WO2012140445A2

WO2012140445A2 - Subsea wellbore construction method and apparatus

Info

Publication number: WO2012140445A2
Application number: PCT/GB2012/050828
Authority: WO
Inventors: Thomas Hasler; Harald Hufthammer
Original assignee: IKM Cleandrill AS
Current assignee: IKM Cleandrill AS
Priority date: 2011-04-13
Filing date: 2012-04-13
Publication date: 2012-10-18
Anticipated expiration: 2013-10-13
Also published as: GB2509377A; GB201320056D0; WO2012140445A3; NO20110564A1; NO339484B1

Abstract

A method and system for constructing a subsea well in a subterranean formation is described. A tubular in a subsea well defines a main wellbore, and a fluid circulation path from the main wellbore to an outlet is formed via the wellbore annulus between the tubular and the subterranean formation. A cement slurry flows from the main wellbore along the wellbore annulus towards the outlet, causing fluid to be displaced from the annulus through the outlet. A controllable subsea choke in fluid communication with the fluid circulation path generates a backpressure in the fluid circulation path using the controllable subsea choke. In a preferred embodiment, the controllable subsea choke is part of a subsea pressure regulation system which also comprises a subsea pump.

Description

Subsea wellbore construction method and apparatus The present invention relates to a method and apparatus for constructing a subsea wellbore, and in particular to a method and apparatus for controlling pressure during a subsea wellbore construction operation. Particular aspects of the invention relate to a method and apparatus for controlling pressure in a wellbore during a cementing operation and/or during running of a tubular (such as casing) into a wellbore. Background to the invention The drilling and construction of wells, for example for the hydrocarbon exploration and production industry, includes many different operations which involve the pumping of fluids from surface through the wellbore and back to surface. For example, a drilling operation typically involves the rotation of a drill bit on the end of a drill string (or drill pipe), which extends from a drilling platform to a drill bit. Drilling fluid (referred to as drilling mud) is pumped from the rig down through the drill string to the drill bit to fulfil a number of different functions, including providing hydrostatic pressure to control the entry of fluids from the formation into the wellbore, lubricating the drill bit, keeping the drill bit cool during drilling, and carrying particulate materials such as drill cuttings upwards and out of the well away from the drill bit. Drilling fluid and cuttings emanating from the wellbore are carried up the annular space between the wall of the bore being drilled and the drill pipe to the mudline. In conventional subsea drilling, a riser is installed above a blow-out preventer (BOP) stack on top of the wellhead, and extends to the surface. Drilling fluid and cuttings are returned to the rig for processing, re-use, storage, removal and/or treatment through the annulus between the drill pipe and the riser. Riserless drilling systems are also used in some subsea applications, for example when drilling the uppermost section of the wellbore, which is referred to as the "tophole". When the tophole section is drilled, there is no riser pipe installed between the seabed and the drilling rig, and as there is no conduit to return drilling fluids from the wellbore back to the surface, the drilling mud and cuttings may be discharged to the subsea environment. Other riserless drilling systems, such as that described in US 4,149,603 [1 ], use a riserless mud return system including a hose, separate from the drill string, to carry mud to the surface. A pumping means is used to pump mud through the hose back to surface, with the pump operated in dependence on the detected level of mud and cuttings supported within a mud sump. A typical wellbore completion contains multiple intervals of casing placed within and cemented in the previous casing run, including a conductor casing, a surface casing, an intermediate casing and a production casing and liner. When the cementing operations are carried out subsequent to the installation of the BOP stack and the riser, a cement slurry is pumped down the drill string from surface. The cement is diverted at the required depth through a cement plug into the annular space between the tubular and an outer wall (e.g. the openhole or a larger casing), and fills the annular space from the bottom upwards. Fluid displaced from the annulus is returned to surface via the riser. The cement is allowed to set to seal the annulus and secure the casing. Circulating a cement slurry through the wellbore annulus during a cementing operation requires an appreciation of the pressures in the geologic formation. Particular difficulties can arise when the casing interval penetrates one or more abnormal pressure zones, through which the cement must be circulated (formation fluid pressure is considered to be "normal" if it is 4,650 psi at 10,000 ft depth). An over-pressured formation zone has a pressure in excess of the normal pressure, and contains fluids, including water and liquid or gaseous hydrocarbons, at a high pressure which tend to leave the formation and enter the annulus. This in-flux of formation fluids into the wellbore annulus can have serious implications for the quality of the cement job. In contrast, an under-pressured formation zone has a formation pressure lower than the normal formation pressure. Cement circulating in such zones has a tendency to flow out of annulus and into the formation. This can cause substantial losses of cement volume into the formation. Control of in-flux and lost circulation is achieved by controlling the pressure in the annulus; a high enough pressure restricts in-flux when circulating through an over-pressured zone, and a low enough pressure reduces lost-circulation through an under-pressured zone. It is known to control the annulus pressure by appropriate selection of fluid density or "weight" (including the cement itself and the fluids circulated ahead of the cement volume), as well as fluid rheology and circulating friction. However, such methods have limitations, particularly where formations have narrow pressure windows between fracturing pressure and pore pressure. More recently, it has been proposed to control flow rate during cementing of onshore wells by control of backpressure as the fluids exit from a diverter above the BOP stack (Montilva et al. 2010 [4]; Beltran et al. 2010 [3]). A similar approach has been used in an offshore well with a surface wellhead (Eck-Olsen et al. 2005 [2]). All of these approaches use techniques which have analogies to Managed Pressure Drilling, and while useful for providing pressure control in some applications, do not have general application for cementing operations. In particular, the systems described are only suitable for surface use. The described applications are all concerned with cementing intermediate and lower casing intervals after the BOP stack has been installed. In subsea applications, Hinton 2009 [3] describes the use of a subsea pump (in a system similar to that described in US 4,149,603 [1 ]) to reduce bottom hole pressure during a drilling operation by pumping heavy mud up a mud return line to surface to lower the level of mud (and thus the hydrostatic pressure) in the marine riser. The paper also suggests that the same approach can be used in cementing operations. However, Hinton 2009 is only suitable for drilling and cementing after the BOP stack and the marine riser has been installed, and therefore does not have application to cementing a conductor casing or surface casing. WO201 1 /036144 [6] describes a Managed Pressure Drilling (MPD) control process in which a fluid is pumped down a drill pipe and returned via the annulus between the drill pipe and the wellbore wall. A set pressure is defined, and a desired extraction flow rate of the fluid in the annulus is determined according to the set pressure and a pumping flow rate. The extraction path from the annulus is configured by use of a backpressure pump and a choke at surface. WO201 1/036144 does not have application to cementing a conductor casing or surface casing. There is generally a need for a method and apparatus which addresses one or more of the problems identified above. It is amongst the aims and objects of the invention to provide a method and/or apparatus for controlling pressure during a wellbore construction operation, and which obviates or mitigates one or more drawbacks or disadvantages of the prior art. In particular, one aim of an aspect of the invention is to provide a method and/or apparatus for controlling pressure which is suitable for a range of cementing operations, including cementing of tubulars prior to the installation of a BOP stack and/or marine riser. Summary of the invention According to a first aspect of the invention, there is provided a method of constructing a subsea well in a subterranean formation, the method comprising:

