, so that the wellbore pressure control balance can be ensured.

[0007] IV. HSE drilling technology is a controlled pressure drilling technology that returns drilling fluid to the drilling platform. It incorporates a pressurized, closed-loop drilling fluid circulation system. The closed-loop drilling fluid circulation system can effectively prevent gas and delayed cuttings from flowing out of the drilling platform, thereby reducing the content of hydrogen sulfide gas and reducing the safety hazards caused by sparks on the drilling platform.

[0008] However, when gas intrusion, overflow, or well kick occurs, the aforementioned methods, while capable of displacing the gas-infiltrated mud from the annulus during the circulation and replacement process, simultaneously allow gas from the producing formation to continuously enter the wellbore and annulus, resulting in excessively long processing times. Furthermore, the high pressure at the wellhead, long open-hole sections, and low pressure-bearing capacity of the lost circulation zone pose significant safety risks, impacting the safety of personnel, equipment, and the downhole environment. Additionally, current pressure-controlled drilling equipment is primarily installed at the wellhead and surface, while conventional drilling tools are still used for downhole tubing. This results in uniform pressure when drilling through long, open-hole formations with multiple pressure systems, increasing the risk of complex downhole problems, especially in weak formations.

[0009] There is currently no effective solution to the problem of low safety in controlling wellbore pressure during drilling using existing methods and devices in related technologies.

[0010] Therefore, based on years of experience and practice in related industries, the inventor proposes a circulation valve, drilling string, and drilling circulation pressure control method to overcome the shortcomings of existing technologies. Summary of the Invention

[0011] The purpose of this invention is to provide a circulation valve, drilling string, and drilling circulation pressure control method, which can reduce the risk of wellhead control, thereby reducing the overall risk of well control, shortening the well control time, ensuring well control safety, and avoiding well control failure accidents.

[0012] The objective of this invention can be achieved using the following technical solutions:

[0013] The present invention provides a circulation valve, the circulation valve including a valve body, the valve body having at least a first end and a second end, the valve body having a first channel communicating with the first end and the second end, the first channel having a valve component, the valve body having a compressible and expandable packer sleeved on it, the valve body having a piston sleeved on it that can slide and squeeze the packer, and the valve body having a second channel located above the packer.

[0014] When the valve is in the conducting state, the first channel is open, and the piston blocks the second channel;

[0015] When the valve is in the open state, the valve blocks the first channel. The pressure inside the valve body and above the valve pushes the piston to slide to the second channel open position, so that the external space of the valve body above the packer is connected to the first end of the valve body through the second channel and the first channel above the valve.

[0016] In a preferred embodiment of the present invention, a sliding sleeve is slidably disposed within the valve body. Both the valve body and the sliding sleeve are cylindrical structures with openings at both ends. The valve component is disposed within the sliding sleeve. A first through hole is provided on the sliding sleeve. An annular flow channel is formed within the valve wall of the valve body. A second through hole and a third through hole are respectively provided on the valve body. The second through hole connects the flow channel with the interior of the valve body, and the third through hole connects the flow channel with the external space of the valve body located above the packer.

[0017] When the valve is in the conducting state, the first through hole and the second through hole are offset, and the piston is blocked at the third through hole;

[0018] When the valve is in the open state, pressure is applied to the valve body from the first end and pushes the sliding sleeve to slide, so that the first through hole moves to a position communicating with the second through hole. The pressure enters the flow channel from the first through hole and the second through hole and pushes the piston to slide to a position where the third through hole communicates with the flow channel. The third through hole, the flow channel, the second through hole and the first through hole cooperate to form the second channel.

[0019] In a preferred embodiment of the present invention, a first protrusion and a second protrusion are respectively provided on the outer wall of the sliding sleeve and the inner wall of the valve body. The outer wall of the sliding sleeve, the inner wall of the valve body, the first protrusion and the second protrusion together form an annular accommodating cavity. A spring is provided in the accommodating cavity. When the valve is in the open state, the sliding sleeve moves and the space of the accommodating cavity decreases, and the spring is in a compressed state. When the valve is restored to the open state, the spring pushes the sliding sleeve back to its original position.

[0020] In a preferred embodiment of the present invention, a limiting ring is provided in the valve body and near the first end, and the sliding sleeve can abut against the limiting ring to limit the movement of the sliding sleeve toward the first end.

[0021] In a preferred embodiment of the present invention, the distance between the first through hole and the first end is less than the distance between the valve and the first end.

[0022] In a preferred embodiment of the present invention, a shear pin is connected between the sliding sleeve and the valve body.

[0023] In a preferred embodiment of the present invention, the piston has an annular structure, the lower part of the piston abuts against the top of the packer, the upper part of the piston extends into the flow channel, and the piston is slidably and sealingly connected to the inner wall of the flow channel.

[0024] In a preferred embodiment of the present invention, the third through hole is connected to the flow channel and is located near the packer, and the second through hole is connected to the flow channel and is located away from the packer. When the valve is in the open state, the upper part of the piston blocks the third through hole.

[0025] In a preferred embodiment of the present invention, the valve is a ball valve.

