• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
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    • 专利摘要:
    "system and method for drilling an underwater well". The present invention relates to an underwater mud pump that can be used to return heavy drilling fluid to the surface. In order to provide a less stringent requirement for such a pump and to better manage downhole recession in the event of a gas kick or well control event, the gas must be separated from the drilling fluid before the drilling fluid. enter the subsea mud pump and the pressure inside the separation chamber. The suction of the mud pump shall be controlled and maintained at or below ambient seawater pressure. This can be achieved within the undersea bop cavities by a system arrangement and methods explained. This function can be used with or without a drill lift by connecting the underwater bop to a drill unit above the body of water.
    公开号:BR112012011127B1
    申请号:R112012011127
    申请日:2010-11-10
    公开日:2019-09-03
    发明作者:Fossli Borre；Sangesland Sigbjorn
    申请人:Enhanced Drilling As；Ocean Riser Systems As；
    IPC主号:
    专利说明:

    Descriptive Report on the Patent of Invention SYSTEM AND METHOD FOR THE WELL CONTROL DURING DRILLING.
    Technical Field [001] The present invention relates to the field of oil and gas exploration, more specifically to systems and methods for well control, especially for well pressure control in wells with hydrocarbon fluids, as defined in the claims attached.
    Background art [002] The drilling of oil and gas in deep water or drilling through exhausted reservoirs is a challenge due to the narrow margin between the pore pressure and the fracture pressure. The narrow margin implies frequent wrapping installation, and restricts the circulation of mud due to the pressure drop in the ring between the borehole and the drill string or in other words the increase in pressure applied or observed in the well due to the activity of drilling such as circulation of drilling fluid flowing down the drill pipe to the well hole orifice ring. Reducing this effect by reducing the flow rate circulation will again reduce the drilling speed and cause problems with the transport of drilling cutouts in the well.
    [003] Normally, in conventional floating drilling with a marine drilling lift installed, two independent pressure guards between a formation possibly containing hydrocarbons and the surroundings are necessary. In conventional subsea drilling operations, the primary (primary) pressure protection is typically the hydrostatic pressure created by the drilling fluid column (mud) in the well and the drilling lift to installation
    Petition 870190031009, dated 04/01/2019, p. 4/33
    2/20 of drilling. The second protection comprises the Explosion Prevention Element (BOP) connected to the underwater well in the seabed. [004] A conventional drilling system is illustrated in figure 1a.
    [005] If a formation is being drilled where the hydrostatic pressure of the drilling fluid is not sufficient to balance the formation pore pressure, an inflow of formation fluids that may contain natural gas can enter the well bore. Primary protection is no longer efficient in controlling or containing formation pore pressure. In order to contain this situation, the submarine Explosion Prevention Element (BOP) must be closed. In a conventional drilling system, the oil and gas industry has developed certain standard operational well control procedures to contain the situation for such an event. These are well-established and well-known procedures and will be described here only in broad general terms.
    [006] Figure 1a illustrates a conventional subsea drilling system. If the pressure in well 1 due to the hydrostatic pressure of the drilling fluid is less than the pore pressure in the formation being drilled, an inlet flow into the well hole must occur. Since the density of the inlet flow is lower (in most cases) than the density of the drilling fluid and now occupies a certain height in the well bore, the hydrostatic pressure in the depth of the inlet flow will continue to decrease if the well cannot be closed when using the BOP. By shutting down the well by closing one of the various elements 15a, b, c, d, 16 in the submarine BOP stack 3 and trapping a pressure in well 14, the inlet flow from the formation can be interrupted (see figure 1 b ). The containment procedures for this situation and how the inlet flow is circulated out of the well by pumping the drilling fluid to
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    3/20 down through drill string 8 and out of drill bit 10 and up through well ring 14 are well established. The valves on the choke line 25 are opened on the submarine BOP for the high pressure choke line (HP) 24 and the lower bore pressure controlled by the adjustable choke 22 above the choke line on the drilling vessel above the waterbody . Downstream of the adjustable throttle valve, the well stream is directed to a sludge and gas separator 42. This is a critical operation, particularly in areas of deep water as there are very narrow margins at which high the surface pressure to amount of the surface choke may be before the forming intensity is exceeded in the open bore section.
    [007] Floating drilling operations are often more critical compared to drilling from platforms supported from below, as the vessel is moving due to wind, waves and sea currents. This means that the floating drilling vessel and the lift can be disconnected from the underwater BOP and well hole below.