providing a tubular in a subsea well, the tubular defining a main wellbore;

providing a fluid circulation path from the main wellbore to an outlet, via a wellbore annulus formed between the tubular and the subterranean formation;

causing a cement slurry to flow from the main wellbore of the subsea well and along the wellbore annulus towards the outlet, thereby causing fluid to be displaced from the annulus through the outlet;

providing a controllable subsea choke in fluid communication with the fluid circulation path; and

generating a backpressure in the fluid circulation path using the controllable subsea choke. The method may also include the step of providing a subsea pump in fluid communication with the fluid circulation path, and may comprise reducing the pressure in the fluid circulation path using the subsea pump. The controllable subsea choke and/or subsea pump may form part of a subsea pressure regulation system. By "subsea pressure regulation system" is meant a pressure regulation system which is located subsea. Preferably the subsea pressure regulation system is located proximal to the outlet to be responsive to conditions detected or sensed at the outlet and provide rapid and/or accurate pressure regulation. This is major advantage of the present invention; by providing a pressure regulation system subsea, the delays associated with monitoring fluid conditions at surface are avoided. Preferably, the tubular is comprises a casing, which may be a conductor casing or a surface casing. The wellbore annulus may therefore be formed between a casing and the subterranean formation. Thus the wellbore annulus of this aspect of the invention is a cementing annulus. Preferably the method comprises regulating the pressure in the fluid circulation path in a range from a first pressure to a second pressure, wherein the first pressure is below the hydrostatic pressure at the outlet, and the second pressure is above the hydrostatic pressure at the outlet. The method may comprise: measuring pressure at the outlet; outputting a pressure measurement signal to a control module; and generating a control signal for the controllable subsea choke in response to the pressure measurement signal. The method may comprise: measuring a flow rate of fluid displaced from the annulus; outputting a flow rate measurement signal to a control module; and generating a control signal for the controllable subsea choke in response to the flow rate measurement signal. The tubular may comprise a casing, and may comprise a surface casing interval or a conductor casing interval. The wellbore annulus may therefore be formed between a casing and the subterranean formation. The method may therefore comprise a method of constructing a tophole section of a subsea well, before the installation of a wellhead and a blowout preventer stack. Thus the method may be performed in the absence of a riser extending from the subsea well to surface, and therefore in the absence of a conventional annular return path for wellbore fluids. The tubular may comprise a conductor casing. Therefore an embodiment of the invention may be a method of cementing a conductor casing in a subterranean formation. In such an embodiment, the method may comprise providing a conductor casing support. The conductor casing support may be a spud base or seabed penetrating skirt which is coupled to the conductor, and which may penetrate the seabed. Preferably, the method comprises regulating the pressure at cement ports located in the tubular. In one embodiment, the method comprises: providing a conductor casing support which is coupled to a casing conductor and which penetrates the seabed; and cementing the conductor casing in a subterranean formation while regulating the pressure in a volume defined by the conductor casing, the conductor casing support, and the seabed. In another embodiment, the method comprises: providing a surface casing interval in a wellbore; cementing the surface casing in the wellbore while regulating the pressure at cement ports of the surface casing interval. The method may comprise the step of transporting fluid displaced from the annulus to a remote location via a conduit. The conduit may be a return line, and the method may comprise returning fluid displaced from the annulus to surface. Where a return line is present, the provision of a choke for generating a back pressure in the fluid circulation path has advantages over a solution which simply supports a column of fluid (such as drilling mud) in the return line. In such an approach, a pump failure would expose the subsea well to the hydrostatic pressure due to the entire weight of the supported fluid column, which could damage the formation and the cement job. In addition, a pump-only arrangement would have an upper limit to the back pressure generated, dependent on the height of the column and the weight of the supported fluid. Generating a back pressure by a

