TECHNICAL BACKGROUND

[0001] This application generally relates to forming a subsea wellbore and, more particularly, to forming a subsea wellbore with a riserless drilling system.

BACKGROUND

[0002] Typically, in drilling a subsea well, a rig at the water's surface has a tubular drilling riser extending from the rig down to a blowout preventer stack (BOP) at the sea floor. A drill string extends from the rig through the interior of the riser and into the wellbore being drilled. Drilling fluid is circulated from the rig, downward through the interior of the drill string and out of the drill bit at the bottom hole assembly (BHA), and back up through the annulus between the drill string and the wall of the wellbore and between the drill string and the riser.

SUMMARY

[0003] In an example general implementation, a riserless subsea drilling system includes a tubular drilling string including a drilling bit; a rotating control device including a seal sealed to the drilling string; and a drilling fluid circuit that circulates drilling fluid from a supply line, through an annulus exterior the drilling string and below the rotating control device, through the drilling bit at a downhole end of the drilling string, and through the drilling string toward an uphole end of the drilling string.

[0004] A first aspect combinable with the general implementation further includes a mud motor coupled to the drilling bit and having a center bypass bore.

[0005] A second aspect combinable with any of the previous aspects further includes a flow control device in or upstream of the center bypass bore.

[0006] A third aspect combinable with any of the previous aspects further includes a flow control apparatus positioned in the drilling fluid circuit to control the circulation of drilling fluid.

[0007] A fourth aspect combinable with any of the previous aspects further includes a buffer chamber above the drilling bit. [0008] A fifth aspect combinable with any of the previous aspects further includes pressure sensors positioned to measure a pressure differential across the seal of the rotating control device.

[0009] In a sixth aspect combinable with any of the previous aspects, the rotating control device further includes a seawater inlet and a seawater outlet to circulate a flow of seawater across the seal.

[0010] In a seventh aspect combinable with any of the previous aspects, the rotating control device further includes an additive to circulate with the flow seawater across the seal.

[0011] In an eighth aspect combinable with any of the previous aspects, the additive includes detergent.

[0012] In a ninth aspect combinable with any of the previous aspects, the supply line extends from at or near a sea surface, through a subsea environment, to the annulus.

[0013] In a tenth aspect combinable with any of the previous aspects, the supply line fluidly connects to the annulus downhole of a blowout preventer.

[0014] In another example general implementation, a method for forming a subsea wellbore includes sealing, with a rotating control device, a portion of a tubular drilling string against a subsea environment, the tubular drilling string extending from at or near a subsea surface through the subsea environment; and circulating, from at or near the sea surface, a drilling fluid in a downhole direction through an annulus between the drilling string and a wellbore, and then in an uphole direction through the drilling string towards the sea surface.

[0015] A first aspect combinable with the general implementation further includes circulating the drilling fluid through a supply line, connected to the annulus downhole of the rotating control device, that extends through the subsea environment to the annulus.

[0016] A second aspect combinable with any of the previous aspects further includes determining density and rheological properties of the drilling fluid entering the supply line.

[0017] A third aspect combinable with any of the previous aspects further includes determining density and rheological properties of the drilling fluid returned through the drilling string.

[0018] A fourth aspect combinable with any of the previous aspects further includes determining, based on the determined densities and rheological properties, a hydrostatic pressure difference between the drilling fluid entering the supply line and the drilling fluid returned through the drilling string.

[0019] A fifth aspect combinable with any of the previous aspects further includes determining, based on the hydrostatic pressure difference, a desired setpoint drilling fluid pressure at a flow control apparatus through which the drilling fluid circulates that results in a predetermined drilling pressure at a predetermined downhole location.

[0020] A sixth aspect combinable with any of the previous aspects further includes adjusting the flow control apparatus to maintain the desired setpoint drilling fluid pressure.

[0021] A seventh aspect combinable with any of the previous aspects further includes circulating the drilling fluid through the annulus downhole to a drilling bit at an end of the drilling string, and from the drilling bit into the tubular drilling string.

[0022] An eighth aspect combinable with any of the previous aspects further includes circulating the drilling fluid through a reverse circulating mud motor.