[0026] In a preferred embodiment of the present invention, the ball valve includes a valve seat and a valve ball. The valve seat has an annular structure and is disposed within the sliding sleeve. The valve ball is inserted into the sliding sleeve through the first end and sits on the valve seat to block the first channel.

[0027] In a preferred embodiment of the present invention, a ball guard is provided inside the valve body and near the second end. When the valve is in the open state, the pressure applied from the first end to the valve body is increased to squeeze the valve ball to deform, pass through the valve seat, and fall into the ball guard, and the valve is restored to the open state.

[0028] In a preferred embodiment of the present invention, a conversion joint is provided at the second end of the valve body, and a fixed sleeve is sleeved on the valve body and located between the conversion joint and the packer. In the axial direction of the valve body, the packer is located between the fixed sleeve and the piston.

[0029] The present invention provides a drilling string, which includes a main body and the aforementioned circulation valve. The circulation valve is connected to the main body and is lowered into the well along with the main body.

[0030] In a preferred embodiment of the invention, the circulation valve is located below the leaking layer and above the producing layer in the well, and the packer in the circulation valve can separate the annulus in the well.

[0031] In a preferred embodiment of the present invention, one end of the tubing body is located at the wellhead, and the other end of the tubing body is provided with a drill bit and is located within the producing formation.

[0032] This invention provides a drilling circulation pressure control method, which includes the following steps:

[0033] Step S1: Check if any abnormal conditions have occurred inside the well;

[0034] Step S2: If the aforementioned abnormal condition exists, perform wellhead pressure control.

[0035] Step S3: If the abnormal situation still exists, the annulus below the leakage layer is set by the packer in the circulation valve, blocking the first channel in the circulation valve and opening the second channel in the circulation valve.

[0036] Step S4: Drilling fluid is injected into the circulation valve, and the injected drilling fluid enters the annulus above the packer through the second channel, and the drilling fluid that has been gas-invaded or liquid-invaded in the annulus above the packer is displaced from the wellhead to the surface.

[0037] In a preferred embodiment of the present invention, in step S1, the abnormal condition includes downhole gas measurement values ​​exceeding a preset range, gas intrusion in the oil, or oil overflow.

[0038] In a preferred embodiment of the present invention, step S2 includes:

[0039] Step S201: Control the wellhead pressure to the preset pressure range;

[0040] Step S202: If the wellhead pressure exceeds the preset pressure range, then stop drilling operations;

[0041] Step S203: Inject drilling fluid into the well and displace the drilling fluid that has been gas- or liquid-entrenched in the annulus from the wellhead to the surface.

[0042] In a preferred embodiment of the present invention, step S3 includes:

[0043] Step S301: A valve ball is inserted into the valve body of the circulation valve from the wellhead, and the valve ball is seated on the valve seat to block the first channel;

[0044] Step S302: Inject drilling fluid into the circulation valve from the wellhead;

[0045] Step S303: Under the pressure of the drilling fluid, the shear pin located between the sliding sleeve and the valve body in the circulation valve is sheared. The sliding sleeve slides in the valve body and compresses the spring. The first through hole on the sliding sleeve is connected to the second through hole on the valve body. The sliding sleeve pushes the piston in the circulation valve to move and squeezes the packer to expand. The packer sets the annulus. The piston is offset from the third through hole on the valve body so that the second channel is open.

[0046] In a preferred embodiment of the present invention, in step S4, the drilling fluid injected into the circulation valve is sequentially circulated into the annulus above the packer through the first end of the valve body, the first channel above the valve element, and the second channel, so as to displace the drilling fluid that has been gas-invaded or liquid-invaded in the annulus above the packer from the wellhead to the surface.

[0047] In a preferred embodiment of the present invention, after step S4, the method further includes:

[0048] Step S5: If the abnormal condition is eliminated, increase the amount of drilling fluid injected into the circulation valve, squeeze the valve ball to deform it and make it pass through the valve seat and fall into the ball rail below, so that the first channel is restored to the conductive state.

[0049] Step S6: Stop injecting drilling fluid into the circulation valve. Under the action of the spring force, the sliding sleeve and the piston return to their original positions, so that the second channel returns to the blocked state. At the same time, the packer returns to its original shape to cancel the setting of the annulus.

[0050] Step S7: Continue to inject drilling fluid into the circulation valve and enter the annulus from the drill bit, so as to displace the gas or liquid intrusion material in the annulus located below the packer from the wellhead to the surface;

[0051] Step S8: Continuously inject drilling fluid into the circulation valve to achieve circulation throughout the well section until the density of the drilling fluid circulating to the wellhead reaches a preset safety value;

[0052] Step S9: Continue drilling operations;

[0053] Step S10: If an abnormal situation occurs again in the detection well, repeat steps S2 to S9.