controllable subsea choke provides a wider pressure management range and a more rapid pressure control, and therefore provides greater control over parameters of the cementing operation (including choice of fluids). Use of a choke also negates the requirement for a return line, which is a further advantage over a cementing method which uses a subsea pump and return line to control back pressure. It will be appreciated that in many low or zero discharge well construction operations it will be desirable to include a return line to prevent discharge of fluids to the subsea environment. The method may comprise flowing seawater into a fluid conduit connected to the outlet. This may be performed to flush or clean a fluid conduit, the outlet (which may be cement ports) and/or the upper part of the annulus. Alternatively, or in addition, seawater may be flowed into a fluid conduit to dilute fluid (e.g. cement) displaced from the annulus in an outlet conduit or transport or return conduit. According to a second aspect of the invention, there is provided a system for constructing a subsea well in a subterranean formation, the system comprising:

a tubular in a subsea well defining a main wellbore and defining a fluid circulation path from the main wellbore to an outlet, via a wellbore annulus formed between the tubular and the subterranean formation; and

a controllable subsea choke operable to generate a backpressure in the fluid circulation path. Preferably, the controllable subsea choke is operable to generate a backpressure in the fluid circulation path at cement ports located in the tubular. The system may further comprise a subsea pump in fluid communication with the fluid circulation path, operable to reduce the pressure in the fluid circulation path. Preferably, the system comprises at least one instrument for monitoring a condition in the fluid circulation path, which may output a measurement signal to a control module. The control module may be located at surface, or may be located subsea. The condition may be selected from the group comprising: acidity (pH); density; conductivity; pressure; flow rate; and temperature. The system may comprise a pressure sensor which outputs a pressure measurement signal to a control module and/or may comprise a flow meter operable to measure a flow rate of fluid displaced from the annulus and provide a flow measurement signal to a control module. Preferably, the control module generates a control signal for regulating the pressure at the outlet in response to a received measurement signal. Preferably, the control module generates a control signal for the subsea choke. Where the subsea pressure regulation system comprises a subsea pump, the control module may provide a control signal for the subsea pump. By providing instruments capable of measuring fluid characteristics, information on the progress of the cementing operation may be provided in real time to the control module. For example, the presence of drilling fluid in the fluid circulation path may be detected by a measurement (or combination of measurements) from the instruments. A changing characteristic of the fluid (e.g. indicative of a change from drilling fluid to cement) may be detected by a measurement (or combination of measurements) from the instruments. These data may be used as inputs to the control module, and control signals for the choke and/or pump may be generated in response to the measurements. The tubular may be a surface casing interval or a conductor casing. The system may comprise a conduit for transporting fluid displaced from the annulus to a remote location, which may be a return line to surface. The system may therefore comprise a system for constructing a tophole section of a subsea well, before the installation of a wellhead and a blowout preventer stack. Thus the system may be used in the absence of a riser extending from the subsea well to surface, and therefore in the absence of a conventional annular return path for wellbore fluids. The system may further comprise a fluid inlet connected to the outlet, which may be a choked inlet. This may be operable to flush or clean a fluid conduit, the outlet (which may be cement ports) and/or the upper part of the annulus. Alternatively, or in addition, the inlet may be operable to allow seawater to be flowed into a fluid conduit to dilute fluid (e.g. cement) displaced from the annulus in an outlet conduit or transport or return conduit. Embodiments of the second aspect of the invention may include one or more features of the first aspect of the invention or its embodiments, or vice versa. According to a third aspect of the invention, there is provided a system for constructing a subsea well in a subterranean formation, the system comprising:

a tubular in a subsea well defining a main wellbore and defining a fluid circulation path from the main wellbore to an outlet, via a wellbore annulus formed between the tubular and the subterranean formation;

a controllable subsea choke operable to generate a backpressure in the fluid circulation path; and a subsea pump operable to lower the pressure in the fluid circulation path. Preferably, the controllable subsea choke and subsea pump are operable to regulate the pressure at cement ports located in the tubular. The system may comprise a system for constructing a tophole section of a subsea well, before the installation of a wellhead and a blowout preventer stack. Thus the system may be used in the absence of a riser extending from the subsea well to surface, and therefore in the absence of a conventional annular return path for wellbore fluids. Embodiments of the third aspect of the invention may include one or more features of the first or second aspects of the invention or its embodiments, or vice versa. According a fourth aspect of the invention there is provided a method of performing an operation in a subsea well, the method comprising:

providing a fluid circulation path from a first region of the subsea well to a second region of the subsea well;

causing wellbore fluid to flow from the first region to the second region;

regulating the pressure using a subsea pressure regulation system;

wherein the subsea pressure regulation system comprises means for creating a backpressure in the fluid circulation path, and means for lowering the pressure in the fluid circulation path. Preferably, the method includes the step of running a tubular into or removing a tubular from the wellbore. Fluid displacement caused by these operations creates an increase or decrease in the wellbore pressure, and the method may include creating a back pressure or lowering the pressure in the fluid circulation path to compensate for the change in pressure. Embodiments of the fourth aspect of the invention may include one or more features of any of the first to third aspects of the invention or its embodiments, or vice versa. According a fifth aspect of the invention there is provided a method of performing an operation in a subsea well, the method comprising: providing a fluid circulation path from a first region of the subsea well to a second region of the subsea well;

running a tubular into or removing a tubular from the wellbore, thereby causing wellbore fluid to flow from the first region to the second region;

regulating the pressure using a subsea pressure regulation system;