[0023] In an example general implementation, a subsea drilling system includes a tubular drilling string that includes a drilling bit at a downhole end of the drilling string, the drilling string configured to extend through and in contact with a subsea environment; a rotating control device positioned on the drilling string above a blowout preventer stack and configured to seal a portion of the drilling string against the subsea environment; a first drilling fluid pathway including a first conduit that extends through the subsea environment and an annulus between the drilling string and a wellbore formed in a subterranean formation; a second drilling fluid pathway in fluid communication with the first drilling fluid pathway through a bottom hole assembly, the second drilling fluid pathway including the drilling string; and a circulation system configured to circulate a drilling fluid into and through the first drilling fluid pathway in a downhole direction and then through the second drilling fluid pathway in an uphole direction.

[0024] A first aspect combinable with the general implementation further includes a guide sleeve positioned around the drilling string above the rotating control device.

[0025] In a second aspect combinable with any of the previous aspects, the second drilling fluid pathway further includes a second conduit that extends from at or near the rotating control device through the subsea environment.

[0026] A third aspect combinable with any of the previous aspects further includes a flow control system configured to control a pressure of the drilling fluid. [0027] Various implementations of a subsea drilling system according to the present disclosure may include one, some, or all of the following features. For example, the subsea drilling system may allow for faster operations as a result of not having to trip the drilling riser before, during and after operations. As another example, the subsea drilling system may allow for a smaller footprint rig. As yet another example, the subsea drilling system may allow for less expensive and tangible assets to be placed in the well. Further, the subsea drilling system may utilize less intangible expenses compared to conventional deepwater wells being drilled today. As another example, smaller casing and wellbore sizes may be implemented with the subsea drilling system according to the present disclosure. The subsea drilling system could require substantially lower quantities of drilling and/or completion fluids as well as requiring substantially lower volumes of contingency well kill fluids and any other fluids that may be required during the well construction and completion operations. The drilling system could be quicker, safer and easier to move off the drilling location in cases of inclement weather, heavy seas, or other occasions requiring the drilling rig to be moved off and back on to the drilling location, as only the drill string and not the drilling riser will have to be secured prior to such moves.

[0028] The details of one or more implementations are set forth in the accompanying drawings and the description below. Other features, objects, and advantages will be apparent from the description and drawings, and from the claims.

DESCRIPTION OF DRAWINGS

[0029] FIG. 1 illustrates a schematic diagram of an example implementation of a subsea drilling system;

[0030] FIG. 2 illustrates a schematic diagram of a portion of an example implementation of a subsea drilling system that includes a flow control assembly;

[0031] FIG. 3 illustrates a schematic diagram of an example implementation of a subsea drilling system that includes a rotating control device; and

[0032] FIG. 4 illustrates an example method for forming a subsea wellbore. DETAILED DESCRIPTION

[0033] The present disclosure describes a riserless, reverse circulation drilling system and method that includes a rotating control device (RCD), or other sealing device (e.g. an annular preventer or other similar device) that prevents (all or substantially all) drilling fluid to escape from the subsea well, but otherwise allowing for drill string movement. The system and method enables managed pressure drilling (MPD), e.g., where the pressure of the drilling fluid is controlled relative to the pressure of the fluids in the subterranean zone being drilled, in certain instances, using mechanisms in addition to the hydrostatic head of the drilling fluid, and in certain instances, to be below, at and/or above the pressure in the zone. .

[0034] FIG. 1 shows an example system 100. The system includes a bit 102 and drilling bottom hole assembly (BHA) 104 at the bottom of a drilling string 106. The drilling string 106 extends from a drilling vessel 108 (e.g., fixed rig, jack-up rig, compliant-tower rig, floating production system, tension-leg platform, spar platform, or otherwise) at the water's surface 110 into a wellbore 112 being drilled. As shown in this example, the system 100 includes a casing 140 installed into a portion of the wellbore 112. The casing 140 can represent, for example, one or more of a conductor pipe, surface casing, and/or intermediate casing. In some alternative aspects, the wellbore 112 may be an open hole completion, e.g., without a casing.

