Patent Application
20110253445
N/A
N/A
1. Field of the Invention
This invention relates to conventional and/or managed pressure drilling from a floating rig.
2. Description of the Related Art
Rotating control devices (RCDs) have been used in the drilling industry for drilling wells. An internal sealing element fixed with an internal rotatable member of the RCD seals around the outside diameter of a tubular and rotates with the tubular. The tubular may be a drill string, casing, coil tubing, or any connected oilfield component. The tubular may be run slidingly through the RCD as the tubular rotates, or when the tubular is not rotating. Examples of some proposed RCDs are shown in U.S. Pat. Nos. 5,213,158; 5,647,444 and 5,662,181.
RCDs have been proposed to be positioned with marine risers. An example of a marine riser and some of the associated drilling components is proposed in U.S. Pat. No. 4,626,135. U.S. Pat. No. 6,913,092 proposes a seal housing with a RCD positioned above sea level on the upper section of a marine riser to facilitate a mechanically controlled pressurized system. U.S. Pat. No. 7,237,623 proposes a method for drilling from a floating structure using an RCD positioned on a marine riser. Pub. No. US 2008/0210471 proposes a docking station housing positioned above the surface of the water for latching with an RCD. U.S. Pat. Nos. 6,470,975; 7,159,669; and 7,258,171 propose positioning an RCD assembly in a housing disposed in a marine riser. An RCD has also been proposed in U.S. Pat. No. 6,138,774 to be positioned subsea without a marine riser.
U.S. Pat. Nos. 3,976,148 and 4,282,939 proposes methods for determining the flow rate of drilling fluid flowing out of a telescoping marine riser that moves relative to a floating vessel heave. U.S. Pat. No. 4,291,772 proposes a method and apparatus to reduce the tension required on a riser by maintaining a pressure on a lightweight fluid in the riser over the heavier drilling fluid.
Latching assemblies have been proposed in the past for positioning an RCD. U.S. Pat. No. 7,487,837 proposes a latch assembly for use with a riser for positioning an RCD. Pub. No. US 2006/0144622 proposes a latching system to latch an RCD to a housing. Pub. No. US 2009/0139724 proposes a latch position indicator system for remotely determining whether a latch assembly is latched or unlatched.
In more recent years, RCDs have been used to contain annular fluids under pressure, and thereby manage the pressure within the wellbore relative to the pressure in the surrounding earth formation. In some circumstances, it may be desirable to drill in an underbalanced condition, which facilitates production of formation fluid to the surface of the wellbore since the formation pressure is higher than the wellbore pressure. U.S. Pat. No. 7,448,454 proposes underbalanced drilling with an RCD. At other times, it may be desirable to drill in an overbalanced condition, which helps to control the well and prevent blowouts since the wellbore pressure is greater than the formation pressure. While Pub. No. US 2006/0157282 generally proposes Managed Pressure Drilling (MPD), International Pub. No. WO 2007/092956 proposes MPD with an RCD. MPD is an adaptive drilling process used to control the annulus pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the hydraulic annulus pressure profile accordingly.
One equation used in the drilling industry to determine the equivalent weight of the mud and cuttings in the wellbore when circulating with the rig mud pumps on is:
Equivalent Mud Weight (EMW)=Mud Weight Hydrostatic Head+Δ Circulating Annulus Friction Pressure (AFP)
This equation would be changed to conform the units of measurements as needed.
In one variation of MPD, the above Circulating Annulus Friction Pressure (AFP), with the rig mud pumps on, is swapped for an increase of surface backpressure, with the rig mud pumps off, resulting in a Constant Bottomhole Pressure (CBHP) variation of MPD, or a constant EMW, whether the mud pumps are circulating or not. Another variation of MPD is proposed in U.S. Pat. No. 7,237,623 for a method where a predetermined column height of heavy viscous mud (most often called kill fluid) is pumped into the annulus. This mud cap controls drilling fluid and cuttings from returning to surface. This pressurized mud cap drilling method is sometimes referred to as bull heading or drilling blind.
The CBHP MPD variation is achieved using non-return valves (e.g., check valves) on the influent or front end of the drill string, an RCD and a pressure regulator, such as a drilling choke valve, on the effluent or back return side of the system. One such drilling choke valve is proposed in U.S. Pat. No. 4,355,784. A commercial hydraulically operated choke valve is sold by M-I Swaco of Houston, Tex. under the name SUPER AUTOCHOKE. Also, Secure Drilling International, L.P. of Houston, Tex., now owned by Weatherford International, Inc., has developed an electronic operated automatic choke valve that could be used with its underbalanced drilling system proposed in U.S. Pat. Nos. 7,044,237; 7,278,496; 7,367,411 and 7,650,950. In summary, in the past, an operator of a well has used a manual choke valve, a semi-automatic choke valve and/or a fully automatic choke valve for an MPD program.
Generally, the CBHP MPD variation is accomplished with the drilling choke valve open when circulating and the drilling choke valve closed when not circulating. In CBHP MPD, sometimes there is a 10 choke-closing pressure setting when shutting down the rig mud pumps, and a 10 choke-opening setting when starting them up. The mud weight may be changed occasionally as the well is drilled deeper when circulating with the choke valve open so the well does not flow. Surface backpressure, within the available pressure containment capability rating of an RCD, is used when the pumps are turned off (resulting in no AFP) during the making of pipe connections to keep the well from flowing. Also, in a typical CBHP application, the mud weight is reduced by about 0.5 ppg from conventional drilling mud weight for the similar environment. Applying the above EMW equation, the operator navigates generally within a shifting drilling window, defined by the pore pressure and fracture pressure of the formation, by swapping surface backpressure, for when the pumps are off and the AFP is eliminated, to achieve CBHP.
The CBHP variation of MPD is uniquely applicable for drilling within narrow drilling windows between the formation pore pressure and fracture pressure by drilling with precise management of the wellbore pressure profile. Its key characteristic is that of maintaining a constant effective bottomhole pressure whether drilling ahead or shut in to make jointed pipe connections. CBHP is practiced with a closed and pressurizable circulating fluids system, which may be viewed as a pressure vessel. When drilling with a hydrostatically underbalanced drilling fluid, a predetermined amount of surface backpressure must be applied via an RCD and choke manifold when the rig's mud pumps are off to make connections.