wherein the subsea pressure regulation system comprises means for creating a backpressure in the fluid circulation path, and means for lowering the pressure in the fluid circulation path. Embodiments of the fifth aspect of the invention may include one or more features of any of the first to fourth aspects of the invention or its embodiments, or vice versa. Brief description of the drawings There will now be described, by way of example only, various embodiments of the invention with reference to the drawings, of which: Figure 1 is a sectional schematic view of a wellbore construction system according to an embodiment of the invention, applied to the cementing of a conductor casing; Figure 2 is a sectional schematic view of a wellbore construction system according to an alternative embodiment of the invention, applied to the cementing of a surface casing; Figure 3 is a sectional schematic view of a wellbore construction system according to a further embodiment of the invention, applied to the cementing of a surface casing; Figure 4 is a sectional schematic view of a wellbore construction method according to a further embodiment of the invention, including a drilling fluid return system and a managed pressure cementing system. Detailed description of the preferred embodiments Referring firstly to Figure 1 , there is shown a wellbore construction system shown generally at 100, for a subsea hydrocarbon well 102 in a subterranean formation 104. The Figure shows the cementing of a conductor casing 106 to a depth d, inside a predrilled hole 108. At this stage of well construction, the high pressure wellhead has not been installed and therefore there is no riser extending to surface from the well 102. The system 100 is shown with the drill string 120 extending from the drilling rig to a cement plug 122 at depth d. The system comprises a seabed penetrating skirt 128, which surrounds the conductor casing 106 and supports it in the hole. The borehole wall 124 and the conductor 106 define an annular space 126. The system 100 therefore comprises a fluid circulation path from a main bore of the well 102 to the volume 129 defined between the seabed penetrating skirt 128, the conductor 106 and the seabed 105. An outlet 130 from the volume 129 is connected to a fluid conduit 133, which is connected to a subsea pressure regulation system 134. The subsea pressure regulation system 34 is located subsea, and preferably in proximity to the well 102 at the seabed 105. The subsea pressure regulation system 134 comprises a subsea controllable variable choke 142. In this embodiment the system also comprises a fluid discharge line 144, which discharges fluid to the ocean. The subsea pressure regulation system 34 is designed to be controlled from surface by control interface 146 to manage the pressure at the outlet 130 (and therefore in the annulus 126). The control interface 146 may be cabled back to surface, or may be coupled to a control module via an ROV which in turn is connected to surface via an umbilical. Alternatively, the control interface may use acoustic signal with a subsea accumulator or battery pack. Although the control module of this embodiment is at surface, a control module may be located in the subsea environment in alternative arrangements. During cementing of the conductor casing, the cementing engineer at surface pumps a cement slurry 121 down the drill pipe to the casing shoe 22, where the cement is diverted out of the main bore defined by the casing 16 and into the annular space defined by the formation 14 and the casing 16. Cement 21 passes up through the annulus 26 and displaces fluid from the annulus 126 and into the volume 129. The spud base 128 controls the flow regime of the displaced fluid and assists in retaining the integrity of the formation 104 at the seabed 105 and reduces the washout and/or inward collapse of the formation in the vicinity of the hole 108. Conventionally, pressure control in the annulus is by appropriate selection of cement density or "weight" as well as cement rheology and circulating friction. However, the system 100 provides a controllable subsea choke 142 which provides additional pressure control by enabling a controllable backpressure to the fluid circulation system to be generated. This allows the cementing engineer to increase the pressure in the annulus by increasing the choking of the flow, thereby generating a pressure greater than the hydrostatic pressure due to the weight of the seawater. This increase in pressure, which is not dependent on cement characteristics, may assist in maintaining the integrity of the formation and the success of the cementing operation. The system provides greater flexibility in the choice of other cementing parameters, including selection of fluid weight (including the cement itself and the fluids circulated ahead of the cement volume), as well as fluid rheology and circulating friction. Referring now Figure 2, there is shown a wellbore construction system shown generally at 200, for a subsea hydrocarbon well 202 in a subterranean formation 204. The system is similar to the system 100, and will be understood from Figure 1 and the accompanying text. However, the system 200 is applied to the cementing of a surface casing interval 216 to a casing depth D, inside the wellbore 102. The surface casing 206 extends through and is supported by a preinstalled and cemented conductor casing 106. At this stage of well construction, the BOP has not been installed and there is no riser extending to surface from the well 102. The system 200 is shown with the drill string 220 extending from the drilling rig to a cement plug 222 at depth D. The borehole wall 224 and the casing 206 define an annular space 226, and cement ports 228 above the mud line provide an outlet 230 to the annulus 226. The system 200 therefore comprises a fluid circulation path from a main bore of the well 102 to the outside of the well, via the outlet 230. The outlet 230 is connected to a fluid conduit 233, which is connected to a subsea pressure regulation system 234. The subsea pressure regulation system is similar to the system 134 and is located subsea. In this example, the system 234 is located on the seabed, but it may be positioned higher up in the water column in alternative

arrangements. The subsea pressure regulation system 234 comprises a subsea controllable variable choke 242, a subsea pump 236, a flow meter 238, a pressure sensor 240 and additional instrumentation 243. The system also comprises a fluid discharge line 244, which discharges circulated fluid to the ocean. The subsea pressure regulation system 234 is controlled from surface via the two-way control interface 246 (although in an alternative arrangement a control module may be located subsea). During cementing of the surface casing, the cementing engineer at surface pumps a cement slurry 221 down the drill pipe to the cement plug 222, where the cement is diverted out of the main bore defined by the casing 206 and into the annular space 226 defined by the formation 104 and the casing 206. Cement 221 passes up through the annulus 226 and displaces fluid from the annulus through the cement ports 228 and outlet 230. Control of in-flux to the annulus 226 and lost circulation is achieved by controlling the pressure in the annulus 226: a high enough pressure restricts in-flux when circulating through an over- pressured zone; and a low enough pressure reduces lost-circulation through an under- pressured zone. Conventionally this would be performed by appropriate selection of fluid density or "weight" (including the cement itself and the fluids circulated ahead of the cement volume), as well as fluid rheology and circulating friction. However, the