[0035] The wellbore 112 extend from a sea floor 115 into one or more subterranean zones 160 that may include hydrocarbon, or other fluid, or mineral bearing geological formations. As shown in this example, a subsea environment 170 (e.g., saltwater) extends between the water surface 110 and the sea floor 115. Although described as a subsea environment with saltwater, the environment 170 may also include a mixture of fresh and saltwater or primarily fresh water.

[0036] The tubular drilling string 106 extends through the subsea environment 170 from the drilling vessel 108 through the wellbore 112. In this example, the system 100 is a riserless drilling system in that the drilling string 106 is not enclosed within a protective tubular but, instead, is exposed to the saltwater of the subsea environment 170. Alternative implementations of the system 100 may include a riser (e.g., tubular) that protects the drilling string 106 from the saltwater of the subsea environment 170.

[0037] A blowout preventer (BOP) stack 114 is provided at the top opening of the wellbore 112, at the sea floor 115. Generally, the BOP stack 114 includes one or more valves (e.g., annular preventers) that can be adjusted to control a flow of formation fluids (e.g., from the subterranean zone 160). In this example, the BOP stack 114 seals around the casing 140. The BOP stack 114 may include other components such as blind and shear rams (e.g., to cut the drilling string 106 and/or other tubing if necessary), a kill (e.g., to circulate high pressure kill fluid to the wellbore 112) and a choke (e.g., to return kill fluid to the drilling vessel 108). To accommodate such choke and kill lines and other electrical and hydraulic control lines from the surface to the BOP stack 114 (or other components of the system 100), a floating vessel (not shown) may be deployed remote from the drilling vessel 108 to prevent entanglement of the lines/umbilicals with the drilling string 106.

[0038] A rotating control device (RCD) 116 is provided at the top of the BOP stack 114.

The RCD 116 has a sealing element (alternately referred to simply as the "seal" or "element") 118 that seals to the drilling string 106 and is supported to rotate on bearings relative to an outer housing 120 affixed to BOP stack 114. In this example, the seal 118 prevents or substantially (e.g., with insignificant fluid loss) prevents a drilling fluid 150 from flowing into the subsea environment 170 during drilling or other operations.

[0039] Turning briefly to FIG. 3, a schematic of the RCD 116 is illustrated in more detail.

As shown, the RCD 116 includes pressure sensors 190 above and below the seal 118. In some aspects, the pressure sensors 190 may measure a pressure differential across the seal 118, e.g., to ensure proper operation/sealing against the drilling string 106. Further, the example implementation of the RCD 116 includes a fluid inlet 180 and a fluid outlet 182 that are adjustably open to the subsea environment 170. For example, seawater may be used for cooling and lubrication of the seal 118. The lubrication can be achieved by pumping small amounts of seawater from the top of the element 118 when the drilling string 106 is going in the hole and from the bottom on the way out of the hole. In some alternative aspects, the RCD 116 may include a self-lubrication element 184 and be closed to the subsea environment 170. Further, if additional lubrication (e.g., beyond seawater and/or an internal lubricant) is required, this may be administered through a subsea HPU fed with a line from surface 110. A suitably environmentally sensitive lubricant (such as a detergent) can be added to the seawater if necessary.

[0040] The RCD 116 may be active or passive or alternately could be in the form of an annular BOP. The element 118 in the RCD and/or the RCD clamping devices are controlled from the water's surface 110 either through a control line 136 or by use of a remote telemetry technology such as is used with pipe lines and subsea production trees and wellheads. The element 118 can be changed out either by using a remote-controlled clamp on the RCD 116 or on the element 118 within the RCD 116, and is retrieved with the BHA 104 portion of the drill string 106 on the way to surface.

[0041] The RCD 116, in some aspects, may include a pneumatic apparatus for latching a bearing assembly or other sub-assembly to the RCD body 120. The latch mechanism may be integral to the RCD body 120 and located in between a top and bottom flange connections of the body 120. It may include an annular piston and a latch dog(s) or ring. The annular piston may be actuated with a compressible fluid which may be air, nitrogen, or similar. The piston has an inner profile such that during actuation, it guides the outer face of the latch ring or dogs radially inward to the latch position. In some aspects, the piston itself has, along its upper face, collet fingers, which retract under latching pneumatic pressure, but also prevent the piston from falling under its own weight. This in turn, may prevent unintentionally unlatching the RCD body 120 while not in operation, or if pneumatic pressure is lost.