While making drill string or other tubular connections on a floating rig, the drill string or other tubular is set on slips with the drill bit lifted off the bottom. The mud pumps are turned off. During such operations, ocean wave heave of the rig may cause the drill string or other tubular to act like a piston moving up and down within the “pressure vessel” in the riser below the RCD, resulting in fluctuations of wellbore pressure that are in harmony with the frequency and magnitude of the rig heave. This can cause surge and swab pressures that will effect the bottom hole pressures and may in turn lead to lost circulation or an influx of formation fluid, particularly in drilling formations with narrow drilling windows. Annulus returns may be displaced by the piston effect of the drill string heaving up and down within the wellbore along with the rig.
The vertical heave caused by ocean waves that have an average time period of more than 5 seconds have been reported to create surge and swab pressures in the wellbore while the drill string is suspended from the slips. See GROSSO, J. A., “An Analysis of Well Kicks on Offshore Floating Drilling Vessels,” SPE 4134, October 1972, pages 1-20, © 1972 Society of Petroleum Engineers. The theoretical surge and swab pressures due to heave motion may be calculated using fluid movement differential equations and average drilling parameters. See BOURGOYNE, J R., ADAM T., et al, “Applied Drilling Engineering,” pages 168-171, © 1991 Society of Petroleum Engineers.
In benign seas of less than a few feet of wave heave, the ability of the CBHP MPD method to maintain a more constant equivalent mud weight is not substantially compromised to a point of non-commerciality. However, in moderate to rough seas, it is desirable that this technology gap be addressed to enable CBHP and other variations of MPD to be practiced in the world's bodies of water where it is most needed, such as deep waters where wave heave may approach 30 feet (9.1 m) or more and where the geologic formations have narrow drilling windows. A vessel or rig heave of 30 feet (peak to valley and back to peak) with a 6⅝ inch (16.8 cm) diameter drill string may displace about 1.3 barrels of annulus returns on the heave up, and the same amount on heave down. Although the amount of fluid may not appear large, in some wellbore geometries it may cause pressure fluctuations up to 350 psi.
Studies show that pulling the tubular with a velocity of 0.5 m/s creates a swab effect of 150 to 300 psi depending on the bottomhole assembly, casing, and drilling fluid configuration. See WAGNER, R. R. et al., “Surge Field Tests Highlight Dynamic Fluid Response,” SPE/IADC 25771, February 1993, pages 883-892, © 1993 SPE/IADC Drilling Conference. One deepwater field in the North Sea reportedly faced heave effects between 75 to 150 psi. See SOLVANG, S. A. et al., “Managed Pressure Drilling Resolves Pressure Depletion Related Problems in the Development of the HPHT Kristin Field,” SPE/IADC 113672, January 2008, pages 1-9, © 2008 IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition. However, there are depleted reservoirs and deepwater prospects, such as in the North Sea, offshore Brazil, and elsewhere, where the pressure fluctuation from wave heaving must be lowered to 15 psi to stay within the narrow drilling window between the fracture and the pore pressure gradients. Otherwise, damage to the formation or a well kick or blow out may occur.
The problem of maintaining a bottomhole pressure (BHP) within acceptable limits in a narrow drilling window when drilling from a heaving Mobile Offshore Drilling Unit (MODU) is discussed in RASMUSSEN, OVLE SUNDE et al, “Evaluation of MPD Methods for Compensation of Surge-and-Swab Pressures in Floating Drilling Operations,” IADC/SPE 108346, March 2007, pages 1-11, © 2007 UDC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition. One proposed solution when using drilling fluid with density less than the pore pressure gradient is a continuous circulation method in which drilling fluid is continuously circulated through the drill string and the annulus during tripping and drill pipe connection. An identified disadvantage with the method is that the flow rate must be rapidly and continuously adjusted, which is described as likely to be challenging. Otherwise, fracturing or influx is a possibility. Another proposed solution using drilling fluid with density less than the pore pressure gradient is to use an RCD with a choke valve for back pressure control. However, again a rapid system response is required to compensate for the rapid heave motions, which is difficult in moderate to high heave conditions and narrow drilling windows.
A proposed solution when using drilling fluid with density greater than the pore pressure is a dual gradient drilling fluid system with a subsea mud lift pump, riser, and RCD. Another proposed solution when using drilling fluid with density greater than the pore pressure is a single gradient drilling fluid system with a subsea mud lift pump, riser, and RCD. A disadvantage with both methods is that a rapid response is required at the fluid level interface to compensate for pressure. Subsea mud lift systems utilizing only an adjustable mud/water or mud/air level in the riser will have difficulty controlling surge and swab effects. Another disadvantage is the high cost of a subsea pump operation.
The authors in the above IADC/SPE 108346 technical paper conclude that given the large heave motion of the MODU (±2 to 3 m), and the short time between surge and swab pressure peaks (6 to 7 seconds), it may be difficult to achieve complete surge and swab pressure compensation with any of the proposed methods. They suggest that a real-time hydraulics computer model is required to control wellbore pressures during connections and tripping. They propose that the capability of measuring BHP using a wired drill string telemetry system may make equivalent circulating density control easier, but when more accurate control of BHP is required, the computer model will be needed to predict the surge and swab pressure scenarios for the specific conditions. However, such a proposed solution presents a formidable task given the heave intervals of less than 30 seconds, since even programmable logic controller (PLC) controlled chokes consume that amount of time each heave direction to receive measurement while drilling (MWD) data, interpreting it, instructing a choke setting, and then reacting to it.
International Pub. No. WO 2009/123476 proposes that a swab pressure may be compensated for by increasing the opening of a subsea bypass choke valve to allow hydrostatic pressure from a subsea lift pump return line to be applied to increase pressure in the borehole, and that a surge pressure may be compensated for by decreasing the opening of the subsea bypass choke valve to allow the subsea lift pump to reduce the pressure in the borehole. The '476 publication admits that compensating for surge and swab pressure is a challenge on a MODU, and it proposes that its method is feasible if given proper measurements of the rig heave motion, and predictive control. However, accurate measurements are difficult to obtain and then respond to, particularly in such a short time frame. Moreover, predictive control is difficult to achieve, since rogue waves or other unusual wave conditions, such as induced by bad weather, cannot be predicted with accuracy. U.S. Pat. No. 5,960,881 proposes a system for reducing surge pressure while running a casing liner.
Wave heave induced pressure fluctuations also occur during tripping the drill string out of and returning it to the wellbore. When surface backpressure is being applied while tripping from a floating rig, such as during deepwater MPD, each heave up is an additive to the tripping out speed, and each heave down is an additive to the tripping in speed. Whether tripping in or out, these heave-related accelerations of the drill string must be considered. Often, the result is slower than desired tripping speeds to avoid surge-swab effects. This can create significant delays, particularly with deepwater rigs commanding rental rates of $500,000 per day.