controllable subsea choke 242 of the invention provides additional pressure control by enabling a controllable backpressure to the fluid circulation system to be generated. This allows the cementing engineer to increase the pressure in the annulus by increasing the choking of the flow, thereby generating a pressure greater than the hydrostatic pressure due to the weight of the seawater and/or drilling fluids. This allows, for example, a greater pressure resistance to in-flux from over-pressured formation zones penetrated by the casing interval without changing the fluid characteristics. Alternatively, or in addition, the system allows a greater flexibility in the choice of other cementing parameters, including selection of fluid weight (including the cement itself and the fluids circulated ahead of the cement volume), as well as fluid rheology and circulating friction. The inclusion of a pump 236 in enables the pressure at the outlet 230 to be reduced, below the hydrostatic pressure at the outlet. This has the effect of reducing the pressure in the annulus 226, and enables control of the fluid and cement losses during the cementing operation. By providing a subsea pressure regulation system including a subsea choke 242 and a subsea pump 236, the system 200 provides considerable variation and control of the pressure in the annular space 226 between the casing being cemented and an outer wall (in this case the wall of the open hole). The subsea choke 242 allows the back pressure to the fluid circulation system to be increased to magnitude above the hydrostatic pressure, without reliance on a fluid return line or other fluid columns supported in the drilling system. The provision of a pump 236 allows the pressure in the annular space 226 between the casing and the formation to be reduced below the hydrostatic pressure due to the water column. This provides a significant amount of flexibility in selecting other parameters at the cementing operation, including fluid characteristics, wellbore geometry, and flow rates. In use, the pressure sensor 240 continuously monitors the pressure at the outlets 230 and provides a signal to a control module (not shown) which is located at surface and connected to the subsea pressure regulation system 234 via the interface 246. In response to the pressure signal, the control module actuates the subsea choke 242 and/or the subsea pump 236 to manage the pressure in the annular space 226 during different phases of the cementing operation. (It will be appreciated that the system 100 of Figure 1 may also comprise a pressure sensor for performing the same or similar functions). Numerous modes of operation are possible within the scope of the invention. In one example, an initial phase of the cementing operation is carried out with the pump 236 operating to create a negative pressure (with respect to the hydrostatic pressure at the depth of the outlet). This has the effect of encouraging upward flow of the cement 221 in the annular space 226, and reduces the cement losses into the formation in under pressured formation zones. During a second phase of the cementing operation, the pump rate can be reduced (reducing the magnitude of the negative pressure) and the back pressure on the cement ports 238 increased by choking the flow via the choke 242. The flow meter measures the flow rate of fluid exiting the annular space 226. This flow rate may be compared to the flow rate of cement being pumped from the surface. The comparison of these two flow rates provides the cementing engineer with the information whether influx of fluid or gas from the formation into the annulus is occurring, and whether cement or other fluids are being lost from the annulus into the formation. This information is used to determine the pressure generated at the outlet by the regulation system 234. Figure 3 shows alternative system, generally depicted at 300, which is similar to the system 200, and will be understood from Figure 2 and the accompanying text. However, the system 300 differs in that it also comprises a fluid inlet 302 to the cement ports, which is provided with an inlet choke 304. This enables seawater to be flushed through the upper part of the annulus 226. This may be undertaken to clean cement out of the upper part of the annulus and the cement ports, which may be advantageous for subsequent operations utilising the cement ports. This is particularly useful for template drilling applications where the cement ports are used during cementing of the next casing section. The system 300 also differs in the configuration of the subsea pressure regulation system 334. In the system 334, the choke 342 is disposed in the fluid conduit 333 between the outlet 330 and the pump 336, rather than being located on the downstream (in the context of the flow circulation path from the main wellbore to the annulus) side of the pump 336. The system also provides an inlet line 348 with a secondary inlet choke 350 connected to the fluid conduit 333 between outlet 330 and the pump 336. The inlet 348 allows seawater into the system, which may be advantageous if the pump is pumping cement, to dilute the cement and reduce its viscosity and keep it moving in the system. It allows enables cleaning of the system). The choke 350 allows this in-flow of water during the managed pressure cementing operation: by controlling both chokes 350 and 342 it is possible to control the pressure at the outlet 330 even when flushing seawater through the pump 336. Figure 4 is a schematic view of a further alternative embodiment of the invention, configured as part of a zero discharge well construction system 400. The system 400 is similar to the systems 200 and 300, and will be understood from Figure 2 and 3 and the accompanying text. The drawing shows the system prior to cementing of a surface casing interval 206. The system 400 includes a subsea pressure regulation system 434

(described in more detail below) and also includes a drilling fluid return system shown generally at 410. This embodiment makes efficient use of subsea components to provide drilling return management, and pressure management of a subsequent cementing operation. The drilling fluid return system 410, is similar configuration to that disclosed in