[0054] As described above, the features and advantages of the circulation valve, drilling string, and drilling circulation pressure control method of the present invention are as follows: A first channel connecting the first and second ends of the circulation valve is provided in the valve body. A valve component is provided in the first channel. A packer and a piston that can slide and squeeze the packer are sleeved on the valve body. A second channel is provided on the valve body above the packer. During normal tunneling operations, the valve component is in the conducting state, the first channel is open, and the piston blocks the second channel. When an abnormal condition is detected in the well, the valve component can be controlled to disconnect. The valve component blocks the first channel, and the pressure in the valve body and above the valve component pushes the piston to the position where the second channel is open. This allows the external space of the valve body above the packer to be connected to the first end of the valve body through the second channel and the first channel above the valve component. This allows the drilling fluid that has been invaded by gas or liquid in the annulus above the packer to be circulated and discharged, ensuring the balance of pressure in the well. This reduces the risk of wellhead control, thereby reducing the overall risk of well control, shortening the well control time, ensuring well control safety, and avoiding well control failure accidents. Attached Figure Description

[0055] The accompanying drawings are intended only to illustrate and explain the present invention and do not limit the scope of the invention.

[0056] in:

[0057] Figure 1 : This is a schematic diagram of the structure of the circulation valve in an embodiment of the present invention.

[0058] Figure 2 : This is a schematic diagram of the drilling string structure in an embodiment of the present invention.

[0059] Figure 3 This is one of the schematic diagrams for the simulation test of the present invention.

[0060] Figure 4 This is the second schematic diagram of the simulation test principle of the present invention.

[0061] The reference numerals in the accompanying drawings of this invention are:

[0062] 1. Valve body; 101. Second through hole;

[0063] 102. Flow channel; 103. Third through hole;

[0064] 104. First end; 105. Second end;

[0065] 106. First channel; 107. Second protrusion;

[0066] 2. Packer; 3. Sliding sleeve;

[0067] 301. First through hole; 302. First boss;

[0068] 4. Spring; 5. Receiving cavity;

[0069] 6. Valves; 601. Valve seat;

[0070] 7. Shear pin; 8. Piston;

[0071] 9. Ball hoop; 10. Adapter connector;

[0072] 11. Limiting ring; 12. Fixing sleeve;

[0073] 100. Circulation valve; 200. Tubing column body;

[0074] 300, drill bit; 400, annulus;

[0075] 500, Leaking layer; 600, Wellhead;

[0076] 700. Production layer; 800. First pipe body;

[0077] 900, Second tube body; 1000, Sealing element;

[0078] 1100, gap space; 1200, air injection pump. Detailed Implementation

[0079] To provide a clearer understanding of the technical features, objectives, and effects of the present invention, specific embodiments of the present invention will now be described with reference to the accompanying drawings.

[0080] The terms "upper," "lower," "top," and "bottom," etc., used in the specification of this invention have directional indications and are used in conjunction with it. Figure 1 The positional relationships of the top, bottom, and upper part of the text are used as a reference, and will be explained here.

[0081] Implementation Method 1

[0082] like Figure 1As shown, the present invention provides a circulation valve, which includes a valve body 1. The valve body 1 is a vertically arranged cylindrical structure with openings at both ends. The valve body 1 has at least a first end 104 at its top and a second end 105 at its bottom. A first channel 106 is provided inside the valve body 1, connecting the first end 104 and the second end 105. A valve element 6 is provided inside the first channel 106. A compressible and expandable packer 2 is sleeved on the valve body 1. A piston 8 is sleeved on the valve body 1, which can slide and compress the packer 2. The piston 8 is located at the sealing... Above the packer 2, a second channel is provided on the valve body 1 located above the packer 2; when the valve 6 is in the conducting state, the first channel 106 is conducting, and the piston 8 blocks the second channel; when the valve 6 is in the disengaged state, the valve 6 blocks the first channel 106, and the pressure inside the valve body 1 and above the valve 6 pushes the piston 8 to slide to the position where the second channel is conducting, so that the external space of the valve body 1 located above the packer 2 (i.e., the annulus 400) is connected to the first end 104 of the valve body 1 through the second channel and the first channel 106 located above the valve 6.

[0083] This invention provides a first channel 106 within a valve body 1, connecting its first end 104 and second end 105. A valve component 6 is installed within the first channel 106. A packer 2 and a piston 8, capable of sliding and compressing the packer 2, are fitted onto the valve body 1. A second channel is located on the valve body 1 above the packer 2. During normal tunneling operations, the valve component 6 is in a conductive state, the first channel 106 is open, and the piston 8 blocks the second channel. When an abnormal condition is detected inside the well, the valve component 6 can be controlled to disconnect, blocking the first channel 106, and the valve body... The pressure inside and above the valve 6 pushes the piston 8 to slide to the second channel open position, so that the external space of the valve body 1 above the packer 2 is connected to the first end 104 of the valve body 1 through the second channel and the first channel 106 above the valve 6. This allows the drilling fluid that has been invaded by gas or liquid in the annulus 400 above the packer 2 to be circulated and discharged, ensuring the balance of the well pressure. This reduces the risk of wellhead control, thereby reducing the overall risk of well control, shortening the well control time, ensuring well control safety, and avoiding well control failure accidents.

[0084] Furthermore, the packer 2 can be, but is no less than, a rubber sleeve.

