EP3207212B1

EP3207212B1 - Wellbore insulation system and associated method

Info

Publication number: EP3207212B1
Application number: EP15777962.0A
Authority: EP
Inventors: Ewen Robertson; Nikolaas VAN DER POST
Original assignee: Maersk Olie og Gas AS
Current assignee: Total E&P Danmark AS
Priority date: 2014-10-17
Filing date: 2015-10-09
Publication date: 2020-04-22
Anticipated expiration: 2035-10-09
Also published as: EP3207212A1; GB201418488D0; WO2016058948A1; DK201770304A1

Description

FIELD

The present invention relates to a wellbore arrangement, system and method for controlling heat transfer between a tubular member located in a wellbore and a well system.

BACKGROUND

The formation of a wellbore involves the drilling of a bore hole into which a casing string can be run to the bottom of the bore hole. The casing string can then be cemented into the bore hole and a drilling assembly may be run through the casing string to drill a further bore hole, extending from the bottom of the casing string to a specific depth. A smaller diameter casing string can be run through the cemented casing string to the bottom of the bore hole and subsequently cemented into the bore hole. This process can be repeated until a hydrocarbon bearing reservoir has been encountered and a liner, which does not extend all the way back to surface, can be cemented across the reservoir. Each of these casing strings can form annuli as the casing strings are not cemented all the way to surface. These annuli may be filled with completion or wellbore fluids, such as fresh water or brines or oil based drilling muds or combination thereof. An A annulus is the inner most annulus, which may be formed between the inner most casing string, the so-called production casing, and a tubing, such as production tubing, through which a hydrocarbon fluid may flow. The hydrocarbon fluid may be a high pressure high temperature (HPHT) fluid. The A annulus may have a Nitrogen gas added to the top of the column of wellbore fluids to reduce pressure build-up as the wellbore system heats up due to production of the HPHT fluid to surface.
The wellbore fluids within the annuli may perform a number of functions. For example, the wellbore fluids may form a fluid pressure barrier against formation or reservoir fluid pressures. The wellbore fluids may allow control of the in-situ pressures applied to the casing and tubing strings by applying or removing surface pressure to the annuli.
Production of hydrocarbon fluids from a subterranean HPHT reservoir may result in the drilled wellbore including the casing or liner strings as well as the production tubing being subjected to significant pressure and thermal loads.
Pressure loads acting on both the casing or liner strings and the production tubing may be difficult to avoid and the well system is required to withstand these loads over the life of the well system and maintain integrity to safely produce the hydrocarbon fluid.
Thermal loads acting on the casing or liner strings and the production tubing can be present during production of hydrocarbon fluids to a surface due to heat transfer from the HPHT hydrocarbon fluid being produced from the subterranean reservoir (through the perforated liner set across the reservoir) and up the inside of the production tubing to a surface. These thermal loads can cause significant expansion of the in-situ casing and tubing strings as well as on the entire well system.
The heating of the well system from a geothermal gradient to the high temperatures of the hydrocarbon fluid during production can cause the fluids within the annuli to significantly expand and increase annuli pressures. This may result in well system failures, bursting and/or collapsing of tubing and/or casing strings.
The heating of the well system from a geothermal gradient to the high temperatures of the hydrocarbon fluid during production can also results in a thermal growth of the well tubing and casing strings. The majority of such growth may be due to the large diameter and heavy walled stiffer casing strings that are deep set within the wellbore at or above the HPHT hydrocarbon reservoir and within close proximity to the production tubing. The thermal expansion of a casing string, which may be longitudinally and radially expanding, can result in failure of an external cement sheath and/or anchoring the casing strings in the wellbore. This failure may result in the ingress of pressurised formation or reservoir fluids into the annulus, compromising the well barrier policy resulting in the wellbores being permanently shut and abandoned, which can lead to significant costs.
This heating of the whole well system during sustained steady state production of HPHT hydrocarbon fluids including the production tubing, casing or liner strings and surface equipment, which may include a wellhead and surface or Christmas tree, may result in a measureable growth of the wellhead at a surface. This growth of the wellhead can lead to significant upwards thrust loads on the surface facilities equipment.
In order to accommodate for this thermal growth, the complexity, overall weight and footprint area of the surface equipment facility increases, leading to a significant increase in costs.
Vacuum insulated tubing (VIT) may be used to reduce some of the transfer of heat from the HPHT hydrocarbons being produced in the production tubing to the outer casing strings. In VIT an outer tubing string can be welded onto the inner load bearing tubing string and a vacuum may be applied to seal the cavity to minimise heat transfer from the produced HPHT hydrocarbons through the tubing to the outer casing strings.
The use of VIT may lead to a reduction in the transfer of heat energy from the production tubing to the outer casing strings. However, there remains heat loss and thermal and pressure loads may still affect the well system as well as surface equipment.
US 5,025,862 (Showalter ) relates to a steam injection pipe system within a cased wellbore, which is processed to reduce the emissivity of an outwardly facing surface. The pipe system is combined with a cleaning device or process for maintaining the low emissivity surface and a mixed fluid non-condensable gas supply to exclude steam from an annular space.
US2014158363 (Deen ) relates to a method of servicing a wellbore within a subterranean formation comprising providing a drill string disposed within the wellbore having one or more tubulars associated therewith and forming one or more annuli around the drill string; placing an insulating packer fluid comprising an aqueous base fluid and a viscosifying agent into at least one of the one or more annuli surrounding the drill string; and performing a drill stem test while the insulating packer fluid is in place.
US2013269947 (Shilling et al ) relates to a lower riser assembly which connects a riser to a seabed mooring and to a subsea hydrocarbon fluid source. The assembly includes intake ports to accommodate flow of hydrocarbons from the hydrocarbon fluid source, as well as optional flow assurance fluid.