The problem of maintaining a substantially constant pressure may also exist in certain applications of conventional drilling with a floating rig. In conventional drilling in deepwater with a marine riser, the riser is not pressurized by mechanical devices during normal operations. The only pressure induced by the rig operator and contained by the riser is that generated by the density of the drilling mud held in the riser (hydrostatic pressure). A typical marine riser is 21¼ inches (54 cm) in diameter and has a maximum pressure rating of 500 psi. However, a high strength riser, such as a 16 inch (40.6 cm) casing with a pressure rating around 5000 psi, known as a slim riser, may be advantageously used in deepwater drilling. A surface BOP may be positioned on such a riser, resulting in lower maintenance and routine stack testing costs.
To circulate out a kick and also during the time mud density changes are being made to get the well under control, the drill bit is lifted off bottom and the annular BOP closed against the drill string. The annular BOP is typically located over a ram-type BOP. Ram type blow out preventers have also been proposed in the past for drilling operations, such as proposed in U.S. Pat. Nos. 4,488,703; 4,508,313; 4,519,577; and 5,735,502. As with annular BOPs, drilling must cease when the internal ram BOP seal is closed or sealed against the drill string, or seal wear will occur. When floating rigs are used, heave induced pressure fluctuations may occur as the drill string or other tubular moves up and down notwithstanding the seal against it from the annular BOP. The annular BOP is often closed for this purpose rather than the ram-type BOP in part because the annular BOP seal inserts can be more easily replaced after becoming worn. The heave induced pressure fluctuations below the annular BOP seal may destabilize an un-cased hole on heave down (surge), and suck in additional influx on heave up (swab).
There appears to be a general consensus that the use of deepwater floating rigs with surface BOPs and slim risers presents a higher risk of the kick coming to surface before a BOP can be closed. With the surface BOP annular seal closed, it sometimes takes hours to circulate out riser gas. Significant heaving on intervals such as 30 seconds (peak to valley and back to peak) may cause or exacerbate many time consuming problems and complications resulting therefrom, such as (1) rubble in the wellbore, (2) out of gauge wellbore, and (3) increased quantities of produced-to-surface hydrocarbons. Wellbore stability may be compromised.
Drill string motion compensators have been used in the past to maintain constant weight on the drill bit during drilling in spite of oscillation of the floating rig due to wave motion. One such device is a bumper sub, or slack joint, which is used as a component of a drill string, and is placed near the top of the drill collars. A mandrel composing an upper portion of the bumper sub slides in and out of a body of the bumper sub like a telescope in response to the heave of the rig, and this telescopic action of the bumper sub keeps the drill bit stable on the wellbore during drilling. However, a bumper sub only has a maximum 5 foot (1.5 m) stroke range, and its 37 foot (11.3 m) length limits the ability to stack bumper subs in tandem or in triples for use in rough seas.
Drill string heave compensator devices have been used in the past to decrease the influence of the heave of a floating rig on the drill string when the drill bit is on bottom and the drill string is rotating for drilling. The prior art heave compensators attempt to keep a desired weight on the drill bit while the drill bit is on bottom and drilling. A passive heave compensator known as an in-line compensator may consist of one or more hydraulic cylinders positioned between the traveling block and hook, and may be connected to the deck-mounted air pressure vessels via standpipes and a hose loop, such as the Shaffer Drill String Compensator available from National Oilwell Varco of Houston, Tex.
The passive heave compensator system typically compensates through hydro-pneumatic action of compressing a volume of air and throttling of fluid via cylinders and pistons. As the rig heaves up or down, the set air pressure will support the weight corresponding to that pressure. As the drilling gets deeper and more weight is added to the drill string, more pressure needs to be added. A passive crown mounted heave compensator may consist of vertically mounted compression-type cylinders attached to a rigid frame mounted to the derrick water table, such as the Shaffer Crown Mounted Compensator also available from National Oilwell Varco of Houston, Tex. Both the in-line and crown mounted heave compensators use either hydraulic or pneumatic cylinders that act as springs supporting the drill string load, and allow the top of the drill string to remain stationary as the rig heaves. Passive heave compensators may be only about 45% efficient in mild seas, and about 85% efficient in more violent seas, again while the drill bit is on bottom and drilling.
An active heave compensator may be a hydraulic power assist device to overcome the passive heave compensator seal friction and the drill string guide horn friction. An active system may rely on sensors (such as accelerometers), pumps and a processor that actively interface with the passive heave compensator to maintain the weight needed on the drill bit while on bottom and drilling. An active heave compensator may be used alone, or in combination with a passive heave compensator, again when the drill bit is on bottom and the drill string is rotating for drilling. An active heave compensator is available from National Oilwell Varco of Houston, Tex.
A downhole motion compensator tool, known as the Subsea Downhole Motion Compensator (SDMC™) available from Weatherford International, Inc. of Houston, Tex., has been successfully used in the past in numerous milling operations. SDMC™ is a trademark of Weatherford International, Inc. See DURST, DOUG et al, “Subsea Downhole Motion Compensator: Field History, Enhancements, and the Next Generation,” IARC/SPE 59152, February 2000, pages 1-12, © 2000 Society of Petroleum Engineers Inc. The authors in the above technical paper IADC/SPE 59152 report that although semisubmersible drilling vessels may provide active rig-heave equipment, residual heave is expected when the seas are rough. The authors propose that rig-motion compensators, which operate when the drill bit is drilling, can effectively remove no more than about 90% of heave motion. The SDMC™ motion compensator tool is installed in the work string that is used for critical milling operations, and lands in or on either the wellhead or wear bushing of the wellhead. The tool relies on slackoff weight to activate miniature metering flow regulators that are contained within a piston disposed in a chamber. The tool contains two hydraulic cylinders, with metering devices installed in the piston sections. U.S. Pat. Nos. 6,039,118 and 6,070,670 propose downhole motion compensator tools.
Riser slip joints have been used in the past to compensate for the vertical movement of the floating rig on the riser, such as proposed in FIG. 1 of both U.S. Pat. Nos. 4,282,939 and 7,237,623. However, when a riser slip joint is located within the “pressure vessel” in the riser below the RCD, its telescoping movement may result in fluctuations of wellbore pressure much greater than 350 psi that are in harmony with the frequency and magnitude of the rig heave. This creates problems with MPD in formations with narrow drilling windows, particularly with the CBHP variation of MPD.