[0085] In an optional embodiment of the present invention, such as Figure 1As shown, a sliding sleeve 3 is slidably disposed inside the valve body 1. The sliding sleeve 3 is a cylindrical structure with open ends. The valve component 6 is fixedly disposed inside the sliding sleeve 3. A first through hole 301 is provided on the side wall of the sliding sleeve 3. An annular flow channel 102 is formed inside the valve wall of the valve body 1. A second through hole 101 and a third through hole 103 are respectively provided on the valve body 1. The second through hole 101 connects the flow channel 102 to the interior of the valve body 1, and the third through hole 103 connects the flow channel 102 to the external space of the valve body 1 located above the packer 2. When the valve component 6 is in the conducting state, the first through hole 301 and the second through hole 101 are staggered. The piston 8 is blocked at the third through hole 103, the first channel 106 is open and the second channel is blocked; when the valve 6 is in the open state, pressure is applied to the valve body 1 from the first end 104 and pushes the sliding sleeve 3 to slide downward, so that the first through hole 301 moves to the position of communicating with the second through hole 101. The pressure enters the flow channel 102 from the first through hole 301 and the second through hole 101 and pushes the piston 8 to slide downward to the position where the third through hole 103 is connected with the flow channel 102. The third through hole 103, the flow channel 102, the second through hole 101 and the first through hole 301 are connected, thereby forming the second channel.

[0086] Specifically, such as Figure 1 As shown, a first annular protrusion 302 is provided on the outer wall of the sliding sleeve 3 along its circumference, and a second annular protrusion 107 is provided on the inner wall of the valve body 1 along its circumference. The second protrusion 107 is located below the first protrusion 302. The outer wall of the sliding sleeve 3 located above the first protrusion 302 is slidably sealed to the inner wall of the valve body 1, thereby forming an annular accommodating cavity 5 between the outer wall of the sliding sleeve 3, the inner wall of the valve body 1, the first protrusion 302, and the second protrusion 107. A spring 4 is provided in the accommodating cavity 5, and the two ends of the spring 4 abut against the first protrusion 302 and the second protrusion 107, respectively. When the valve 6 is in the open state, the sliding sleeve 3 moves downward to compress the accommodating cavity 5, the space of the accommodating cavity 5 decreases, and the spring 4 is in a compressed state. When the valve 6 returns to the open state, under the action of the spring force of the spring 4, the sliding sleeve 3 can be pushed upward and returned to its original position.

[0087] In actual use, by adjusting the maximum compression of spring 4 and controlling the wellhead pressure, the sliding sleeve 3 can be moved to the preset position when spring 4 reaches its maximum compression or by continuously adjusting the wellhead pressure, thereby ensuring that the first through hole 301 and the second through hole 101 can be stably connected.

[0088] Furthermore, such as Figure 1 As shown, a limiting ring 11 is fixedly installed inside the valve body 1 and near the first end 104. The sliding sleeve 3 can abut against the limiting ring 11. The limiting ring 11 can limit the movement of the sliding sleeve 3 towards the first end 104.

[0089] Furthermore, such as Figure 1 As shown, the distance between the first through hole 301 and the first end 104 is less than the distance between the valve 6 and the first end 104. Therefore, when the first through hole 301 and the second through hole 101 are connected, the valve 6 only blocks the first channel 106, and the second through hole is in a conductive state.

[0090] Furthermore, such as Figure 1 As shown, a shear pin 7 is connected between the sliding sleeve 3 and the valve body 1. When the valve 6 is in the open state, pressure is applied to the valve body 1 through the wellhead 600. As the pressure increases, the shear pin 7 is sheared, and the sliding sleeve 3 can slide inside the valve body 1.

[0091] In an optional embodiment of the present invention, such as Figure 1 As shown, piston 8 has a ring-shaped structure and can be slidably sleeved on valve body 1. The lower part of piston 8 abuts against the top of packer 2, and the upper part of piston 8 extends into the flow channel 102 from below. Piston 8 is slidably sealed to the inner wall of flow channel 102.

[0092] Furthermore, such as Figure 1 As shown, the third through hole 103 is connected to the flow channel 102 near the packer 2, and the second through hole 101 is connected to the flow channel 102 away from the packer 2. That is, the third through hole 103 and the second through hole 101 are axially opposite each other at both ends of the flow channel 102. The drilling fluid entering the flow channel 102 through the second through hole 101 needs to pass through the entire flow channel 102 before being output to the annulus 400 through the third through hole 103, thus providing a pressure stabilizing effect. When the valve 6 is in the conducting state, the upper part of the piston 8 blocks the third through hole 103, thus blocking the second channel.

[0093] In an optional embodiment of the present invention, such as Figure 1 As shown, valve 6 can be, but is not limited to, a ball valve. Of course, other valves (such as electrically controlled valves) can also be used, allowing for remote control of the valve's on / off state.

[0094] Specifically, such as Figure 1 As shown, the ball valve includes a valve seat 601 and a valve ball (not shown). The valve seat 601 has an annular structure and is fixedly installed in the sliding sleeve 3. When it is necessary to disconnect the valve component 6, the valve ball can be inserted through the wellhead 600. The valve ball is inserted into the sliding sleeve 3 through the first end 104 of the valve body 1 and is seated on the valve seat 601 to block the first channel 106.