    [008] If a fluid heavier than seawater drilling fluid is being used, this will result in a hydrostatic pressure drop in the well. Generally, a lift margin is required. An elevator margin is defined as the required density (specific gravity) of the drilling fluid in the well to balance any formation pore pressure after the drilling elevator is disconnected from the top of the submarine BOP near the seabed in addition to the pressure of sea water at the disconnection point
    20. When disconnecting the submarine BOP marine drilling lift, the hydrostatic head of the drilling fluid in the well and the hydrostatic seawater head must be equal to or greater than
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    4/20 than the formation pore pressure (FPP) to achieve a lift margin. The lift margin is difficult to reach, particularly in deep water. The reason for this is that there can be a substantial pressure difference between the pressure inside the drilling lift due to heavy drilling fluids and the seawater pressure outside the lift disconnection point. To compensate for the pressure reduction in the open pit below the pore pressure when the elevator is disconnected, drilling with a very high mud weight in the well and elevator borehole would be necessary. Therefore, when drilling with this high mud weight all the way to the spill point on the frame 5, usually between 10 and 50 meters above sea level, the downhole pressure would be greater than the resistance of the training is able to withstand. In this way, the resistance of the formation would be exceeded and the losses of mud would occur. It would no longer be possible to circulate and transport the drilling cutouts from the well and the drilling operation would have to be stopped.
    [009] Perforation Without Elevator, Double Gradient Perforation and drilling with a Low Elevator Return System (LRRS), were introduced to reduce some of the problems mentioned above. The LRRS is described, for example, in WO 2003/023181, WO 2004/085788 and WO 2009/123476, which all belong to the present applicant.
    [0010] In double gradient drilling (DG) systems, a high density drilling fluid is used below a specified depth in the well, with a lighter fluid (for example, seawater or other lighter fluid) above from that point. When drilling with a lift, a double gradient effect can be achieved by diluting the contents of the drill lift with a gaseous fluid, for example, or another lighter liquid, U.S. 6,536,540 (from
    Petition 870190031009, dated 04/01/2019, p. 7/33
    5/20
    Boer). Another method may be to install a pump on the seabed or submarine and keep the elevator contents full or partially filled with seawater instead of mud while the borehole ring returns are pumped from the seabed up to the drilling installation on an external return path to the main drilling elevator. Thus, there are two liquids of different density in addition to atmospheric pressure creating the hydrostatic pressure in the underground formation. References are created to the prior art, U.S. 4,813,495 (Leach) and U.S. 6,415,877 (Fincher et al.).
    [0011] Another technology that can create an elevator margin is the unique mud gradient, LRRS belonging to the applicant. Here, a pump is placed somewhere between sea level and sea bed and connected to the drilling elevator. The level of drilling mud is reduced to a considerable depth below sea level. Due to the shorter hydrostatic head (height) of the drilling fluid acting in the formation of an open pit, the density of the drilling mud can be increased without exerting excessive pressure acting on the formation. If this heavy drilling mud is transported all the way back to the drilling frame, as may be the case in a conventional drilling operation, the hydrostatic pressure will exceed the formation resistances, and thus the mud losses will occur.
    [0012] In drilling without an elevator, there is simply no hydraulically installed elevator connecting the BOP installed on the seabed to the drilling frame via a marine drilling elevator. Normally, the top of the well hole (submarine BOP) is kept open to seawater pressure during drilling; thus, the hydrostatic well bore pressure is leveled with the seawater pressure acting on the well in the seabed, plus the hydrostatic pressure of the drilling fluid in the well below that point, also
    Petition 870190031009, dated 04/01/2019, p. 8/33
    6/20 described in U.S. 4,149,603 (Arnold).
    [0013] Several other concepts have been introduced and are in the public domain.
    [0014] Other systems have introduced a closure element on top of the submarine BOP that can isolate seawater pressure on the seabed preventing it from acting on the well ring (U.S. 6,415,877). Such a closure element can be a so-called Rotary Control Device (RCD) or a rotating BOP. These are somewhat different from an annular prevention element since it is possible to rotate the drill string while sealing pressure from below or from above (sea water). It is not recommended practice to rotate the drill string while a conventional annular BOP is closed during drilling due to excessive wear on the rubber element. If such a system is used in combination with an underwater mud lift pump on the seabed or in the middle of the sea, the suction pressure of the mud pump below the RCD in addition to the height of the drilling fluid and loss of dynamic pressure in the ring, directly control the pressure in the well.
    [0015] Common for all these drilling systems is that the drilling fluid returning from the well cannot be returned through this high pressure choke or kills the lines in a conventional manner due to limited formation resistance when the BOP is closed after an influx occurred. Due to the high mud weight needed or used, this mud can be displaced out of the borehole ring ahead of the lighter inlet flow, so the formation resistance cannot withstand being hydraulically in contact with the surface installation. when the well and conduit ring (disposal and / or strangulation lines) back to the surface are filled with heavy drilling fluid. This effect will restrict the use of previous systems or place severe stress and
    Petition 870190031009, dated 04/01/2019, p. 9/33
    7/20 equipment and process requirements in a well control event.