The above discussed U.S. Pat. Nos. 3,976,148; 4,282,939; 4,291,772; 4,355,784; 4,488,703; 4,508,313; 4,519,577; 4,626,135; 5,213,158; 5,647,444; 5,662,181; 5,735,502; 5,960,881; 6,039,118; 6,070,670; 6,138,774; 6,470,975; 6,913,092; 7,044,237; 7,159,669; 7,237,623; 7,258,171; 7,278,496; 7,367,411; 7,448,454; 7,487,837; and 7,650,950; and Pub. Nos. US 2006/0144622; 2006/0157282; 2008/0210471; and 2009/0139724; and International Pub. Nos. WO 2007/092956 and WO 2009/123476 are all hereby incorporated by reference for all purposes in their entirety. U.S. Pat. Nos. 5,647,444; 5,662,181; 6,039,118; 6,070,670; 6,138,774; 6,470,975; 6,913,092; 7,044,237; 7,159,669; 7,237,623; 7,258,171; 7,278,496; 7,367,411; 7,448,454 and 7,487,837; and Pub. Nos. US 2006/0144622; 2006/0157282; 2008/0210471; and 2009/0139724; and International Pub. No. WO 2007/092956 are assigned to the assignee of the present invention.
A need exists when drilling from a floating drilling rig for an approach to rapidly compensate for the change in pressure caused by the vertical movement of the drill string or other tubular when the rig's mud pumps are off and the drill string or tubular is lifted off bottom as joint connections are being made, particularly in moderate to rough seas and in geologic formations with narrow drilling windows between pore pressure and fracture pressure. Also, a need exists when drilling from floating rigs for an approach to rapidly compensate for the heave induced pressure fluctuations when the rig's mud pumps are off, the drill string or tubular is lifted off bottom, the annular BOP seal is closed, and the drill string or tubular nevertheless continues to move up and down from wave induced heave on the rig while riser gas is circulated out. Also, a need exists when tripping the drill string into or out of the hole to optimize tripping speeds by canceling the rig heave-related swab-surge effects. Finally, a need exists when drilling from floating rigs for an approach to rapidly compensate for the heave induced pressure fluctuations when the rig's mud pumps are on, the drill bit is on bottom with the drill string or tubular rotating during drilling, and a telescoping joint in the riser located below an RCD telescopes from the heaving.
A system for both conventional and MPD drilling is provided to compensate for heave induced pressure fluctuations on a floating rig when a drill string or other tubular is lifted off bottom and suspended on the rig. When suspended, the tubular moves vertically within a riser, such as when tubular connections are made during MPD, when tripping, or when a gas kick is circulated out during conventional drilling. The system may also be used to compensate for heave induced pressure fluctuations on a floating rig from a telescoping joint located below an RCD when a drill string or other tubular is rotating for drilling. The system may be used to better maintain a substantially constant BHP below an RCD or a closed annular BOP. Advantageously, a method for use of the below system is provided.
In one embodiment, a valve may be remotely activated to an open position to allow the movement of liquid between the riser annulus below an RCD or annular BOP and a flow line in communication with a gas accumulator containing a pressurized gas. A gas source may be in fluid communication with the flow line and/or the gas accumulator through a gas pressure regulator. A liquid and gas interface preferably in the flow line moves as the tubular moves, allowing liquid to move into and out of the riser annulus to compensate for the vertical movement of the tubular. When the tubular moves up, the interface may move further along the flow line toward the riser. When the tubular moves down, the interface may move further along the flow line toward or into the gas accumulator.
In another embodiment, a valve may be remotely activated to an open position to allow the liquid in the riser annulus below an RCD or annular BOP to communicate with a flow line. A pressure relief valve or an adjustable choke connected with the flow line may be set at a predetermined pressure. When the tubular moves down and the set pressure is obtained, the pressure relief valve or choke allows the fluid to move through the flow line toward a trip tank. Alternatively, or in addition, the fluid may be allowed to move through the flow line toward the riser above the RCD or annular BOP. When the tubular moves up, a pressure regulator set at a first predetermined pressure allows the mud pump to move fluid along the flow line to the riser annulus below the RCD or annular BOP. A pressure compensation device, such as an adjustable choke, may also be set at a second predetermined pressure and positioned with the flow line to allow fluid to move past it when the second predetermined pressure is reached or exceeded.
In yet another embodiment, in a slip joint piston method, a first valve may be remotely activated to an open position to allow the liquid in the riser annulus below the RCD or annular BOP to communicate with a flow line. The flow line may be in fluid communication with a fluid container that houses a piston. A piston rod may be attached to the floating rig or the movable barrel of the riser telescoping joint, which is in turn attached to the floating rig. The fluid container may be in fluid communication with the riser annulus above the RCD or annular BOP through a first conduit. The fluid container may also be in fluid communication with the riser annulus above the RCD or annular BOP through a second conduit and second valve. The piston can move in the same direction and the same distance as the tubular to move the required amount of fluid into or out of the riser annulus below the RCD or annular BOP.
In one embodiment of the slip joint piston method, when the tubular moves down, the piston moves down, moving fluid from the riser annulus located below the RCD or annular BOP into the fluid container. When the tubular heaves up, the piston moves up, moving fluid from the fluid container to the riser annulus located below the RCD or annular BOP. A shear member may be used to allow the piston rod to be sheared from the rig during extreme heave conditions. A volume adjustment member may be positioned with the piston in the fluid container to compensate for different tubular and riser sizes.
In another embodiment of the slip joint piston method, a first valve may be remotely activated to an open position to allow the liquid in the riser annulus below the RCD or annular BOP to communicate with a flow line. The flow line may be in fluid communication with a fluid container that houses a piston. The piston rod may be attached to the floating rig or the movable barrel of the riser telescoping joint, which is in turn attached to the floating rig. The fluid container may be in fluid communication with a trip tank through a trip tank conduit. The fluid container may have a fluid container conduit with a second valve. The piston can move in the same direction and the same distance as the tubular to move the required amount of fluid into or out of the riser annulus below the RCD or annular BOP.
Any of the embodiments may be used with a riser having a telescoping joint located below an RCD to compensate for the pressure fluctuations caused by the heaving movement of the telescoping joint when the drill bit is on bottom and drilling. For all of the embodiments, there may be redundancies. Two or more different embodiments may be used together for redundancy. There may be dedicated flow lines, valves, pumps, or other apparatuses for a single function, or there may be shared flow lines, valves, pumps, or apparatuses for different functions.