SUMMARY

According to a first aspect there is provided a wellbore arrangement for controlling heat transfer between a tubular member located in a wellbore and a well system, according to claim 1
In use, the insulating fluid may be circulated, for example intermittently or continuously circulated, in the space, e.g. by the control arrangement. The insulating fluid may be forward and/or reverse circulated, e.g. continuously or intermittently forward and/or reverse circulated, in the space, e.g. by the control arrangement. For example, in use, forward and/or reverse circulation of the insulating fluid may be achieved by injecting the insulating fluid into the space above and/or in proximity of the lower member and venting and/or returning the insulating fluid from the space at a distance and/or remote from the lower member, or vice versa.
By continuously forward and/or reverse circulating the insulating fluid, thermal insulation between the tubular member and a well system may be increased.
In use, the control arrangement may be utilised to facilitate control of heat transfer between the tubular member and a well system and/or a wellbore formation, e.g. adjacent to a well system.
The insulating fluid may substantially fill the space.
The insulating fluid may surround or at least partially surround the tubular member. The insulating fluid may extend or at least partially extend along a length and/or in a longitudinal direction of the tubular member. The tubular member may be immersed or partially immersed in the insulating fluid. The insulating fluid may provide or define a first insulating, e.g. a thermally insulating, barrier or region between the tubular member and a well system and/or a wellbore formation.
The wellbore arrangement may comprise an upper member. The space may be defined or extend between the lower and upper members.
The space may be an annular space. The space may extend in the longitudinal direction of the tubular member.
The insulating fluid may comprise or define a low thermal conductivity fluid. A thermal conductivity of the insulating fluid may be in the range of 3 x 10^-3 to 50 x 10^-3 W/(m K), for example around 25.8 x 10^-3 W/(m K). The insulating fluid may comprise a gas, e.g. an inert gas. In some examples, the insulating fluid may comprise Nitrogen, Krypton, Argon and/or Xenon, such as gaseous Nitrogen, Krypton, Argon and/or gaseous Xenon or the like. In other examples, the insulating fluid may comprise one or more insulating fluids and/or a combination of one or more insulating fluids. By combining one or more insulating fluids the thermal conductivities and/or properties of the insulating fluid may be controllable or variable.
In use, a flow or flow rate of insulating fluid into the space and/or from the space may be controlled or controllable, e.g. by the control arrangement.
In use, the flow or flow rate of the insulating fluid may be adjusted, varied and/or controlled to at least partially fill or substantially fill the space. The flow or flow rate may be controlled, adjusted and/or varied based on properties of a well system, e.g. a length or depth of the space, radial extension of the space, diameter of a wellbore and/or a volume of the space.
In use, the flow or flow rate of the insulating fluid may be adjusted, varied and/or controlled, e.g. by the control arrangement, to minimise heat transfer between the tubular member and a well system and/or a wellbore formation, e.g. adjacent to a well system.
In use, the control arrangement may adjust, vary or control the flow or flow rate of the insulating fluid in the space to reach a specific and/or pre-determined value of the flow rate. At the specific and/or pre-determined value of the flow rate, heat transfer between the tubular member and a well system may be minimised and/or decreased.
Alternatively or additionally, in use, a temperature of the insulating fluid, which may be injected and/or circulated in the space, may be controlled or controllable, e.g. by the control arrangement. In use, the temperature of the insulating fluid, which may be injected and/or circulated in the space, may be adjusted, varied and/or controlled to minimise heat transfer between the tubular member and a well system and/or a wellbore formation, e.g. adjacent to a well system. For example, a decrease in temperature of the insulating fluid in the space may cause or lead to a decrease in thermal conductivity of the insulating fluid, thereby decreasing heat transfer between the tubular member and a well system. In some examples, the temperature of the insulating fluid, which may be injected and/or circulated in the space, may be about or below 273.15 K (0° C), e.g. below 200 K (-73 °) or below 100 K (-173 °C). By controlling, varying and/or adjusting the temperature of the insulating fluid in the space, the thermal conductivity of the insulating fluid may be varied.