    [0016] In Double Gradient Drilling and Drill without Elevator, many types of Subsea Lifting Pumps (SLP) may not normally handle a significant amount of well gas, as the case may be in a well control event for a kick of gas. There are several reasons for this. In normal operations, these pumps must handle a significant amount of drilling cuttings and stones in addition to the fine solid particles of the weight materials used in the drilling mud. If a gas inlet flow is introduced into the well bore at a considerable depth and pressure, that gas will expand when circulated through the well bore to the seabed or ocean medium where the pump is located. If this fluid return path from the well needs to go directly into the pump, it will impose severe stress on the pump system.
    [0017] Second, the downhole pressure will be a direct function of the fluid head in the ring, the loss of dynamic pressure in the ring and the pump suction pressure. It will be extremely difficult to achieve a stable and controllable suction pressure at the pump when there will be pieces of high concentration of hydrocarbon gas flowing directly into the pump system. As a consequence of this, it will be a great advantage if the hydrocarbon gas and drilling fluid can be separated from each other under water, before the liquid drilling fluid and solids are diverted and pumped to the surface by the underwater pump. This was also envisioned by Gonzáles in U.S. 6,276,455.
    [0018] Third, as the subsea pump in previous systems is in direct communication with the ring, the lines of
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    8/20 return and the pump system must have the same high pressure rating as the BOP itself. This places severe demands on the pump system to handle internal pressures.
    Submarine Throttling Systems [0019] The prior art exists in an attempt to compensate for excessive pressure in the well by acting on the well when circulating a kick in a conventional manner through the small high pressure orifice choke line and a throttling choke. surface at the top of that line. US 4,046,191 (Neath) and US 4,210,208 (Shanks) introduce a surface-controlled undersea bottleneck where the flow from under a closed Submarine BOP has been directed into the main hole of the drilling lift through an undersea bottleneck .
    [0020] Neath envisioned a conventional drilling system where the elevator was filled with conventional heavy drilling fluid. If such a system is used in a situation where double gradient drilling technology has been used, the pressure downstream of the adjustable choke may become too high due to the high weight of mud used. Also, since the elevator was initially filled with drilling mud, the gas introduced at the base of the elevator at great depth of water can introduce additional problems since the elevator has limited internal pressure and disassembly ratings.
    Summary of the Invention [0021] In order to overcome the challenges with the prior art in conducting well control operations during non-elevator drilling and other double gradient drilling technology, a well controlled pressure control method will be explained.
    [0022] Several alternatives for the creation of a submarine separation system within a submarine BOP will be explained below.
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    9/20
    Reference numbers refer to the attached drawings as examples only.
    Submarine BOP Gas Separation System [0023] An elevator joint can be particularly designed to function as a separator where the separated gas is vented to the surface via the elevator and the liquid is pumped to the surface via an external return path from the drilling elevator (figures 2 and 3). The main difference here with the prior art is that the level of mud / liquid in the elevator is controlled and located at a considerable level below sea level. In this way, drilling fluids or liquids are prevented from being discharged from the top of the elevator if gas is being released into the base of the elevator.
    [0024] In another embodiment, a BOP extension joint (BOP-EJ) located between the lower and upper annular prevention element is designed so that with 2 different closed BOP elements a chamber or cavity will be formed where the gas can be separated of liquids by gravity and the separated gas vented through a conventional throttle line or a separate duct line, or alternatively via an elevator to the surface. The liquid is pumped to the surface by the underwater mud pump controlling the level of liquid in the cavity.
    [0025] Another alternative would be a separate unit for separation where the separated gas is vented through a conventional choke line and the liquid is pumped to the surface via a separate liquid line (not shown here).
    [0026] A representation of a new drilling system without an elevator is illustrated in figure 4. In this system an underwater mud pump 11 is installed on the seabed or some distance above and hydraulically connected to the well so that the drilling fluid
    Petition 870190031009, dated 04/01/2019, p. 12/33
    10/20 and the drilling cutouts are pumped to the drilling installation on a separate return flow path 12. The interface between the drilling fluid and seawater is then somewhere in the vicinity of the Submarine BOP.
    [0027] Extension Joint BOP X elevator joint for separating mud and gas.