A better understanding of the present invention can be obtained with the following detailed descriptions of the various disclosed embodiments in the drawings:
The below systems and methods may be used in many different drilling environments with many different types of floating drilling rigs, including floating semi-submersible rigs, submersible rigs, drill ships, and barge rigs. The below systems and methods may be used with MPD, such as with CBHP to maintain a substantially constant BHP, during tripping including drill string connections and disconnections. The below systems and methods may also be used with other variations of MPD practiced from floating rigs, such as dual gradient drilling and pressurized mud cap. The below systems and methods may be used with conventional drilling, such as when the annular BOP is closed to circulate out a kick or riser gas, and also during the time mud density changes are being made to get the well under control, while the floating rig experiences heaving motion. The more compressible the drilling fluid, the more benefit that will be obtained from the below systems and methods when underbalanced drilling. The below systems and methods may also be used with a riser having a telescoping joint located below an RCD to compensate for the pressure fluctuations caused by the heaving movement of the telescoping joint when the drill bit is in contact with the wellbore and drilling. As used herein, drill bit includes, but is not limited to, any device disposed with a drill string or other tubular for cutting or boring the wellbore.
Accumulator System
Turning to
Other riser tension systems are contemplated for all embodiments shown in all of the Figures, such as riser tensioner cables connected to a riser tensioner ring disposed with the riser, such as shown in
First T-connector 23 extends from the right side of the riser 16, and first valve 26 is disposed with the first T-connector 23 and fluidly connected with first flexible flow line 30. First valve 26 may be remotely actuatable. First valve may be in hardwire connection with a PLC 38. Sensor 25 may be positioned within first T-connector 23, as shown in
A vent valve 36 may be disposed with accumulator 34 to allow the movement of vent gas or other fluids through vent line 44. A gas source 42 may be in fluid communication with first flow line 30 through a pressure regulator 40. Gas source 42 may provide a compressible gas, such as Nitrogen or air. It is also contemplated that the gas source 42 and/or pressure regulator 40 may be in fluid communication directly with accumulator 34. Pressure regulator 40 may be in hardwire connection with PLC 38. However, pressure regulator 40 may be operated manually, semi-automatically, or automatically to maintain a predetermined pressure. For all embodiments shown in all of the Figures, any connection with a PLC may also be wireless and/or may actively interface with other systems, such as the rig's data collection system and/or MPD choke control systems. Second T-connector 24 extends from the left side of the riser 16, and second valve 28 is fluidly connected with the second T-connector 24 and fluidly connected with second flexible flow line 32, which is fluidly connected with choke manifold 3. It is contemplated that other devices besides a choke manifold 3 may be connected with second flow line 32.
For redundancy, it is contemplated that a mirror-image second accumulator, second gas source, and second pressure regulator may be fluidly connected with second flow line 32 similar to what is shown on the right side of the riser 16 in
For
In
First T-connector 82 extends from the right side of the BOP spool 72, and first valve 86 is disposed with the first T-connector 82 and fluidly connected with first flexible flow line or hose 90. Although flexible flow lines are preferred, it is contemplated that partial rigid flow lines may also be used with flexible portions. First valve 86 may be remotely actuatable, and it may be in hardwire connection with a PLC 100. An operator console 115 may be in hardwire connection with PLC 100. The operator console 115 may be located on the rig for use by rig personnel. A similar operator console may be in hardwire connection with any PLC shown in any of the Figures. Sensor 83 may be positioned within first T-connector 82, as shown in
Second T-connector 84 extends from the left side of the BOP spool 72, and a second valve 88 is fluidly connected with the second T-connector 84 and fluidly connected with second flexible flow line or hose 92. For redundancy, a minor-image second flow line 92 is fluidly connected with a second accumulator 112, a second gas source 106, a second pressure regulator 108, and a second PLC 110 similar to what is shown on the right side of the riser 76. Second vent valve 114 and second vent line 116 are in fluid communication with second accumulator 112. Alternatively, one accumulator may be fluidly connected with both flow lines (90, 92). A well control choke 81, such as used to circulate out a well kick, may also be in fluid connection with second T-connector 84. It is contemplated that other devices may be connected with first or second T-connectors (82, 84). First valve 86 and second valve 88 may be hydraulically remotely actuated controlled or operated gate (HCR) valves, although other types of valves are contemplated.
It is contemplated that riser 76 may be a casing type riser or slim riser with a pressure rating of 5000 psi or higher, although other types of risers are contemplated. The pressure rating of the system may correspond to that of the riser 76, although the pressure rating of the first flow line 90 and second flow line 92 must also be considered if they are lower than that of the riser 76. The use of surface BOPs and slim risers, such as 16 inch (40.6 cm) casing, allows older rigs to drill in deeper water than originally designed because the overall weight to buoy is less, and the rig has deck space for deeper water depths with a slim riser system than it would have available if it were carrying a typical 21¼ inch (54 cm) diameter riser with a 500 psi pressure rating. It is contemplated that first accumulator 94, second accumulator 112, first gas source 104, second gas source 106, first pressure regulator 102, and/or second pressure regulator 108 may be positioned on or over the rig floor, such as over beam 60.
Accumulator Method
When drilling using the embodiment shown in
When a connection to the drill string DS needs to be made, or when tripping, the rig's mud pumps are turned off and the first valve 26 may be opened. The rotation of the drill string DS is stopped and the drill string DS is lifted off bottom and suspended from the rig, such as with slips. Drill string or tubular DS is shown lifted in
When the tubular moves upward, the pressure of the gas, and the suction or swab created by the tubular in the riser 16, will cause the liquid and gas interface to move along the first flow line 30 toward the riser 16, replacing the volume of drilling fluid moved by the tubular. A substantially equal amount of volume to that previously removed from the annulus is moved back into the annulus. The compressibility of the gas may significantly dampen the pressure fluctuations during connections. For a 6⅝ inch (16.8 cm) casing and 30 feet (9.1 m) of heave, it is contemplated that approximately 150 cubic feet of gas volume may be needed in the accumulator 34 and first flow line 30, although other amounts are contemplated
The pressure regulator 40 may be used in conjunction with the gas source 42 to insure that a predetermined pressure of gas is maintained in the first flow line 30 and/or the gas accumulator 34. The pressure regulator 40 may be monitored or operated with a PLC 38. However, the pressure regulator 40 may be operated manually, semi-automatically, or automatically. A valve that may regulate pressure may be used instead of a pressure regulator. If the pressure regulator 40 or valve is PLC controlled, it may be controlled by an automated choke manifold system, and may be set to be the same as the targeted choke manifold's surface back pressure to be held when the rig's mud pumps are turned off. It is contemplated that the choke manifold back pressure and matching accumulator gas pressure setting are different values for each bit-off-bottom occasion, and determined by the circulating annular friction pressure while the last stand was drilled. It is contemplated that the values may be adjusted or constant.
