WO2012140445A2 - Procédé et appareil de construction de puits sous-marin - Google Patents

Procédé et appareil de construction de puits sous-marin Download PDF

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Publication number
WO2012140445A2
WO2012140445A2 PCT/GB2012/050828 GB2012050828W WO2012140445A2 WO 2012140445 A2 WO2012140445 A2 WO 2012140445A2 GB 2012050828 W GB2012050828 W GB 2012050828W WO 2012140445 A2 WO2012140445 A2 WO 2012140445A2
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WO
WIPO (PCT)
Prior art keywords
pressure
subsea
fluid
circulation path
wellbore
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PCT/GB2012/050828
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English (en)
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WO2012140445A3 (fr
Inventor
Thomas Hasler
Harald Hufthammer
Original Assignee
Ikm Cleandrill As
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Application filed by Ikm Cleandrill As filed Critical Ikm Cleandrill As
Priority to GB1320056.3A priority Critical patent/GB2509377A/en
Publication of WO2012140445A2 publication Critical patent/WO2012140445A2/fr
Publication of WO2012140445A3 publication Critical patent/WO2012140445A3/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • E21B33/14—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes
    • E21B33/143—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes for underwater installations
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/02—Valve arrangements for boreholes or wells in well heads
    • E21B34/025—Chokes or valves in wellheads and sub-sea wellheads for variably regulating fluid flow
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/02—Subsoil filtering
    • E21B43/10—Setting of casings, screens, liners or the like in wells
    • E21B43/101—Setting of casings, screens, liners or the like in wells for underwater installations

Definitions

  • Subsea wellbore construction method and apparatus 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.
  • 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.
  • a riser 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.
  • BOP blow-out preventer
  • 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".
  • 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.
  • riserless drilling systems such as that described in US 4,149,603 [1 ]
  • 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.
  • 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.
  • 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.
  • fluid density or weight including the cement itself and the fluids circulated ahead of the cement volume
  • 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.
  • 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.
  • 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.
  • tubular in a subsea well the tubular defining a main wellbore
  • 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.
  • subsea pressure regulation system is meant a pressure regulation system which is located subsea.
  • 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.
  • 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.
  • the wellbore annulus of this aspect of the invention is a cementing annulus.
  • 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.
  • 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.
  • 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.
  • the method comprises regulating the pressure at cement ports located in the tubular.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • dilute fluid e.g. cement
  • 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;
  • controllable subsea choke operable to generate a backpressure in the fluid circulation path.
  • 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.
  • 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.
  • the control module generates a control signal for regulating the pressure at the outlet in response to a received measurement signal.
  • the control module generates a control signal for the subsea choke.
  • the control module may provide a control signal for the subsea pump.
  • 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
  • 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.
  • 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.
  • the inlet may be operable to allow seawater to be flowed into a fluid conduit to dilute fluid (e.g.
  • 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.
  • a system for constructing a subsea well in a subterranean formation 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;
  • controllable subsea choke operable to generate a backpressure in the fluid circulation path
  • a subsea pump operable to lower the pressure in the fluid circulation path.
  • 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.
  • 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.
  • a fourth aspect of the invention there is provided a method of performing an operation in a subsea well, the method comprising:
  • 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.
  • 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.
  • 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;
  • 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.
  • 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.
  • FIG. 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.
  • 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.
  • 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.
  • the control module of this embodiment is at surface, a control module may be located in the subsea environment in alternative arrangements.
  • 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.
  • pressure control in the annulus is by appropriate selection of cement density or "weight" as well as cement rheology and circulating friction.
  • 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.
  • FIG. 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.
  • 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.
  • 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.
  • the system 234 is located on the seabed, but it may be positioned higher up in the water column in alternative
  • 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).
  • 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.
  • weight including the cement itself and the fluids circulated ahead of the cement volume
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • FIG. 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.
  • the system 300 also differs in the configuration of the subsea pressure regulation 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.
  • FIG 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
  • drilling fluid return system 410 (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
  • 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.
  • 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
  • the pump 436 is operated in dependence on the detected level of drilling fluid and cuttings supported within the body 412.
  • 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.
  • 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.
  • the fluid path can be switched through different flow lines in the system 434.
  • 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).
  • 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.
  • 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.
  • the invention has other applications to the control of pressure in annular space in a wellbore.
  • 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.
  • 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.
  • 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.