    [0028] A conventional submarine BOP is normally equipped with two annular prevention elements in modern frames. The lower annular prevention element 16 in figure a is normally the uppermost closure element in the lower BOP stack 3 which consists of a series of plunger-like prevention elements stacked on top of each other 15 a, b, c, of said stack BOP 3 installed with a special connector to a High Pressure Wellhead (HP WH) 52 or a Horizontal Christmas Tree (HXT) (not shown here). The total height of the lower submarine BOP is around 7 to 10 meters. The height of the HP WH is approximately 1 meter. HP WH is normally installed in what is defined as a surface wrap that is normally above the sea bed for 2 to 3 meters. The upper annular prevention element 19 is normally installed in what is called the Lower Marine Elevator Package (LMRP). However, some frames may have both annular prevention elements above the BOP disconnection point of elevator 20, figure 1 b, on the LMRP. The interface between the lower BOP stack and the LMRP is typically designed as a remote hydraulic disconnect point between the lower marine lift package (elevator) and the lower submarine BOP. Thus, the distance between the lower annular prevention element on the BOP and the upper annular prevention element on the LMRP is usually approximately 1.5 to 2.5 meters. In order to create a greater distance between the 2 prevention elements
    Petition 870190031009, dated 04/01/2019, p. 13/33
    11/20 ring, an extension joint can be installed to create more space.
    [0029] If the sludge and gas can be separated in a BOP cavity and / or BOP Extension Joint, thus creating a gas phase at the top of the BOP, this would allow a surface choke to control the gas pressure if connected to the cavity between the two closing elements, hydraulically by flexible or fixed lines (without gas ventilation through the elevator).
    [0030] The BOP Extension Joint can then be used to separate fluid and mud when drilling with and without the elevator.
    [0031] If and when using the Low Lift Return System in another embodiment of this invention, the upper annular prevention element can be closed during a connection with the drill pipe to avoid adjusting the fluid level in the elevator where, in this case, the fluid level in the choke line is used to control and regulate the ring pressure to compensate for the effect of equivalent circulation density (ECD) (time saving). This is also explained in WO 2009/123476, which belongs to the applicant. The disadvantage of having the liquid separated from the gas near the seabed as opposed to the higher one in the elevator is the larger pump suction line needed in deep water and the higher differential pressure capacity of the subsea pump system.
    [0032] Another characteristic of this provision is the possibility of controlling the downhole pressure while drilling (lower open ring) and when circulating out of a well kick (closed lower ring), by controlling the level of mud of liquid in the strangulation line (fully open submarine strangulation) (figure 6). In this case, the upper annular can be replaced by a rotating BOP (RBOP or RCD) 19 where the pressure of the mud in the ring of well 1 is
    Petition 870190031009, dated 04/01/2019, p. 14/33
    12/20 regulated by the level of liquid sludge in the choke line 51 (figure 6). The pressure in the BOP and / or BOP extension is now a function of the liquid level 51 in the choke line and gas / air pressure above. This gas can be vented to atmospheric pressure or controlled and regulated by surface choke 22. This will create a smoother and more dynamic process than causing the pump suction pressure (liquid only) to directly control the well bore pressure . When the low compressibility liquid is contained in a closed circuit system, it will create a very rigid system. Minor changes will affect the well hole pressure immediately, while controlling the level of drilling fluid, mud and / or seawater in the choke line will be a slower and more controllable process.
    [0033] While drilling, this can configure a unique pressure control method. An inlet flow into the well between the open hole and the drill string can have a self-regulating effect. An inlet flow into the well bore has a higher density than air at the top of the choke line and, for the example case, 8 1/2 bore and 6 bore collars will have a capacity of at least 17, 8 liters per meter of hole section. The capacity of most choke lines (3 - 5) is between 4.56 liters per meter to 12.6 liters per meter. An inflow of a determined magnitude would increase the level in the lower capacity choke line to a level higher than that of the inflow in the open hole - drill string ring, thus a progressing inflow would be interrupted only by hydrostatic pressure highest created by a higher liquid level 51 in the strangulation line 17.
    Brief Description of the Drawings [0034] Figure 1a illustrates a conventional subsea drilling system in normal drilling operations;
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    13/20 [0035] Figure 1 b illustrates a conventional subsea drilling system in well control mode;
    [0036] Figure 2 illustrates a first embodiment of the present invention, including an elevator, in drilling mode;
    [0037] Figure 3 illustrates the modality of figure 2 in the well control mode;
    [0038] Figure 4 illustrates a second elevator-free embodiment of the present invention in drilling mode;
    [0039] Figure 5 illustrates the modality of figure 4 in the well control mode;
    [0040] Figure 6 illustrates the system of figures 4 and 5, performing an alternative method for well control.
    Detailed Description of the Invention [0041] Figure 2 illustrates a first embodiment of the underwater drilling system of the invention. It comprises a well having a well bore. The well hole can be partially closed. Above the seabed level 2 a submarine BOP 3 with a BOP 3a extension joint is fitted, which is equipped with several pressure sensors and several inlets and outlets. An elevator 4 is connected to the BOP and extends to a vessel 5 above sea level 6. The elevator 4 has a sliding joint 7 to accommodate the suspension of the vessel 5 and an elevator tensioning system 7a, 7b. Above the bypass housing and bypass outlet is a low pressure gas remover 53 installed to prevent the low pressure gas from escaping to the drilling floor of the drill frame. Bypass line 36 is vented to the atmosphere or the gas and slurry separator (not shown). The flow line valve 35 is closed as the drilling fluid is now returned via the underwater pump 11 and return line 12.