Although the accumulator vent valve 36 usually remains closed, it may be opened to relieve undesirable pressure sensed in the accumulator 34. When the drill string connection is completed, first valve 26 is remotely actuated to a closed position and drilling or rotation of the tubular may resume. If a redundant system is connected with second flow line 32 as described above, it may be used instead of the system connected with first flow line 30, such as by keeping first valve 26 closed and opening second valve 28 when drill string connections need to be made. It is contemplated that second valve 28 may remain open for drilling. A redundant system may also be used in combination with the first flow line 30 system as discussed above.
When drilling using the embodiment shown in
For all embodiments shown in all of the Figures and/or discussed therewith, it is contemplated that the systems and methods may be used when tripping the drill string out of and returning it to the wellbore. During tripping, the drill bit DB is lifted off bottom, and the same methods may be used as described for when the drill bit DB is lifted off bottom for a drill string connection. The systems and methods offer the advantage of allowing for the optimization and/or maximization of tripping speeds by, in effect, cancelling the heave-up and heave down pressure fluctuations otherwise caused by a heaving drill string or other tubular. It is contemplated that the drill string or other tubular may be moved relative to the riser at a predetermined speed, and that any of the embodiments shown in any of the Figures may be positioned with the riser and operated to substantially eliminate the heave induced pressure fluctuations in the “pressure vessel” so that a substantially constant pressure may be maintained in the annulus between the tubular and the riser while the predetermined speed of the tubular is substantially maintained. Otherwise, a lower or variable tripping speed may need to be used.
For all embodiments shown in all of the Figures and/or discussed therewith, it is contemplated that pressure sensors (25, 83, 139, 211, 259) and a respective PLC (38, 100, 155, 219, 248) may be used to monitor pressures, heave-induced fluctuations of those pressures, and their rates of change, among other measurements. Actual heave may also be monitored, such as via riser tensioners, such as the riser tensioners (20, 22) shown in
Pump and Relieve System
Turning to
RCD housing 128 may be a housing such as the docking station housing in Pub. No. US 2008/0210471 positioned above the surface of the water for latching with an RCD. However, other RCD housings are contemplated, such as the RCD housings disposed in a marine riser proposed in U.S. Pat. Nos. 6,470,975; 7,159,669; and 7,258,171. The RCD 126 may allow for MPD, including the CBHP variation of MPD. A subsea BOP 170 is positioned on the wellhead at the sea floor. The subsea BOP 170 may be a ram-type BOP and/or an annular BOP. Although the subsea BOP 170 is only shown in
First T-connector 138 extends from the right side of the riser 132, and first valve 142 is fluidly connected with the first T-connector 138 and fluidly connected with first flexible flow line 146. First valve 142 may be remotely actuatable. First valve 142 may be in hardwire connection with a PLC 155. Sensor 139 may be positioned within first T-connector 138, as shown in
Second T-connector 140 extends from the left side of the riser 132, and second valve 144 is fluidly connected with the second T-connector 140 and fluidly connected with second flexible flow line 148, which is fluidly connected with a second trip tank 181, such as a dedicated trip tank, or an existing trip tank on the rig used for multiple purposes. It is also contemplated that there may be only first trip tank 150, and that second flow line 148 may be connected with first trip tank 150. It is also contemplated that instead of second trip tank 181, there may be a MPD drilling choke connected with second flow line 148. The MPD drilling choke may be a dedicated choke manifold that is manual, semi-automatic, or automatic. Such an MPD drilling choke is available from Secure Drilling International, L.P. of Houston, Tex., now owned by Weatherford International, Inc.
Second valve 144 may be remotely actuatable. It is also contemplated that second valve 144 may be a settable overpressure relief valve, or that it may be a rupture disk device that ruptures at a predetermined pressure to allow fluid to pass, such as a predetermined pressure less than the maximum allowable pressure capability of the riser 132. It is also contemplated that for redundancy, a mirror-image configuration identical to that shown on the right side of the riser 132 may also be used on the left side of the riser 132, such as second fluid line 148 being in fluid communication through a second four-way mud cross with a second mud pump, a second pressure compensation device, and a second trip tank through a second pressure relief valve. It is contemplated that mud pump 156, pressure compensation device 154, pressure relief valve 160, first trip tank 150, and/or second trip tank 180 may be positioned on or over the rig floor, such as over beam 120.
Pump and Relieve Method
When drilling using the embodiment shown in
Using the system shown to the right of the riser 132, when the drill string or tubular moves downward, the volume of drilling fluid displaced by the downward movement will flow through the open first valve 142 into first flow line 146, which contains the same type of drilling fluid or water as is in the riser 132. First pressure relief valve 160 may be pre-set to open at a predetermined pressure, such as the same setting as the drill choke manifold during that connection, although other settings are contemplated. At the predetermined pressure, first pressure relief valve 160 allows a volume of fluid to move through it until the pressure of the fluid is less than the predetermined pressure. The downward movement of the tubular will urge the fluid in first flow line 146 past the first pressure relief valve 160.
If tank line 184 and riser line 164 are both present as shown in
When the drill string or tubular DS moves upward, the mud pump 156 with pressure regulator is activated and moves fluid through the first fluid line 146 and into the riser 132 below the sealed RCD 126. The pressure regulator with the mud pump 156 and/or the pressure compensation device 154 may be pre-set at whatever pressure the shut-in manifold surface backpressure target should be during the tubular connection, although other settings are contemplated. It is contemplated that mud pump 156 may alternatively be in communication with the flow line serving the choke manifold rather than a dedicated flow line such as first flow line 146. It is also contemplated that mud pump 156 may alternatively be the rig's mud kill pump, or a dedicated auxiliary mud pump such as shown in
It is also contemplated that mud pump 156 may be an auxiliary mud pump such as proposed in the auxiliary pumping systems shown in FIG. 1 of U.S. Pat. Nos. 6,352,129, FIGS. 2 and 2a of U.S. Pat. No. 6,904,981, and FIG. 5 of U.S. Pat. No. 7,044,237, all of which patents are hereby incorporated by reference for all purposes in their entirety. It is contemplated that mud pump 156 may be used in combination with the auxiliary pumping systems proposed in the '129, '981, and '237 patents. Mud pump 156 may receive fluid through mud pump line 180 from a fluid source, such as first trip tank 150, the rig's drilling fluid source, or a dedicated mud source. When the drill string connection is completed, first valve 142 is closed and rotation of the tubular or drilling may resume.