[0042] The RCD 116 may also, in some aspects, include a mechanically operated latch mechanism that locks into a mating RCD body 120 and forms a seal between an inner diameter of the RCD body 120 and an outer diameter of the latch mechanism. The latch mechanism can be transported to the RCD body 120, latched into position, managed for hydraulic locking, unlatched and transported back to the drilling vessel 108 by vertical and rotational manipulations of the drilling string 106 (e.g., solely by the string 106). In some aspects, the latch mechanism can be transported on a running tool from the drilling vessel 108 to the RCD body 120 and mechanically actuated through the running tool. The running tool may be integral to the drilling string 106 and may include collet fingers, J-Slots (e.g., a pin and guide slot used to create relative motion between two or more bodies by using the guide slot to direct the motion of the pin or vice versa), or some other device for attaching to the latch mechanism.

[0043] Blind rams and/or an annular preventer of the BOP stack 114 may be closed during the retrieval of the RCD 116 and/or RCD's sealing element 118 until it is replaced. In some implementations, a spacer section may be provided between the top of the BOP stack 114 and the RCD 116 to fully accommodate the drilling BHA 104 between the blind rams of the BOP stack 114 and the RCD 116. [0044] In some implementations, in order to relieve stress and prevent excessive wear and tear on the RCD 116, its sealing element 118, bearings and also to the BOP 114 and wellhead by the lateral movement of the drilling pipe 106 that is unconstrained from the drilling vessel 108 floor to the entry point into the RCD 116 and BOP stack 114, a guide section 172 may be positioned above the RCD 116. Limiting rotation of the drill pipe 106, e.g., by including a reverse circulating mud motor, drilling turbine in the drilling BHA 104 to provide the needed RPM to the drill bit 102, may also help relieve stress and prevent excessive wear and tear on the RCD 116.

[0045] The illustrated implementation of the subsea drilling system 100 includes a reverse circulation system. For example, the drilling fluid 150 is circulated (e.g., from a pumping system 126) from the drilling vessel 108 down a drilling fluid supply line 124 that is coupled to the outer housing 120 of the RCD 116 to flow into the annulus 142 of the wellbore 112 (between the wellbore 112 and the drilling string 106) to the drill bit 102. The drilling fluid 150 then returns, through the drill bit 102 and drilling BHA 104, up the center bore of the drilling string 106 to the drilling vessel 108. As described above, the illustrated implementation of the system 100 is riserless, in that no riser is provided around the drilling string 106 extending from the RCD 116 to the drilling vessel 108. In certain instances, the system 100 can use dual wall drill pipe for the drilling string 106, and the supply line 124 can then supply drilling fluid 150 to the annular space between the walls of the drilling string 106 and return drilling fluid up the center bore.

[0046] In some implementations, a bypass line 176 may be fluidly connected to the drilling string 106 (e.g., within the RCD 116) to provide a flow path for drilling fluid 150 to the drilling vessel 108. For example, in some implementations, to control or help control backpressure (as described more fully below), drilling fluid 150 returning to the drilling vessel 108 up through the bore of the drilling string 106 can be diverted to the bypass line 176 in order to, for instance, better control fluid pressure in the annulus 142 and/or drilling string 106.

[0047] For example, in some implementations, to accommodate well control operations and/or to use managed pressure drilling (MPD) techniques during drilling, controlled backpressure is applied to the drilling fluid 150 in the annulus 142. In example implementations that use a reverse circulation of the drilling fluid 150, the mud motor in the BHA 104 may be arranged for reverse circulation, which may transmit additional back pressure on the drilling fluid 150 in the annulus 142 when weight on the drilling bit 102 is initially applied (e.g., when changing from off-bottom to on-bottom) or as weight on the drilling bit 102 is increased, as a turbine or rotor of the mud motor may require more force to turn with increasing weight on the drilling bit 102.