In use, the temperature and/or flow rate of the insulating fluid, which may be injected and/or circulated into the space, may be varied, adjusted and/or controlled to lead or cause a change in temperature, e.g. a decrease in temperature, of the tubular member and/or the second fluid flowing in the tubular member. The second fluid may also be defined as a produced fluid.
In use, the temperature and/or flow rate of the insulating fluid, which may be injected and/or circulated into the space, may be varied, adjusted and/or controlled to vary and/or control a temperature of the tubular member and/or the second fluid flowing in the tubular member, e.g. by the control arrangement. For example, a decrease in temperature of the insulating fluid in the space may cause or lead to a decrease in temperature of the tubular member and/or the second fluid flowing in the tubular member. Alternatively or additionally, an increase in the flow rate of the insulating fluid into the space may cause or lead to a decrease in temperature of the tubular member and/or the second fluid flowing in the tubular member.
In use, the control arrangement may adjust, vary and/or control the temperature of the insulating fluid, which may be injected and/or circulated, in the space to reach a specific and/or pre-determined value of the temperature. At the specific and/or predetermined value of the temperature, heat transfer between the tubular member and a well system may be minimised and/or decreased. The tubular member may be arranged to transport or contain a second fluid, such as a hydrocarbon fluid, e.g. oil and/or a gas, such as a gas condensate or the like. The tubular member may transport the second fluid from a reservoir, such as a subterranean reservoir, of second fluid to a surface structure, e.g. a wellhead member, offshore platform, vessel or the like, and/or the upper member. The reservoir of the second fluid may be a hydrocarbon reservoir, e.g. a high pressure high temperature hydrocarbon bearing reservoir. The second fluid may comprise or exhibit a temperature, which may be a temperature greater than 350°F (205° C). The second fluid may comprise a pressure, e.g. a surface pressure, which may be greater than a hydrostatic gradient of 0.8 psi/ft (0.18 bar/m) or a pressure in excess of 3,000 psi (200 bar), for example, greater than 5,000 psi (350 bar), such as in excess of 15,000 psi (1,380 bar). At a pressure exceeding 15,000 psi (1,380 bar), the second fluid may comprise or define as a high pressure high temperature fluid. The insulating fluid may assist to minimise heat/thermal energy transfer from the second fluid to a well system and/or wellbore formation.
The tubular member may be or comprise a tubular, tubing string, such as a production tubing string, a conduit, casing, casing string, conductor or the like. The tubular member may define or form part of a wellbore completion.
The insulating fluid may be or comprise a pressurised insulating fluid.
In some examples, the second fluid may comprise a high pressure high temperature gas condensate. Production of the HPHT gas condensate from a reservoir through the tubular member to a surface may result in a temperature and/or pressure change of the gas condensate. The second fluid and/or insulating fluid may comprise or exhibit a pressure gradient, e.g. a pressure gradient along a length of the tubular member. The pressure gradient of the second fluid and/or insulating fluid may be due to or caused by a hydrostatic pressure of the second fluid and/or insulating fluid. The pressure gradient of the insulating fluid may be adjusted, varied and/or modified to match to or track the pressure gradient of the second fluid, e.g. to be substantially the same as or similar to the pressure gradient of the second fluid in the tubular member, e.g. by the control arrangement.
In use, the pressure gradient of the second fluid may be matched or tracked by selecting an insulating fluid comprising substantially the same or similar hydrostatic pressure as the second fluid. By adjusting the pressure gradient of the insulating fluid to be substantially the same or similar to the pressure gradient of the second fluid, pressure loading, such as in-situ pressure loading, which may be due to production of the second fluid, may be reduced. A pressure of the insulating fluid may be adjusted to match or track a pressure change, pressure differential and/or pressure gradient of the gas condensate, contained or flowing in tubular member.
In use, the insulating fluid may be pressurised to a pre-determined pressure and/or specific pressure. At the pre-determined and/or specific pressure, the insulating fluid may minimise thermal loading, e.g. thermal in-situ loading, on the tubular member. The pre-determined and/or specific pressure may be in a range of a shut-in pressure, e.g. a pressure measured at or near the surface of a wellbore when a wellbore is closed, to a flowing pressure over the a lifetime of a wellbore and/or to a minimum surface back pressure or less.