It should be understood that when drilling conventionally, the embodiment shown in
Slip Joint Piston System
Turning to
RCD housing 208 may be a housing such as the docking station housing proposed in Pub. No. US 2008/0210471. However, other RCD housings are contemplated, such as the RCD housings disposed in a marine riser proposed in U.S. Pat. Nos. 6,470,975; 7,159,669; and 7,258,171. The RCD 206 allows for MPD, including the CBHP variation of MPD. First T-connector 232 and second T-connector 234 with fluidly connected valves and flow lines are shown extending outwardly from the riser 216. However, they are optional for this embodiment. Drill string DS is disposed in riser 216 with drill bit DB spaced apart from the wellbore W, such as when tubular connections are made.
Flow line 214 with first valve 212 may be fluidly connected with RCD housing 208. It is also contemplated that flow line 214 with first valve 212 may alternatively be fluidly connected below the RCD housing 208 with riser 216 or it components. Flow line 214 may be flexible, rigid, or a combination of flexible and rigid. First valve 212 may be remotely actuatable and in hardwire connection with a PLC 219. Sensor 211 may be positioned within flow line 214, as shown in
It is contemplated that fluid container 217 may have an outside diameter of 10 inches (25.4 cm), although other sizes are contemplated. It is contemplated that the pressure rating of the fluid container 217 may be a multiple of the maximum surface back pressure during connections, such as 3000 psi, although other pressure ratings are contemplated. It is contemplated that the volume capacity of the fluid container 217 may be approximately twice the displaced annulus volume resulting from the drill string or tubular DS at maximum wave heave, such as for example 2.6 barrels (1.3 barrels×2) assuming a 6⅝ inch (16.8 cm) diameter drill string and 30 foot (9.1 m) heave (peak to valley and back to peak). The height of the fluid container 217 and the length of the piston rod 218 in the fluid container 217 should be greater than the maximum heave distance to insure that the piston 224 remains in the fluid container 217. The height of the fluid container 217 may be about the same height as the outer barrel of the slip joint 204. The piston rod may be in 10 foot (3 m) threaded sections to accommodate a range of wave heaves. The fluid container and piston could be fabricated by The Sheffer Corporation of Cincinnati, Ohio.
A shearing device such as shear pin 220 may be disposed with piston rod 218 at its connection with rig beam 200 to allow a predetermined location and force shearing of the piston rod 218 from the rig. Other shearing methods and systems are contemplated. Piston rod 218 may extend through a sealed opening in fluid container cap 236. A volume adjustment member 222 may be positioned with piston 224 to compensate for different annulus areas including sizes of tubulars inserted through the riser 216, or different riser sizes, and therefore the different volumes of fluid displaced. Volume adjustment member 222 may be clamped or otherwise positioned with piston rod 218 above piston 224. Drill string or tubular DS is shown lifted with the drill bit spaced apart from the wellbore, such as when tubular connections are made.
As an alternative to using a different volume adjustment member 222 for different tubular sizes, it is contemplated that piston rods with different diameters may be used to compensate for different annulus areas including sizes of tubulars inserted through the riser 216 and risers. As another alternative, it is contemplated that different fluid containers 217 with different volumes, such as having the same height but different diameters, may be used to compensate for different diameter tubulars. A smaller tubular diameter may correspond with a smaller fluid container diameter.
First conduit 226, such as an open flanged spool, provides fluid communication between the fluid container 217 and the riser 216 above the sealed RCD 206. Second conduit 228 provides fluid communication between the fluid container 217 and the riser 216 above the sealed RCD 206 through second valve 229. Second valve 229 may be remotely actuatable and in hardwire connection with PLC 219. Fluid, such as drilling fluid, seawater, or water, may be in fluid container 217 above and below piston 224. The fluid may be in riser 216 at a fluid level, such as fluid level 230, to insure that there is fluid in fluid container 217 regardless of the position of piston 224. First conduit 226 and second conduit 228 may be 10 inches (25.4 cm) in diameter, although other diameters are also contemplated. First valve 212 and/or second valve 229 may be HCR valves, although other types of valves are contemplated. Although not shown, it is contemplated that a redundant system may be attached to the left side of riser 216 similar to the system shown on the right side of the riser 216 or similar to any embodiment shown in any of the Figures. It is also contemplated that as an alternative embodiment to
Turning to
Flow line 256 with first valve 258 may be fluidly connected with RCD housing 272. It is also contemplated that flow line 256 with first valve 258 may alternatively be fluidly connected below the RCD housing 272 with riser 268 or any of its components. Flow line 256 may be rigid, flexible, or a combination of flexible and rigid. First valve 258 may be remotely actuatable and in hardwire connection with a PLC 248. Sensor 259 may be positioned within flow line 256, as shown in
It is contemplated that fluid container 282 may have an outside diameter of 10 inches (25.4 cm), although other sizes are contemplated. It is contemplated that the pressure rating of the fluid container 282 may be a multiple of the maximum surface back pressure during connections, such as 3000 psi, although other pressure ratings are contemplated. It is contemplated that the volume capacity of the fluid container 282 may be approximately twice the displaced annulus volume resulting from the drill string or tubular at maximum wave heave, such as for example 2.6 barrels (1.3 barrels×2) assuming a 6⅝ inch (16.8 cm) diameter drill string and 30 foot (9.1 m) heave (peak to valley and back to peak). The height of the fluid container 282 and the length of the piston rod 244 in the fluid container 282 should be greater than the maximum heave distance to insure that the piston 284 remains in the fluid container 282. The height of the fluid container 282 may be about the same height as the outer barrel of the slip joint 280. The piston rod may be in 10 foot (3 m) threaded sections to accommodate a range of wave heaves. The fluid container and piston could be fabricated by The Sheffer Corporation of Cincinnati, Ohio.
A shearing device such as shear pin 242 may be disposed with piston rod 244 at its connection with rig beam 240 to allow a predetermined location and force shearing of the piston rod 244 from the rig. Other shearing methods and systems are contemplated. Piston rod 244 may extend through a sealed opening in fluid container cap 288. A volume adjustment member 286 may be positioned with piston 244 to compensate for different annulus areas including sizes of tubulars inserted through the riser 268, or different riser sizes, and therefore the different volumes of fluid displaced.
Volume adjustment member 286 may be clamped or otherwise positioned with piston rod 244 above piston 284. As an alternative to using a different volume adjustment member 286 for different tubular sizes, it is contemplated that piston rods with different diameters may be used to compensate for different annulus areas including sizes of tubulars inserted through the riser 268 and risers. As another alternative, it is contemplated that different fluid containers 282 with different volumes, such as having the same height but different diameters, may be used to compensate for different diameter tubulars. A smaller tubular diameter may correspond with a smaller fluid container diameter.