[0095] Furthermore, such as Figure 1As described above, a ball guard 9 is fixedly installed inside the valve body 1 near the second end 105. When the valve 6 is in the open state, the pressure applied to the valve body 1 from the first end 104 can be increased to deform the valve ball. The deformed valve ball passes through the valve seat 601 and falls into the ball guard 9 below, thus restoring the valve 6 to the conducting state. The ball guard 9 has a mesh structure (with holes), and its installation will not affect the normal conduction of the first channel 106.

[0096] In an optional embodiment of the present invention, such as Figure 1 As shown, a conversion joint 10 is provided at the second end 105 of the valve body 1. A fixing sleeve 12 is fitted on the valve body 1 between the conversion joint 10 and the packer 2. In the axial direction of the valve body 1, the packer 2 is located between the fixing sleeve 12 and the piston 8. The fixing sleeve 12 limits the packer 2, so that the packer 2 will expand and deform when squeezed, thereby achieving the purpose of setting the annulus 400. The conversion joint 10 can use existing structural components, and its purpose is to be able to connect to the lower tubing.

[0097] Implementation Method 2

[0098] like Figure 2 As shown, the present invention provides a drilling string, which includes a main body 200 and the aforementioned circulation valve 100. The circulation valve 100 is connected to the main body 200 and is lowered into the well along with the main body 200.

[0099] Furthermore, such as Figure 2 As shown, the circulation valve 100 is located below the leaking layer 500 and above the producing layer 700 in the well. The packer 2 in the circulation valve 100 can separate the annulus 400 in the well. When the packer 2 is set in the annulus 400, the drilling fluid that has experienced gas or liquid intrusion in the annulus 400 above the packer 2 can be circulated and displaced to the surface until the density of the drilling fluid reaches a stable level and there is no longer any gas or liquid intrusion, indicating that the leaking layer 500 is no longer leaking. Then, the packer 2 is set, and the remaining drilling fluid that has experienced gas or liquid intrusion in the annulus 400 below the packer 2 is circulated and displaced to the surface, thereby shortening the well control time and ensuring well control safety.

[0100] Furthermore, such as Figure 2 As shown, one end of the tubing string body 200 is located at the wellhead 600, and the other end of the tubing string body 200 is equipped with a drill bit 300 located within the producing formation 700. The distance between the circulation valve 100 and the drill bit 300 can be, but is not limited to, 300m to 500m.

[0101] The features and advantages of the drilling string of this invention are:

[0102] 1. In the event of gas or liquid intrusion in the drilling string, the process is carried out in stages. First, the drilling fluid above packer 2 that has been intruded by gas or liquid is circulated and drained, replacing the intruded drilling fluid to the surface in a short time to solve the leakage problem in the leakage layer 500. Then, the remaining drilling fluid below packer 2 that has been intruded by gas or liquid is replaced to achieve the effect of stabilizing the drilling fluid density, effectively shortening the well control time and ensuring well control safety.

[0103] Second, in the event of gas or liquid intrusion, this drilling string can ensure that the pressure inside the well is quickly restored to balance, reducing the risk of wellhead control, thereby reducing the overall risk of well control, ensuring well control safety, and avoiding accidents caused by loss of well control.

[0104] Implementation Method 3

[0105] This invention provides a drilling circulation pressure control method, which includes the following steps:

[0106] Step S1: During drilling operations, monitor in real time whether any abnormal conditions occur in the well.

[0107] Furthermore, in step S1, abnormal conditions include downhole gas measurement values ​​exceeding the preset range, gas intrusion in the oil, oil overflow, or well kick.

[0108] Step S2: If an abnormal situation exists, perform wellhead pressure control.

[0109] Furthermore, step S2 includes:

[0110] Step S201: Control the wellhead pressure to a preset pressure range, such as 0.3MPa to 4MPa;

[0111] Step S202: If the wellhead pressure exceeds the preset pressure range, stop drilling operations; if the wellhead pressure exceeds 4MPa, drilling operations need to be stopped and the drill bit 300 needs to be raised to a distance of 2m to 3m from the bottom of the well.

[0112] Step S203: Inject drilling fluid into the well and replace the drilling fluid that has been invaded by gas or liquid in the annulus 400 with the wellhead 600 to the surface. Through gradual circulation and increased pressure circulation, replace the drilling fluid that has been invaded by gas or liquid in the entire well section with the surface.

[0113] Step S3: If the abnormal situation still exists, the annulus 400 below the leakage layer 500 is set by the packer 2 in the circulation valve 100, blocking the first channel 106 in the circulation valve 100 and opening the second channel in the circulation valve 100.

[0114] Furthermore, step S3 includes:

[0115] Step S301: Stop injecting drilling fluid, and insert a valve ball into the valve body 1 of the circulation valve 100 from the wellhead 600. The valve ball is seated on the valve seat 601 to block the first channel 106.