US 4,149,603 [1 ], and includes a body 412 defining a volume for collecting drilling fluid returns. An outlet 414 to the body is connected to a flow line 416 which in turn is connected to an inlet of a four-way valve 418 of the system 434. An outlet of the four-way valve 418 is connected to the subsea pump 436 of the subsea pressure regulation system 434. In use, a tophole section of the well 102 is drilled without a riser, with the drilling fluid and entrained cuttings circulated conventionally from the bottomhole assembly upwards in the annular space between the drill pipe and the hole being drilled. The drilling fluid passes upwards in the wellbore and into the body 412. The drilling fluid and drill cuttings are then pumped from the body 412, and through a cuttings breaker or crusher 419 in the flow path 416, to ensure that all materials including entrained solids are sufficiently small to be passed through the subsea pump and choke. The drilling fluid and cuttings are

transported back to surface through return hose 420 for treatment and/or recirculation. The pump 436 is operated in dependence on the detected level of drilling fluid and cuttings supported within the body 412. In a subsequent cementing operation, a cement slurry (not shown) is pumped down the drill pipe to the cement plug 422, where the cement is diverted out of the main bore defined by the casing 206 and into the annular space 426. Cement displaces fluid from the annulus through the cement ports 428 and into a manifold 429. The system 400 also includes a fluid inlet 437 to the manifold 429 including a shuttle valve 439. The fluid inlet allows the manifold to be flushed out with seawater if required. An outlet 430 to the manifold is connected to the subsea pressure regulation system 434 via the four-way valve 418 and flow conduit 433. Depending on the actuation of the four-way valves 418 and 435, the fluid displaced from the annulus can be in fluid communication with the pump 436, the choke 442, or both, for providing management of the pressure at the outlet 430 and the annulus 426 in the manner described with reference to the previous embodiments. In different modes of operation, the fluid path can be switched through different flow lines in the system 434. In this embodiment, the choke 442 is located in a secondary fluid return line 444 from the outlet of the fluid circulation path to a remote fluid returns treatment facility (which may be a surface). However, the system does not rely on the control of the level of drilling fluid in the fluid return line in order to control back pressure; this is achieved by the use of the choke. It will be appreciated that although two parallel return lines 420 and 444 are shown in Figure 4, an alternative embodiment provides a single return line for the mud returns during the drilling operation and the displaced fluid during cementing. The above-described embodiments provide advantages in cementing phases of wellbore construction. However, the invention has other applications to the control of pressure in annular space in a wellbore. For example, when running a surface casing interval into a subsea wellbore, prior to the installation of a BOP stack and marine riser, the resulting fluid displacement causes a pressure increase in the wellbore, which is dependent on the speed at which the tubing string is run-in. The increase in pressure may be significant enough to cause damage to weak formation zones, compromising the integrity of the well and/or efficiency of production. Similarly, rapid withdrawal of a tubular (such as a drill string) from the uncased hole may cause a pressure drop which cause the hole to collapse inwardly. The invention provides a method and system for constructing a subsea well in a subterranean formation is described. A tubular in a subsea well defines a main wellbore, and a fluid circulation path from the main wellbore to an outlet is formed via the wellbore annulus between the tubular and the subterranean formation. A cement slurry flows from the main wellbore along the wellbore annulus towards the outlet, causing fluid to be displaced from the annulus through the outlet. A controllable subsea choke in fluid communication with the fluid circulation path generates a backpressure in the fluid circulation path using the controllable subsea choke. In a preferred embodiment, the controllable subsea choke is part of a subsea pressure regulation system which also comprises a subsea pump. Variations to the above-described embodiments are within the scope of the invention. In particular, it will be apparent to one skilled in the art that different configurations of the subsea pressure regulation system, including the location of chokes, pumps, and connecting valves may be modified within the scope of the invention. Furthermore, features of the described embodiments are compatible with other embodiments of the invention.

References [1 ] US 4,149,603 [2] SPE/IADC 92568; "Managing Pressures During Underbalanced Cementing by Choking the Return Flow, Innovative Design and Operational Modelling as Well as Operational Lessons"; Johan Eck-Olsen, SPE; Per-Johan Pettersen and Arnfinn Ronneberg, Statoil ASA; Knut S Bjorkevoll and Rolv Rommetveit SPE, SINTEF Petroleum Research; SPE/IADC Drilling Conference, 23-25 February 2005. [3] lADC/SPE 122201 ; "A New Chapter in MPD: Subsea Pumping"; Andy Hinton SPE, AGR Drilling Services; lADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, 12-13 February 2009. [4] lADC/SPE 128923; "New Automated Control System Manages Pressure and