[0048] To offset the additional back pressure, the differential pressure created between on- and off-bottom circulation equivalent circulating density (ECD) is correspondingly reduced. ECD, generally, a formation pore pressure gradient (e.g., of the subterranean zone 160) and a fracture pressure gradient (e.g., of the zone 160) may increase with the true vertical depth (TVD) of the wellbore 112. A density of the drilling fluid 150 (e.g., a mud weight) may be used that is greater than the pore pressure gradient, but less than the fracture pressure gradient, such that the drilling fluid 150 pressure lies between the pore pressure and the fracture pressure. In many cases, the difference between downhole pore pressure and fracture pressure is sufficient so that the equivalent circulating density (ECD) of the drilling fluid remains within the allowable density window. The ECD is the effective density exerted by the circulating drilling fluid 150 against the formation that takes into account the pressure losses in the annulus 142 above the location in the wellbore 112 being considered (e.g., at the casing shoe or otherwise). In this example reverse circulation technique, ECD comprises the static mud weight pressure at a depth location in the wellbore 112 added to the pressure losses of the return flow in the drilling string 106 between that depth and the drilling vessel 108 and then converted to density units. A typical conversion between ECD and pressure at a downhole location is:

ECD = ^22 + p

0.052TVD ·

Where ECD is in pounds per gallon (ppg), PLOSS is annular pressure loss in psi, TVD is true vertical depth in feet, and PDF is drilling fluid density (mud weight) in ppg.

[0049] Pressure reduction can be implemented with a flow control assembly, which may include one or more apparatus. For example, the flow control assembly can be or include a relief system, such as a pressure relief or pressure safety valve, placed in one of the return lines to the drilling vessel 108 that is in fluid communication with the annulus 142. As another example, the flow control assembly may be or include a nozzle placed in or immediately in front of the bore in the rotor of the mud motor. Further, a flow control assembly can be or include a constant flow regulator placed in the bore of a rotor of the mud motor. Further, the flow control assembly can be or include a choke system placed in the bore of the rotor that would allow connectivity to a Human Machine Interface (HMI) that is run in automation with a real time hydraulic control software system.

[0050] Regarding the nozzle, regulator, and choke system, and as shown in FIG. 2, these can be represented by a flow control device 128 implemented within the bore 135 of a mud motor 132 of the BHA 104. The flow control device 128, in some aspects, may controllably allow some portion of the drilling fluid 150 to return through the center bore 135 of the mud motor 132 and bypass the drive components 134, e.g., the turbine or rotor/stator gap. Thus, the fluid 150 has an alternate path to the drilling vessel 108 that does not become more difficult to flow through as weight on the drilling bit 102 increases. The flow control device 128, however, has a controlled or reduced flow area, so all of the drilling fluid 150 does not bypass the drive components 134.

[0051] As another example of a flow control assembly, a buffer chamber 130 may be placed on top of the bit 102 that would allow flow through ports in the bit 102 for injection, but not allow flow back between the annulus 142 and the bit 102. This flow back restriction could simply be a restriction to flow back with nozzles or the back pressure restrictor could actually have a chamber that would allow the cavity to be energized with fluid 150 and allow loading as weight on the drilling bit 102 increases, and relieving of the energized chamber as weight on bit is reduced.

[0052] In certain instances, to run a MPD operation in reverse circulation environment, an underbalanced drilling fluid 150 (UB fluid) could be circulated into the wellbore 112. As the UB fluid 150 is being circulated, then the flow control device 128 in the mud motor 132 could be used to apply controlled back pressure on the wellbore 112 so that the well does not experience an underbalanced state. A combination of the hydrostatic pressure of the drilling fluid 150, the ECD and the back pressure could allow the wellbore 112 to experience the planned pressure needed to successfully drill the well.

[0053] In some implementations, a continuous circulation system, a rig pump diverter, a back pressure pump, and/or trapping pressure could be used to assist in maintaining constant bottom hole pressure conditions when making a connection or tripping. For instance, with a choke in the rotor of the drilling bit 102, a choking device may still be used at the drilling vessel 108 to ensure well control in the event that gas that enters into the system. This can be incorporated into a reverse circulating swivel or downstream in the return flow line 124 back to handling tanks at the drilling vessel 108.