[0116] Step S302: Inject drilling fluid into circulation valve 100 again from wellhead 600, and adjust pump pressure to 2MPa to 3MPa;

[0117] Step S303: Under the pressure of the drilling fluid, the shear pin 7 located between the sliding sleeve 3 and the valve body 1 in the circulation valve 100 is sheared. The sliding sleeve 3 slides in the valve body 1 and compresses the spring 4. The sliding sleeve 3 slides until the first through hole 301 on it is connected to the second through hole 101 on the valve body 1. The sliding sleeve 3 pushes the piston 8 in the circulation valve 100 to move and squeeze the packer 2 to expand. The packer 2 sets the annulus 400. The piston 8 is offset from the third through hole 103 on the valve body 1 so that the second channel is open.

[0118] Step S4: After the first channel 106 is blocked and the second channel is opened, drilling fluid is injected into the circulation valve 100, and the injected drilling fluid enters the annulus 400 above the packer 2 through the second channel, and the drilling fluid that has been gas-invaded or liquid-invaded in the annulus 400 above the packer 2 is replaced by the wellhead 600 and brought to the surface.

[0119] Specifically, in step S4, the drilling fluid injected into the circulation valve 100 is circulated into the annulus 400 above the packer 2 through the first end 104 of the valve body 1, the first channel 106 above the valve member 6 and the second channel, so as to circulate and replace the drilling fluid that has been invaded by gas or liquid in the annulus 400 above the packer 2 to the surface through the wellhead 600.

[0120] In an optional embodiment of the present invention, after step S4, the method further includes:

[0121] Step S5: If the abnormal condition is eliminated (i.e., the downhole gas measurement value is detected to return to the preset range, and there is no gas intrusion, liquid intrusion or oil overflow in the oil), the drilling fluid injection into the circulation valve 100 is increased, the valve ball is squeezed and deformed, so that the deformed valve ball can pass through the valve seat 601 and fall into the ball rail 9 below, so that the first channel 106 is restored to the conductive state.

[0122] Step S6: Stop injecting drilling fluid into the circulation valve 100. Under the action of the spring force of the spring 4, the sliding sleeve 3 and piston 8 move upward to return to their original positions so that the second channel is restored to the blocked state. At the same time, the packer 2 returns to its original shape to cancel the setting of the annulus 400.

[0123] Step S7: Continue to inject drilling fluid into the circulation valve 100 and enter the annulus 400 from the drill bit 300, so that the gas or liquid intrusion material in the annulus 400 located below the packer 2 is replaced by the wellhead 600 and brought to the surface.

[0124] Step S8: Continuously inject drilling fluid into the circulation valve 100 to achieve circulation throughout the well section until the density of the drilling fluid circulated to the wellhead 600 reaches the preset safety value.

[0125] Step S9: After confirming that the drilling fluid density has reached a safe range, drilling operations can continue;

[0126] Step S10: If an abnormal situation occurs again in the detection well, repeat steps S2 to S9.

[0127] The features and advantages of the drilling circulation pressure control method of the present invention are as follows:

[0128] This drilling circulation pressure control method does not affect normal drilling operations. In the event of abnormal conditions such as gas intrusion or liquid intrusion, it can immediately block the flow of fluid rushing into the bottom of the well from the source (i.e., the leakage layer 500). At the same time, it can circulate and replace the drilling fluid that has been intruded by gas or liquid to the surface in a short time, shortening the well control time, reducing the actual pressure value of the wellhead control equipment, reducing the well control risk at the wellhead, and winning valuable time for surface well control.

[0129] Real-time method four

[0130] like Figure 3 , Figure 4 As shown, the present invention also provides a test apparatus to demonstrate the reliability of the circulation valve and drilling string during operation.

[0131] like Figure 3 , Figure 4As shown, the experimental apparatus includes a first tube 800 and a second tube 900. The first tube 800 is arranged vertically, with an open top and a sealed bottom. The second tube 900 is also arranged vertically, with open tops and bottoms. The second tube 900 is placed inside the first tube 800. The first tube 800 simulates a wellbore, and the second tube 900 simulates a drilling string. An annular gap space 1 is left between the first tube 800 and the second tube 900. Unit 100 is used to simulate the annulus 400 within the well. The top opening of the second pipe body 900 extends above the top opening of the first pipe body 800. A circulation valve 100 and a packer element 1000 are installed in the middle of the second pipe body 900, with the packer element 1000 located below the circulation valve 100. An injection pump 1200 is connected to the bottom of the first pipe body 800, which injects gas into the first pipe body 800 to simulate a gas intrusion environment. During the test, liquid (such as clean water) is injected into the first pipe body 800 through the top opening of the second pipe body 900 to simulate drilling fluid injection, creating a circulation between the first pipe body 800 and the second pipe body 900.

[0132] The structure and working principle of the circulation valve 100 used in this test device can be the same as or similar to the structure and working principle of the circulation valve 100 actually installed on the drilling string, but the volume of the circulation valve 100 used in the test device is much smaller than that of the circulation valve 100 actually installed on the drilling string.