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  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Physics & Mathematics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Mechanical Engineering (AREA)
  • Placing Or Removing Of Piles Or Sheet Piles, Or Accessories Thereof (AREA)
  • Earth Drilling (AREA)
  • Glass Compositions (AREA)

Abstract

La présente invention a trait à un procédé et à un système permettant de construire un puits sous-marin dans une formation souterraine. Un élément tubulaire dans un puits sous-marin définit un puits principal et une trajectoire de circulation de fluide allant du puits principal jusqu'à un orifice de sortie est formée par l'intermédiaire de l'espace annulaire du puits entre l'élément tubulaire et la formation souterraine. Du lait circule depuis le puits principal le long de l'espace annulaire du puits vers l'orifice de sortie, entraînant le déplacement du fluide depuis l'espace annulaire à travers l'orifice de sortie. Un orifice calibré sous-marin réglable qui est en communication fluidique avec la trajectoire de circulation de fluide génère une contre-pression dans la trajectoire de circulation de fluide à l'aide de l'orifice calibré sous-marin réglable. Selon un mode de réalisation préféré, l'orifice calibré sous-marin réglable fait partie d'un système de régulation de pression sous-marin qui comprend également une pompe sous-marine.
PCT/GB2012/050828 2011-04-13 2012-04-13 Procédé et appareil de construction de puits sous-marin WO2012140445A2 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
GB1320056.3A GB2509377A (en) 2011-04-13 2012-04-13 Subsea wellbore construction method and apparatus

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NO20110564A NO339484B1 (no) 2011-04-13 2011-04-13 Fremgangsmåte og apparatur for å bygge et undersjøisk brønnhull
NO20110564 2011-04-13

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AU2012254933B2 (en) * 2011-11-16 2015-04-09 Weatherford Technology Holdings, Llc Managed pressure cementing
US9911016B2 (en) 2015-05-14 2018-03-06 Weatherford Technology Holdings, Llc Radio frequency identification tag delivery system
US10041328B2 (en) 2014-12-10 2018-08-07 Halliburton Energy Services, Inc. Method for using managed pressure drilling with epoxy resin
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CN106968650B (zh) * 2017-03-21 2019-03-15 中国石油集团川庆钻探工程有限公司长庆井下技术作业公司 一种治理表层套管与气层套管环空气窜的方法

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Publication number Priority date Publication date Assignee Title
AU2012254933B2 (en) * 2011-11-16 2015-04-09 Weatherford Technology Holdings, Llc Managed pressure cementing
US9249646B2 (en) 2011-11-16 2016-02-02 Weatherford Technology Holdings, Llc Managed pressure cementing
US9951600B2 (en) 2011-11-16 2018-04-24 Weatherford Technology Holdings, Llc Managed pressure cementing
US10041328B2 (en) 2014-12-10 2018-08-07 Halliburton Energy Services, Inc. Method for using managed pressure drilling with epoxy resin
US9911016B2 (en) 2015-05-14 2018-03-06 Weatherford Technology Holdings, Llc Radio frequency identification tag delivery system
US10198606B2 (en) 2015-05-14 2019-02-05 Weatherford Technology Holdings, Llc Radio frequency identification tag delivery system
US10890046B2 (en) 2016-05-11 2021-01-12 Halliburton Energy Services, Inc. Managed pressure reverse cementing
US11293248B2 (en) 2017-10-26 2022-04-05 Equinor Energy As Wellhead assembly installation

Also Published As

Publication number Publication date
NO20110564A1 (no) 2012-10-15
GB2509377A (en) 2014-07-02
GB201320056D0 (en) 2013-12-25
NO339484B1 (no) 2016-12-19
WO2012140445A3 (fr) 2014-01-09

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