[0054] As another example of a flow control assembly, a plurality of spaced apart one way valves (e.g., flapper valves and/or other type of valve) can be positioned along the length of the drilling string 106 in its center bore, oriented to allow flow up the drilling string 106 toward the drilling vessel 108 and prevent backfiow of cuttings-laden fluids down the drilling string 106 toward the drill bit 102 when drilling fluid circulation is paused. The arrangement of one way valves may prevent the majority of cuttings from settling to the bottom of the drilling string 106, as they may settle no deeper than the nearest valve. The one-way valves may not need to be pressure tight and can be configured to allow some amount of downward fluid and pressure communication, for example, by having small bypass passages or holes.

[0055] Alternatively or additionally, the drilling string 106 can include a plurality of spaced apart subs having a fluid path through the sub is off-center from the center bore and having a settling chamber aligned with the center bore to catch settling cuttings. Monitoring and modeling can also be used to determine and control the maximum rate of penetration (ROP) to not overload the drill pipe 106 with cuttings and cause a blockage of the drill pipe 106.

[0056] FIG. 4 illustrates an example method 400 for forming a subsea wellbore, such as, for example, by all or part of the subsea drilling system 100. Method 400 includes step 402, which includes sealing, with an RCD, a portion of a tubular drilling string against a subsea environment. For example, in some aspects, the tubular drilling string may be extended through the subsea environment from a drilling platform or other subsea drilling location, and to a wellbore location. The RCD may sealing engage the drilling string, e.g., above a BOP stack, to fiuidly decouple a drilling fluid from the subsea environment (e.g., from seawater or other liquid). In some examples, the drilling string may not be enclosed within a riser.

[0057] Step 404 may include performing a reverse circulation drilling operation. For example, performing the reverse circulation drilling operation may include circulating, from the drilling rig, a drilling fluid through one or more circuits (e.g., conduits) that extend from the rig through the subsea environment. The drilling fluid is then circulated into an annulus between the drilling string and a formation wellbore, e.g., at a location below the RCD, below the BOP stack, or below both. The drilling fluid is circulated downhole in the annulus and through a BHA (e.g., through a reverse circulation mud motor and through a drilling bit). The drilling fluid, and bits of the formation, may leave the drilling bit and enter a bore of the drilling string. In the bore of the drilling string, the drilling fluid may be circulated uphole to the drilling rig. In some aspects, an uphole directed circuit of the drilling fluid path may include a bypass circuit, e.g., to manage or help manage a drilling fluid pressure in the annulus.

[0058] In step 406, a managed pressure drilling operation may be performed. In some aspects, the managed pressure drilling operation may include one or more sub-steps. For example, in some aspects, properties of the drilling fluid (e.g., density and/or rheological properties) may be analyzed. In some instances, the properties may be analyzed (e.g., automatically, without human intervention, or otherwise) as the drilling fluid is circulated from the drilling rig and as the drilling fluid is returned (e.g., from downhole) to the drilling rig. A difference in a hydrostatic pressure between the drilling fluid circulated from the rig and the drilling fluid returned to the drilling rig may then be determined (e.g., through a model, algorithmically, or otherwise). Based on the determined difference, a desired setpoint drilling fluid pressure may be set to achieve a particular drilling fluid pressure at a downhole location (e.g., within a particular drilling interval and/or at a particular subterranean formation).

[0059] In some aspects, the managed pressure drilling operation may include further sub- steps. For example, in order to maintain the desired setpoint of the drilling fluid pressure (e.g., at the drilling rig, a location downhole, or otherwise), a flow control apparatus may be included in the drilling system. In some aspects, the desired setpoint drilling fluid pressure may be maintained at the flow control apparatus. The flow control apparatus may include one or more of a nozzle, choke, valve, or other flow control device placed, e.g., in the drilling string, in the BHA, and/or in the drilling bit. In some aspects, the flow control apparatus may include a bypass circuit to route drilling fluid from the bore of the drilling string to the drilling rig. In further aspects, the flow control apparatus may include a flow control device at the drilling rig.

[0060] A number of embodiments of the invention have been described. Nevertheless, it will be understood that various modifications may be made. For example, telemetry communications can be implemented either via negative pulse MWD, acoustic systems, siren telemetry systems in drilling operations. Also, sea floor controls might be utilized similar to completion systems and Christmas trees. Accordingly, other embodiments are within the scope of the following claims.