[0133] Furthermore, the first pipe body 800 may be made of, but is not limited to, an acrylic tube, and the second pipe body 900 may be made of, but is not limited to, a steel tube. The second pipe body 900 may be configured as two sections of steel tubes, with the circulation valve 100 and the sealing element 1000 positioned between the two sections. Each section of steel tube may have a length of, but is not limited to, 1500 mm, an outer diameter of, but is not limited to, 60 mm, and an inner diameter of, but is not limited to, 40 mm; the acrylic tube may have an outer diameter of, but is not limited to, 200 mm, and a thickness of, but is not limited to, 10 mm.

[0134] Furthermore, the packer element 1000 may be, but is not limited to, a compression packer.

[0135] like Figure 3 , Figure 4As shown, the experimental procedure is as follows: The second tube 900 is inserted into the first tube 800, with a 200mm to 300mm gap between the bottom of the second tube 900 and the bottom of the first tube 800. Clean water is injected into the second tube 900 through its top opening (this water can be pumped using an injection pump). Air is injected into the gap space 1100 between the first tube 800 and the first tube 900 using an air pump 1200 at the bottom of the first tube 800. Air bubbles can be observed returning with the clean water in the gap space 1100 at the top of the first tube 800, thus simulating air intrusion. Pressure is applied to the top opening of the second tube 900 to achieve a seal. The element 1000 is compressed and deformed, separating the upper and lower parts of the gap space 1100. This prevents air injected from the bottom of the first tube 800 from flowing into the gap space 1100 above the packer element 1000. At this time, the first channel 106 in the circulation valve 100 is blocked, while the second channel is open. The clean water injected into the second tube 900 flows directly out through the second channel into the gap space 1100 above the packer element 1000 and returns through the top opening of the first tube 800. During the return of the clean water, air bubbles are carried out, thus simulating the actual drilling operation where drilling fluid above the packer 2 that has experienced gas or liquid intrusion is circulated and discharged. Through simulation experiments, it can be seen that the circulation valve, drilling string, and drilling circulation pressure control method of this invention can all achieve the desired technical effects.

[0136] The above description is merely an illustrative embodiment of the present invention and is not intended to limit the scope of the invention. Any equivalent changes and modifications made by those skilled in the art without departing from the concept and principles of the present invention should fall within the scope of protection of the present invention.

Claims

1. A circulation valve, characterized in that, The circulation valve includes a valve body, which has at least a first end and a second end. A first channel is provided inside the valve body to connect the first end and the second end. A valve component is provided in the first channel. A compressible and expandable packer is fitted on the valve body. A piston that can slide and squeeze the packer is fitted on the valve body. A second channel is provided on the valve body located above the packer. When the valve is in the conducting state, the first channel is open, and the piston blocks the second channel; When the valve is in the open state, the valve blocks the first channel. The pressure inside the valve body and above the valve pushes the piston to slide to the second channel open position, so that the external space of the valve body above the packer is connected to the first end of the valve body through the second channel and the first channel above the valve. A sliding sleeve is slidably disposed within the valve body. Both the valve body and the sliding sleeve are cylindrical structures with openings at both ends. The valve component is disposed within the sliding sleeve. A first through hole is provided on the sliding sleeve. An annular flow channel is formed within the valve wall of the valve body. A second through hole and a third through hole are respectively provided on the valve body. The second through hole connects the flow channel to the interior of the valve body, and the third through hole connects the flow channel to the external space of the valve body located above the packer. A first boss and a second boss are respectively provided on the outer wall of the sliding sleeve and the inner wall of the valve body. The outer wall of the sliding sleeve, the inner wall of the valve body, the first boss, and the second boss together form an annular accommodating cavity. A spring is disposed within the accommodating cavity. When the valve component is in the open state, the sliding sleeve moves and the space of the accommodating cavity decreases, and the spring is in a compressed state. When the valve component returns to the open state, the spring pushes the sliding sleeve back to its original position. In the valve's conducting state, the first through hole and the second through hole are offset, and the piston is blocked at the third through hole; When the valve is in the open state, pressure is applied to the valve body from the first end and pushes the sliding sleeve to slide, so that the first through hole moves to a position communicating with the second through hole. The pressure enters the flow channel from the first through hole and the second through hole and pushes the piston to slide to a position where the third through hole communicates with the flow channel. The third through hole, the flow channel, the second through hole and the first through hole cooperate to form the second channel.

2. The circulation valve as described in claim 1, characterized in that, A limiting ring is provided inside the valve body and near the first end. The sliding sleeve can abut against the limiting ring to limit the movement of the sliding sleeve toward the first end.

3. The circulation valve as described in claim 1, characterized in that, The distance between the first through hole and the first end is less than the distance between the valve and the first end.

4. The circulation valve as described in claim 1, characterized in that, A shear pin connects the sliding sleeve to the valve body.

5. The circulation valve as described in claim 1, characterized in that, The piston has an annular structure, with its lower part abutting against the top of the packer, its upper part extending into the flow channel, and the piston slidingly and sealingly connected to the inner wall of the flow channel.