Return Flow While Drilling and Cementing Casing in Depleted Onshore Field"; Julio Montilva, Shell Exploration & Production Company; Paul Fredericks and Ossama Sehsah, At Balance; lADC/SPE Drilling Conference Centre Exhibition, 2-4

February 2010. [5] SPE/IADC 130313; "Managed Pressure Drilling Brings Added Value to Production Casings Cementing Operations Increasing Success Rates and Quality in HPHT Fractured Narrow Window Wells"; Juan Carlos Beltran SPE, Corrado Lupo SPE, Fernando Gallo SPE, Hermogenes Duno SPE, and Leiro Medina SPE,

Schlumberger; SPE/IADC Managed Pressure Drilling and Underbalanced

Operations Conference and Exhibition, 24-25 February 2010. [6] WO201 1 /036144 A1

Claims

Claims: 1 . A method of constructing a subsea well in a subterranean formation, the method comprising:

providing a tubular in a subsea well, the tubular defining a main wellbore;

generating a backpressure in the fluid circulation path using the controllable subsea choke.

2. The method as claimed in claim 1 comprising providing a subsea pump in fluid

communication with the fluid circulation path, and reducing the pressure in the fluid circulation path using the subsea pump.

3. The method as claimed in claim 1 or claim 2 comprising regulating the pressure in the fluid circulation path in a range from a first pressure to a second pressure, wherein the first pressure is below the hydrostatic pressure at the outlet, and the second pressure is above the hydrostatic pressure at the outlet.

4. The method as claimed in any preceding claim wherein the tubular comprises a casing.

5. The method as claimed in claim 4 wherein the tubular comprises a surface casing interval or a conductor casing interval.

6. The method as claimed in any preceding claim comprising:

measuring pressure at the outlet;

outputting a pressure measurement signal to a control module; and

generating a control signal for the controllable subsea choke in response to the pressure measurement signal.

7. The method as claimed in any preceding claim comprising:

measuring a flow rate of fluid displaced from the annulus;

outputting a flow rate measurement signal to a control module; and

generating a control signal for the controllable subsea choke in response to the flow rate measurement signal.

8. The method as claimed in any preceding claim comprising constructing a tophole section of a subsea well, before the installation of a wellhead and a blowout preventer stack.

9. The method as claimed in any preceding claim comprising:

providing a conductor casing support which is coupled to a casing conductor and which penetrates the seabed;

cementing the conductor casing in a subterranean formation while regulating the pressure in a volume defined by the conductor casing, the conductor casing support, and the seabed.

10. The method as claimed in claim any preceding claim comprising:

providing a surface casing interval in a wellbore; and

cementing the surface casing in the wellbore while regulating the pressure at cement ports of the surface casing interval.

1 1 . The method as claimed in any preceding claim comprising transporting fluid

displaced from the annulus to a location from the outlet via a conduit.

12. The method as claimed in any preceding claim comprising flowing seawater into a fluid conduit connected to the outlet.

13. A system for constructing a subsea well in a subterranean formation, the system comprising:

a tubular in a subsea well defining a main wellbore and defining a fluid circulation path from the main wellbore to an outlet, via a wellbore annulus formed between the tubular and the subterranean formation; and a controllable subsea choke operable to generate a backpressure in the fluid circulation path.

14. The system as claimed in claim 13 further comprising a subsea pump in fluid

communication with the fluid circulation path, operable to reduce the pressure in the fluid circulation path.

15. The system as claimed in claim 13 or claim 14, comprising at least one instrument for monitoring a condition in the fluid circulation path and outputting a measurement signal to a control module.

16. The system as claimed in any of claims 13 to 15, wherein the tubular is a surface casing interval or a conductor casing.

17. The system as claimed in any of claims 13 to 16, comprising a conduit for

transporting fluid displaced from the annulus to a remote location.

18. The system as claimed in any of claims 13 to 17, comprising a fluid inlet in fluid communication with the outlet.

19. A method of performing an operation in a subsea well, the method comprising: providing a fluid circulation path from a first region of the subsea well to a second region of the subsea well;

causing wellbore fluid to flow from the first region to the second region;

regulating the pressure using a subsea pressure regulation system;

wherein the subsea pressure regulation system comprises means for creating a backpressure in the fluid circulation path, and means for lowering the pressure in the fluid circulation path.

20. The method as claimed in claim 19 comprising:

running a tubular into or removing a tubular from the wellbore; and

generating a back pressure or lowering the pressure in the fluid circulation path to compensate for a change in pressure induced by running or removing the tubular.