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    14/20 [0042] Drill cord 8 extends from an upper driver 9 on platform 5 and into well hole 1. The lower end of drill cord 8 is equipped with a drill bit 10.
    [0043] A liquid return line 12 is connected to the BOP 3a extension on a first side door 13 and extends to the water surface. The liquid return line has an underwater elevation pump 11 to assist in the return of the mud to the surface vessel 5. The liquid return line has a valve 49 in the branch between the first side door 13 and the pump 11.
    [0044] A gas return line 17 is also connected to BOP 3 or BOP 3a extension by a second side port 18. The gas return line 17 extends to the water surface and the drilling vessel 5. The line gas return valve has a first valve near the second side port 18 and a throttle valve near the water surface 6 or in the drilling unit. Both the liquid return line 12 and the gas return line 17 are at their upper ends connected to a collection tank 23 via a gas and mud separator 42 in the drilling frame.
    [0045] The BOP has a main hole 14 through which the drilling cord 8 extends. A plurality and safety valves 15, pistons 15a, 15b, 15c, are adapted to close the main orifice 14 around the drill pipe or to seal the well bore completely 15d to prevent an explosion.
    [0046] Above the safety valves 15 and below the first side door 13 the BOP 3 has a lower annular valve 16, which is adapted to close around the drilling tubes 8.
    [0047] The BOP has an upper annular valve 19 above the second side port 18. This annular valve can be a so-called rotating BOP, allowing drilling while the valve is closed.
    Petition 870190031009, dated 04/01/2019, p. 17/33
    15/20 [0048] An override line 24 extends from the lower BOP (here two side ports 25 and 26 are illustrated) below the lower annular valve 16 to a third side port 27 between the first and second side doors 13 and 18. The overtaking also has a branch 29 connecting to the gas return line 17 defined here as the gas line or choke line. The override line 24 has lower valves 28 to close the lower part of the overpass line 24, a first upper valve 30 to close the branch 29 and a second upper valve 31 to close the connection to port 27. Additionally, there is a valve bottleneck 32 on that overtaking line.
    [0049] The system also has an interruption line 33, which is also included in a conventional system.
    [0050] At the top of the elevator there is a mud flow line 34 with a flow line valve 35 and a bypass line 36 with a valve 37, which are also in accordance with a conventional system.
    [0051] As also according to a conventional system, there are several mud pumps 38 pumping mud from the collection tank 23 to the upper actuator 9 via a line 39. A valve 40 is included in line 39 near the upper actuator.
    [0052] Additionally, there is an amplification line 41 extending from a mud pump 38 to a fourth side door 42 in the Lower Marine Elevator Package or a circulation line connected below the first side door 13. Line 41 is equipped with at least one valve 50 near side port 42. It can be a back pressure valve and / or a two-way shut-off valve. This line can also be used to inject low density fluid or gas into the return path downstream of the undersea throttle valve installed near the BOP
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    16/20 submarine.
    [0053] The system as described above with respect to figure 2 is basically the same for all the modalities described later. In the following only the items that deviate from the disposition of figure 2 will be described in detail.
    [0054] The system of figure 2 can be used to drill with and without the marine drilling lift. Figure 4 illustrates a system without an elevator. Except for the lack of an elevator, the system is identical to the system described in figure 2.
    [0055] The operation of the system according to the invention will now be as described:
    [0056] Figure 2 illustrates the normal drilling mode of the system. During normal drilling with an elevator, both the upper and lower annular valves 16, 19 in BOP 3 are opened. The level of mud 45 in the BOP or BOP extension or elevator is controlled using the underwater mud elevation pump 11, which is hydraulically connected to the bottom of the BOP extension joint or elevator. Any drilling gas or carrier gas is vented out through the marine drilling lift, that is, through the gas vent line 36. Small suspended gas bubbles can, in most cases, follow the liquid mud phase into the pump system 11 and be pumped to the surface. On the surface the returns can be directed to the shale oscillators 43 directly or through a valve 47 to the gas and mud separator 42. The system allows the mud level 45 to be adjusted to control the downhole pressure. The fluid above the mud in the elevator can be any type of liquid or gas, including air.