The pressure and/or pressure gradient of the insulating fluid may be varied or variable, in use. By pressurising the insulating fluid, the thermal conductivity of the fluid may be varied so as to adjust or control the thermal insulating capabilities of the insulating fluid. For example, by increasing a pressure of the insulating fluid in the space, a thermal conductivity of the insulating fluid may increase. Alternatively, a decrease in a pressure of the insulating fluid in the space may provide a decrease of a thermal conductivity of the insulating fluid, which may increase a thermal insulation between the tubular member and a well system.
In use, the insulating fluid may be pressurised to match a pressure of the second fluid within the tubular member. Alternatively, a pressure of the insulating fluid may be higher or lower than a pressure of the second fluid in the tubular member, in use. In use, the pressure gradient e.g. along a length of the tubular member and/or well system, of the insulating fluid may match a pressure gradient of the second fluid within the tubular member. For example, the pressure gradient of the insulating fluid contained in the space may be substantially the same or equivalent to the pressure gradient of the second fluid contained in the tubular member. By adjusting the pressure gradient of the insulating fluid to be substantially the same as or similar to the pressure gradient of the second fluid, pressure loading, such as in-situ pressure loading, which may be due to production of the second fluid, may be reduced. For example, the pressure gradient of the insulating fluid may complement or be matched to a decreasing or increasing pressure, pressure gradient and/or pressure differential of the second fluid in the tubular member. For example, the pressure gradient may complement or be matched to a decreasing pressure, pressure gradient and/or pressure differential of the second fluid from a depleting hydrocarbon reservoir. By matching or complementing a pressure, pressure gradient and/or pressure differential of the second fluid from a depleting hydrocarbon reservoir, thermal insulation between the tubular member and a well system may be increased.
The tubular member may be configured to reduce transfer of thermal energy/heat from the second fluid contained or flowing therein to a well system and/or wellbore formation (e.g. a further tubular member). The tubular member may comprise an insulating chamber. The insulating chamber of the tubular member may provide a second insulating, e.g. thermally insulating, barrier or region between an interior of the tubular member and a well system. By providing the first and/or second thermally insulating barriers or regions between the tubular member and a well system, transfer of heat/thermal energy between an interior of the tubular member to a well system may be reduced.
The insulating fluid and/or the insulating chamber of the tubular member may minimise heat/thermal energy transfer from the second fluid to a well system (e.g. a further tubular member). By minimising heat/thermal energy from being transferred to a well system and/or a wellbore formation adjacent to a well system, thermal loading or expansion of a well system may be minimised. The first insulating and/or second insulating barriers may lead to a reduction of the thermal heating of a well system, which may reduce or minimise thermal and/or pressure loading of a well system, for example thermal and/or pressure loading on cement sheaths external to the further tubular member.
The insulating chamber may surround or at least partially surround the tubular member. The insulating chamber may be an annular insulating chamber. The insulating chamber may extend or at least partially extend along the length and/or in the longitudinal direction of the tubular member. The insulating chamber may be provided on an outer surface of the tubular member. The insulating chamber may be provided integrally with the tubular member. The insulating chamber may comprise or define a vacuum or partial vacuum. Alternatively, the insulating chamber may comprise a third fluid, such as a gas, for example an inert gas or the like. The insulated chamber may minimise transfer of heat and/or thermal energy from the second fluid, which may be contained or flow within the tubular member. By providing the tubular member with an insulating chamber, heat and/or thermal energy transfer from the second fluid to a well system (e.g. a further tubular member) may be minimised or reduced.