Fluid container conduit 252 is in fluid communication through second valve 254 between the portion of fluid container 282 above the piston 284 and the portion of fluid container 282 below piston 284. Second valve 254 may be remotely actuatable, and in hardwire connection with PLC 248. Any hardwire connections with a PLC in any of the embodiments in any of the Figures may also be wireless. Trip tank conduit 250 is in fluid communication between the fluid container 282 and trip tank 246. Trip tank 246 may be a dedicated trip tank, or it may be an existing trip tank on the rig that may be used for multiple purposes. Trip tank 246 may be located on or over the rig floor, such as over rig beam 240. Bracket support member 260, such as a blank flanged spool, may support fluid container 282 from riser 268. Other types of attachment are contemplated. Fluid, such as drilling fluid, seawater, or water, may be in fluid container 282 above and below piston 284. The fluid may be in riser 268 at a sufficient fluid level to insure that there is fluid in fluid container 282 regardless of the position of piston 284. The fluid may also be in the trip tank 246 at a sufficient level to insure that there is fluid in fluid container 282 regardless of the position of piston 284.
Flow line 256 may be 10 inches (25.4 cm) in diameter, although other diameters are also contemplated. First valve 258 and/or second valve 254 may be HCR valves, although other types of valves are contemplated. Although not shown, it is contemplated that a redundant system may be attached to the left side of riser 268 similar to the system shown on the right side of the riser 216 or similar to any embodiment shown in any of the Figures. On the left side of riser 268, flow hose 264 is fluidly connected with RCD housing 272 through T-connector 262. Flow hose 264 may be in fluid communication with the rig's choke manifold, or other devices. It is also contemplated that as an alternative embodiment to
As another alternative to
The alternative fluid container may be attached with some part of the riser or its components using one or more attachment support members, similar to bracket support member 260 in
Slip Joint Piston Method
When drilling using the embodiment shown in
As the rig heaves while the drill string or tubular connection is being made, the telescoping joint 204 will telescope, and the inserted drill string or tubular DS will move in harmony with the rig. If the floating rig has a prior art drill sting or heave compensator device, it is no longer operating since the drill bit is lifted off bottom. It is otherwise turned off. When the drill string or tubular DS moves downward, the piston 224 connected by piston rod 218 to rig beam 200 will move downward a corresponding distance. The volume of fluid displaced by the downward movement of the drill string or tubular will flow through the open first valve 212 through flow line 214 into fluid container 217. Piston 224 will move a corresponding amount of fluid from the portion of fluid container 217 below piston 224 through first conduit 226 into riser 216.
When the drill string or tubular moves upward, the piston 224, which is connected with the rig beam 200, will also move a corresponding distance upward. The piston 224 will displace fluid above it in fluid container 217 through fluid line 214 into riser 216 below RCD 206. The amount of fluid displaced by piston 224 desirably corresponds with the amount of fluid displaced by the tubular. Fluid will flow from the riser 216 above the RCD 206 or annular BOP through first conduit 226 into the fluid container 217 below the piston 224. A volume adjustment member 222 may be positioned with the piston 224 to compensate for a different diameter tubular.
It is contemplated that there may be a different volume adjustment member for each tubular size, such as for different diameter drill pipe and risers. A shearing member, such as shear pin 220, allows piston rod 218 to be sheared from rig beam 200 in extreme heave conditions, such as hurricane type conditions. When the drill string or tubular connection is completed, the first valve 212 may be closed, the second valve 229 opened, the drill string DS lowered so that the drill bit is on bottom, the mud pumps turned on, and rotation of the tubular begun so drilling may resume.
It should be understood that when drilling conventionally, the embodiment shown in
When drilling using the embodiment shown in
As the rig heaves while the drill string or tubular connection is being made, the telescoping joint 280 can telescope if in the unlocked position or remains fixed if in the locked position, and, in any case, the inserted drill string or tubular DS will move in harmony with the rig. When the drill string or tubular moves downward, the piston 284 connected by piston rod 244 to rig beam 240 will move downward a corresponding distance. The volume of fluid displaced by the downward movement of the drill string or tubular DS will flow through the open first valve 258 through flow line 256 into fluid container 282. Piston 284 will move a corresponding amount of fluid from the portion of fluid container 282 below piston 284 through trip tank conduit 250 into trip tank 246.
When the drill string or tubular moves upward, the piston 284, which is connected with the rig beam 240, will also move a corresponding distance upward. The piston 284 will displace fluid above it in fluid container 282 through flow line 256 into RCD housing 272 or riser 268 below RCD 266. The amount of fluid displaced by piston 284 desirably corresponds with the amount of fluid displaced by the tubular. Fluid will move from trip tank 246 through trip tank flexible conduit 250 into fluid container 282 below piston 284. A volume adjustment member 286 may be positioned with the piston 284 to compensate for a different diameter tubular. It is contemplated that there may be a different volume adjustment member for each tubular size, such as for different diameter drill pipe and risers.
A shearing member, such as shear pin 242, allows piston rod 244 to be sheared from rig beam 240 in extreme heave conditions, such as hurricane type conditions. When the drill string or tubular connection is completed, first valve 258 may be closed, second valve 254 opened, the drill string DS lowered so that the drill bit DB is on bottom, the mud pumps turned on, and rotation of the tubular begun so drilling may resume.
It should be understood that when drilling conventionally, the embodiment shown in
For the alternative embodiment to
As will be discussed below in conjunction with
System while Drilling
Marine diverter 4 is disposed below the rig beam 2 and above RCD housing 8. RCD 10 is disposed in RCD housing 8 over annular BOP 12. The annular BOP 12 is optional. A surface ram-type BOP is also optional. There may also be a subsea ram-type BOP and/or a subsea annular BOP, which are not shown, but were discussed above and illustrated in
Method while Drilling
The methods described above for each of the embodiments shown in any of the Figures may be used with the riser 300 configuration shown in
As the rig heaves while the drill bit DB is drilling, the unlocked telescoping joint 280 of
In
As can now be understood, all embodiments shown in
Any redundancy shown in any of the Figures for one embodiment may be used in any other embodiment shown in any of the Figures. It is contemplated that different embodiments may be used together for redundancy, such as for example the system shown in
The foregoing disclosure and description of the invention are illustrative and explanatory thereof, and various changes in the details of the illustrated apparatus and system, and the construction and method of operation may be made without departing from the spirit of the invention.