    [0057] Figure 3 illustrates the system in a well control event. The rotation of the drill string is interrupted and the lower and upper annular valves 16, 19 are closed. This creates a cavity
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    17/20 between the lower and upper annular valves 16, 19. The well fluid is diverted from the lower annular valve 16 to below the upper annular valve 19, that is, into the cavity 46, through the overflow line 24 containing the throttle valve 32. The separation of fluids in cavity 46 in the BOP extension joint will occur due to gravity. The outlet 13 for the subsea lift pump 11 is arranged below the entry level 27 for the well fluid, and the gas is vented out to the surface via the gas return or choke line 17 connected to the located outlet 18 above fluid inlet 27 from the well. Typically, the gas and liquid interface level 45 will be located below the level for gas line 17. A surface choke 22 is used to control the pressure of the gas phase. The level 45 in the BOP cavity can be measured by pressure transducers, gamma densitometers, sound, or other methods.
    [0058] In this method of control of circulation and well pressure, the pressure of the surface drilling pipe can be regulated by the regulation of the submarine bottleneck 32, the underwater pump 11 can be used to regulate the level of liquid 45 in the BOP cavity and the pressure in the cavity can be regulated by pressure in the surface choke 22, pressure in the BOP cavity, or liquid level 51 in figure 6 (or a combination of the two).
    [0059] Figures 4 and 5 illustrate drilling without elevator, and the well control mode in drilling without elevator, respectively.
    [0060] During drilling without a lift, annular valves 16, 19 in BOP 3 are opened as shown in figure 4. The level of seawater and mud 45 in BOP 3 is controlled using the underwater mud lift pump. 11 and pressure sensors on the extension joint 3a between the two rings 16, 19. Any small amount of gas
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    18/20 drilling or support gas can escape into the sea from the open top of the BOP extension. However, most of the drilling gas will follow the return liquids through the pump system 11. In a well control event, the rotation of the drilling cord 8 is stopped and the lower and upper annular valves 16, 19 are closed, as shown in figure 5. The well fluid is diverted from below the lower annular 16 to below the upper annular valve 19 through the overflow line 24 containing the throttle valve 32. The throttle valve 32 will now control the downhole pressure and the pressure downstream of the choke 32 will be much less than the pressure upstream. This will improve the separation process.
    [0061] The separation of fluids in the BOP 3a extension joint will occur due to the action of gravity. An outlet 13 for the subsea lift pump 11 is arranged below the entry level 27 for the well fluid, and any free gas is vented out to the surface via the fixed or flexible choke line 17 above the water surface. . Normally, the gas and fluid level 45 will be located below the outlet level 18 for the vent line 17. A surface choke 22 is used to control the pressure of the gas phase.
    [0062] Figure 6 illustrates the submarine separator in an alternative mode. Here, submarine throttling 32 is used to control downhole pressure (BHP). The separator with the ventilation line 17 is used to remove gas from the liquid before entering the subsea lift pump. However, the liquid can enter the vent line 17 and establish a liquid and gas interface 51 on the vent line 17. The head of that liquid column and any pressure above the liquid and gas interface sets the pressure in the separator cavity. 46. By regulating the pressure above the
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    19/20 fluid and interface level 51, the pressure in cavity 46 can be adjusted as shown in figure 6.
    [0063] The pressure in the cavity 46 can be increased by pumping mud from the surface through the amplification line 41. This will quickly raise the interface 51 and thereby increase the pressure in the cavity 46. The pressure in the cavity 46 can be reduced by increasing the pump rate of the subsea return pump 11. This will quickly reduce interface level 51 and thereby the pressure in cavity 46. This provides a means to quickly adjust the pressure in cavity 46 and thereby , the support pressure against the well fluid entering cavity 46 from overflow line 24 if the choke is completely opened.
    [0064] In the event of an underwater pump failure or as an option, a low density fluid or gas can be injected into the return lines or throttle line, downstream of the underwater throttle valve, in order to maintain pressure immediately downstream of the subsea throttle valve 32 substantially less than the pressure upstream of the subsea throttle valve. In this way, the well pressure can be precisely controlled by submarine throttling.
    Means for Reducing Pressure Fluctuations [0065] In order to prevent the flow of pieces and large pressure variations, a throttle valve 32 can be used to control the flow of fluids into the separator 48 and prevent or reduce fluctuations pressure. The pressure fluctuation downstream of the subsea throttle valve 32 can also affect the pressure upstream of the subsea throttle (well pressure). However, maintaining the gas and fluid level within the separator allows for higher gas flow rates to be handled.
    [0066] Increasing the diameter of the choke line (15.24
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    20/20 to 20.32 cm) allows the liquid to enter the vent line 17 and separate from the gas without excessive pressure fluctuation in the BOP cavity. Since an undersea throttle valve reduces pressure, a low pressure throttle line can be used.
    [0067] In a subsea separation system without an efficient lift, the level of liquid and gas interface can be maintained within the separator and a surface throttle valve to control the separator pressure can be introduced.