6. The circulation valve as described in claim 5, characterized in that, The third through hole is connected to the flow channel and is located near the packer. The second through hole is connected to the flow channel and is located away from the packer. When the valve is in the open state, the upper part of the piston blocks the third through hole.

7. The circulation valve as described in any one of claims 1 to 6, characterized in that, The valve is a ball valve.

8. The circulation valve as described in claim 7, characterized in that, The ball valve includes a valve seat and a valve ball. The valve seat has an annular structure and is disposed inside the sliding sleeve. The valve ball is inserted into the sliding sleeve through the first end and sits on the valve seat to block the first channel.

9. The circulation valve as described in claim 8, characterized in that, A ball guard is provided inside the valve body and near the second end. When the valve is in the open state, the pressure applied to the valve body from the first end is increased to squeeze the valve ball to deform, so that it passes through the valve seat and falls into the ball guard, and the valve is restored to the open state.

10. The circulation valve as claimed in claim 1, characterized in that, A conversion joint is provided at the second end of the valve body, and a fixed sleeve is fitted on the valve body between the conversion joint and the packer. In the axial direction of the valve body, the packer is located between the fixed sleeve and the piston.

11. A drilling string, characterized in that, The drilling string includes a string body and a circulation valve as described in any one of claims 1 to 10, wherein the circulation valve is connected to the string body and is lowered into the well along with the string body.

12. The drilling string as described in claim 11, characterized in that, The circulation valve is located below the leaking layer and above the producing layer in the well, and the packer in the circulation valve can separate the annulus in the well.

13. The drilling string as described in claim 12, characterized in that, One end of the tubing string is located at the wellhead, and the other end of the tubing string is equipped with a drill bit and is located within the producing formation.

14. A drilling circulation pressure control method, comprising using the circulation valve according to any one of claims 1 to 10, characterized in that, The drilling circulation pressure control method includes the following steps: Step S1: Check if any abnormal conditions have occurred inside the well; Step S2: If the aforementioned abnormal condition exists, perform wellhead pressure control. Step S3: If the abnormal situation still exists, the annulus below the leakage layer is set by the packer in the circulation valve, blocking the first channel in the circulation valve and opening the second channel in the circulation valve. Step S4: Drilling fluid is injected into the circulation valve, and the injected drilling fluid enters the annulus above the packer through the second channel, and the drilling fluid that has been gas-invaded or liquid-invaded in the annulus above the packer is displaced from the wellhead to the surface.

15. The drilling circulation pressure control method as described in claim 14, characterized in that, In step S1, the abnormal conditions include downhole gas measurement values ​​exceeding the preset range, gas intrusion in the oil, or oil overflow.

16. The drilling circulation pressure control method as described in claim 14 or 15, characterized in that, Step S2 includes: Step S201: Control the wellhead pressure to the preset pressure range; Step S202: If the wellhead pressure exceeds the preset pressure range, then stop drilling operations; Step S203: Inject drilling fluid into the well and displace the drilling fluid that has been gas- or liquid-entrenched in the annulus from the wellhead to the surface.

17. The drilling circulation pressure control method as described in claim 14, characterized in that, Step S3 includes: Step S301: A valve ball is inserted into the valve body of the circulation valve from the wellhead, and the valve ball is seated on the valve seat to block the first channel; Step S302: Inject drilling fluid into the circulation valve from the wellhead; Step S303: Under the pressure of the drilling fluid, the shear pin located between the sliding sleeve and the valve body in the circulation valve is sheared. The sliding sleeve slides in the valve body and compresses the spring. The first through hole on the sliding sleeve is connected to the second through hole on the valve body. The sliding sleeve pushes the piston in the circulation valve to move and squeezes the packer to expand. The packer sets the annulus. The piston is offset from the third through hole on the valve body so that the second channel is open.

18. The drilling circulation pressure control method as described in claim 17, characterized in that, In step S4, the drilling fluid injected into the circulation valve circulates sequentially through the first end of the valve body, the first channel above the valve element, and the second channel into the annulus above the packer, so as to displace the drilling fluid that has been gas- or liquid-invaded in the annulus above the packer from the wellhead to the surface.

19. The drilling circulation pressure control method as described in claim 18, characterized in that, After step S4, the method further includes: Step S5: If the abnormal condition is eliminated, increase the amount of drilling fluid injected into the circulation valve, squeeze the valve ball to deform it and make it pass through the valve seat and fall into the ball rail below, so that the first channel is restored to the conductive state. Step S6: Stop injecting drilling fluid into the circulation valve. Under the action of the spring force, the sliding sleeve and the piston return to their original positions, so that the second channel returns to the blocked state. At the same time, the packer returns to its original shape to cancel the setting of the annulus. Step S7: Continue to inject drilling fluid into the circulation valve and enter the annulus from the drill bit to displace the gas or liquid intrusion material in the annulus located below the packer from the wellhead to the surface; Step S8: Continuously inject drilling fluid into the circulation valve to achieve circulation throughout the well section until the density of the drilling fluid circulating to the wellhead reaches a preset safety value; Step S9: Continue drilling operations; Step S10: If an abnormal situation occurs again in the detection well, repeat steps S2 to S9.

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