    [0068] When keeping the pressure in the separator equal to or slightly below the ambient seawater pressure, normal drilling operations can be conducted without major adjustments to the separator pressure. With only gas in the choke line, the size can be reduced (5.08 to 7.62 cm). This system will also reduce the gas separated from the liquid before entering the subsea lift pump. The pressure will reduce the underwater pump differential pressure required to bring the return fluid back to the drilling vessel. Gas bleeding can occur at high rates.
    [0069] This means that the remaining gas still contained in the liquids needs to be separated on the surface. In this way, the gas from the choke line, and the mud and gas from the underwater lift pump can be bypassed through the Poor Boy 42 gas and mud separator / gas remover and vented out through the ventilation line on the winch.
    权利要求:
    Claims (26)
    [1]
    claims
    1. System for the control of a well during the drilling, completion or intervention of a well in an underwater well, comprising a well hole (1) and a submarine explosion prevention element (BOP) (3) above the well hole (1), characterized by the fact that it additionally comprises:
    a separator defined by a cavity (46) between a closed lower closing element (16) and a closed upper closing element (19), said closing elements (16, 19) being located in a part of the BOP (3) and / or in a lower marine elevator package (LMRP) (3a), said BOP (3) and / or lower marine elevator package (3a) being below any elevator (4);
    an overflow line (24) extending from the well hole (1) to the separator cavity (46);
    said separator cavity (46) being adapted to receive the well fluid, which can contain gas, through said overflow line (24), said overflow line having a fixed (32) or adjustable choke, a line of gas return (17) extending from an upper part of said separator cavity (46), a liquid return line (12) extending from a lower part of said separator cavity (46), to said return line (12) having a lift pump.
    [2]
    2. System, according to claim 1, characterized in that the overflow line (24) is connected to the separator cavity (46) above the liquid return line (12).
    [3]
    3. System according to claim 1 or 2, characterized in that the overflow line (24) is connected to the separator cavity (46) below the gas return line (17).
    [4]
    4. System according to any one of the preceding claims, characterized by the fact that said gas return line (17)
    Petition 870190031009, dated 04/01/2019, p. 24/33
    2/6 has a throttle valve (22).
    [5]
    5. System according to claim 4, characterized in that said throttle valve (22) is arranged close to the water surface level (6).
    [6]
    6. System according to any one of the preceding claims, characterized in that the pressure of well fluid in the cavity of the separator (46) is substantially equal to or less than the pressure of seawater in the seabed (2).
    [7]
    7. System according to any one of the preceding claims, characterized in that the separator cavity (46) is adapted to be opened for the well flow directly from the well hole ring (1), and the line return fluid (12) to be connected to a liquid filled part of the ring or separator cavity (46).
    [8]
    8. Method for the control of a well during the drilling, completion or intervention of a well in an underwater well, characterized by the fact that it comprises the following steps:
    create a separator cavity (46) by closing an upper (19) and lower (16) closure element, said closure elements (16, 19) being located in a submarine BOP (3) and / or marine lift package lower (3a) connected to the well below any elevator (4);
    withdrawing well fluid from the well hole (1) through an overflow line (24) fluidly connecting the well hole (1) with the separator cavity (46);
    separating the gas from the well fluid in the separator cavity (46);
    withdraw the liquid from a lower part of the separator cavity (46) and evacuate the liquid to the water surface (6);
    remove gas from an upper part of the separator cavity
    Petition 870190031009, dated 04/01/2019, p. 25/33
    3/6 (46) and let the gas flow to the water surface (6).
    [9]
    9. Method, according to claim 8, characterized in that the pressure in the well hole (1) below the lower closing element (16) is controlled by regulating the loss of friction in the overtaking line (24).
    [10]
    10. Method according to claim 8 or 9, characterized in that the pressure of the separator (46) is controlled by regulating the pressure of the gas flowing to the water surface (6).
    [11]
    Method according to any one of claims 8 to 10, characterized in that the liquid and gas interface in the separator cavity (46) is regulated by the rate of liquid evacuation from the bottom of the separator cavity ( 46).
    [12]
    Method according to any one of claims 8 to 11, characterized in that the gas flow is brought to the water surface (6) through a gas return line (17) and the gas pressure be reduced when removed from the separator cavity (46).
    [13]
    Method according to any one of claims 8 to 12, characterized in that it additionally comprises the connection of an elevator (4) above the separator cavity (46).
    [14]
    14. Method for the control of a well during the drilling, completion or intervention of a well in an underwater well, characterized by the fact that it comprises the following steps:
    establishment of a separator cavity (46) in a submarine BOP (3) and / or lower marine lift package (3a);
    establishing a choke return line (17) from said cavity;
    establishing a liquid return line (12) from said cavity;
    closing of an upper closing element (19),
    Petition 870190031009, dated 04/01/2019, p. 26/33
    4/6 located on the BOP (3) or the lower marine lift package (3a) and being above an outlet (18) for the choke return line (17) and the outlet (13) liquid return line ( 12), closing a lower closing element (16), located on the BOP or the lower marine lift package (3a) and being below an exit for a choke return line (17) and an exit (13) of liquid return line (12);
    allowing a liquid / gas interface (51) to establish in the throttle return line (17), and using the hydrostatic liquid head of that interface (51) and a gas pressure above the liquid / gas interface to control the pressure in the cavity (46);
    and withdrawing the liquid from the well bore (1) and evacuating the liquid to the water surface (6) through the liquid return line (12).
    [15]
    15. Method according to claim 14, characterized in that the pressure in the cavity (46) can be substantially equalized with the pressure of the well hole (1).
    [16]
    16. Method, according to claim 14, characterized in that a low density fluid is injected downstream of a throttle valve (32) in an overflow line (24) connecting the well hole (1) with the cavity (46) in order to keep the pressure immediately downstream of the throttle valve (32) lower than the pressure upstream of the throttle valve (32).
    [17]
    17. Method according to claim 14, characterized in that the choke return line (17) has a substantially smaller diameter than the well bore (1).
    [18]
    18. Method according to claim 16, characterized
    Petition 870190031009, dated 04/01/2019, p. 27/33
    5/6 due to the fact that the pressure in the well hole below the lower closing element (16) is controlled by regulating the loss of friction in the overtaking line (24).
    [19]
    19. Method according to claim 18, characterized in that it additionally comprises the pumping of a fluid at a variable flow rate into the well below the lower closure element (16) through an interruption line (33) .
    [20]
    20. Method according to claim 18 or 19, characterized in that the overflow line well fluids (24) enter the closed cavity (46) above the liquid outlet (13) and below the outlet (18) choke line (17).
    [21]
    21. Method according to any one of claims 14 to 20, characterized in that the gas pressure in the choke return line (17) is adjustable.
    [22]
    22. Method for the control of a well during the drilling, completion or intervention of a well in an underwater well, characterized by the fact that it comprises the following steps:
    close an element (16) in a submarine BOP (3) and / or lower marine lift package (3a) connected to the well, withdraw the fluid from the well from the well bore (1) through a choke line (24) connected by fluid to the well bore (1) below the closed BOP element (16), the choke line (24) containing an undersea choke valve (32) located near the BOP (3), the choke line (24) extending to the drilling installation on the water surface (6), inject a low density fluid, for example, a gas, into the choke line (24) _ downstream of the choke valve (32), evacuate the well downstream of the subsea throttle valve (32) to the water surface (6) while maintaining the pressure downstream of the subsea throttle (32) substantially below the pressure upstream of the subsea valve
    Petition 870190031009, dated 04/01/2019, p. 28/33
    6/6 underwater strangulation (32).
    [23]
    23. Method for the control of a well during the drilling, completion or intervention of a well in an underwater well, characterized by the fact that it comprises the following steps:
    create a cavity (46) by closing an upper (19) and lower (16) closure element in a submarine BOP (3) and / or lower marine lift package (3a) connected to the well, withdraw the fluid from the well to from the well through an overflow line (24) fluidly connecting the well bore (1) with the cavity (46), inject a low density fluid, eg gas, into the cavity (46) from the surface water (6), remove the mixed fluid from the top of the cavity (46) through a choke line (17) to the water surface (6), thus maintaining the pressure in the cavity (46) below that pressure in the well below the lower closed BOP element (16).
    [24]
    24. Method according to claim 22 or 23, characterized in that the pressure in the well hole (1) below the lower closure element (16) is controlled by regulating the loss of friction in the overtaking line (24) .
    [25]
    25. Method according to claims 22 to 24, characterized in that the cavity pressure (46) is controlled by regulating the pressure of the gas and liquid flowing to the surface (6) by a surface controlled choke (22) .
    [26]
    26. Method according to claims 22 to 25, characterized in that the well pressure is controlled by a throttle valve (32) controlled by surface in the overtaking line (24).
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    法律状态:
    2017-08-29| B25A| Requested transfer of rights approved|Owner name: ENHANCED DRILLING AS (NO) |
    2019-01-08| B06F| Objections, documents and/or translations needed after an examination request according art. 34 industrial property law|
    2019-02-05| B06T| Formal requirements before examination|
    2019-07-09| B09A| Decision: intention to grant|
    2019-09-03| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 10/11/2010, OBSERVADAS AS CONDICOES LEGAIS. (CO) 20 (VINTE) ANOS CONTADOS A PARTIR DE 10/11/2010, OBSERVADAS AS CONDICOES LEGAIS |
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    NO20093309|2009-11-10|
    PCT/EP2010/067169|WO2011058031A2|2009-11-10|2010-11-10|System and method for drilling a subsea well|
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