The tubular member may comprise one or more tubular portion(s). Each of the tubular portions may comprise at least part of the insulating chamber. The tubular member may comprise a connection arrangement for connecting together and/or securing the tubular portions to one another. The connection arrangement between each of the tubular portions may be thermally insulated, for example to minimise heat transfer from the second fluids flowing in the tubular member to a well system.
In some examples, a well system may comprise a further tubular member, which may surround the tubular member. The further tubular may define a wall of a well system. The space may be formed between the tubular member and the further tubular member. The space may be an annular space formed between the tubular member and the further tubular member. The space between the tubular member and the further tubular member may define or comprise an A annulus. The further tubular member may be or comprise a casing, casing string, conduit, conductor or the like. The further tubular member may be at least partially fixed or cemented in a wellbore.
The lower member may be provided on the tubular member. The lower member may be configured for engagement with a well system (e.g. the further tubular member). The lower member may provide a seal between the tubular member and a well system and/or a wall of a well system. The lower member may isolate the space containing the insulating fluid from a space or zone containing the second fluid, such as a hydrocarbon bearing zone or production zone, wellbore fluids or particles, or the like. The lower member may be located above a production zone of the second fluid. The lower member may confine the insulating fluid within the space.
In use, the lower member may provide a substantially pressure (tight) seal to maintain a pressure of the insulating fluid in the space. The lower member may restrict flow of the insulating fluid in a downhole direction. The lower member may comprise a sealing member, e.g. an annular sealing member. The sealing member may comprise a packer, such as a production packer. Alternatively or additionally, the lower member may comprise a plug, flow control device or the like.
The upper member may restrict or prevent flow of the insulating fluid in an uphole direction in the space. The upper member may provide a further seal to flow of the insulating fluid in an uphole direction. The upper member may maintain a pressure, e.g. a pressure of the insulating fluid in the space.
The upper member may comprise at least part of the control arrangement.
In use, the upper member may provide a substantially further pressure (tight) seal to maintain a pressure of the insulating fluid in the space. The upper member may be configured to control, adjust and/or maintain a pressure of the insulating fluid in the space. The upper member may be configured to circulate, e.g. continuously or intermittently circulate, the insulating fluid in the space. The upper member may be configured to provide forward and/or reverse circulation, e.g. continuous or intermittent forward and/or reverse circulation, of the insulating fluid in the space.
Alternatively or additionally, the upper member may be configured to control, adjust and/or maintain a pressure of the second fluid in the tubular member.
The upper member may comprise the wellhead member. The upper member may comprise tubing hanger. Alternatively or additionally, the wellhead member may comprise a wellhead, casing hanger, Christmas tree, blow out preventer and/or the like. In other examples, the upper member may be a further sealing member, such as a packer, plug or the like.
The lower member (e.g. a packer or production packer) may be pre-installed on the tubular member, such as pre-installed in an unset or retracted configuration. In use, installation of the tubular member may comprise installing and/or locating the pre-installed and/or retracted lower member in a wellbore. When installed at a desired position in a wellbore, the lower member may be set, e.g. by actuating, such as hydraulically and/or mechanically actuating, the lower member from the retracted configuration to an expanded configuration. In the expanded configuration of the lower member, the lower member may engage a well system (e.g. the further tubular member).
The lower member may be disposed and/or pre-installed at or on a lower end or downhole end of the tubular member. At least a portion of the tubular member may extend or protrude (downhole) from the lower member. The portion of the tubular member extending or protruding from the lower member may comprise one or more perforations or openings. The one or more perforations or openings allow inflow of the second fluid into the tubular member. The portion of the tubular member extending from the lower member may be or comprise a tail or tail portion.
The wellbore arrangement may comprise a vessel or chamber, e.g. a pressure vessel or chamber. The vessel or chamber may be part of or comprised in the control arrangement. The vessel or chamber may be or comprise a source or reservoir of the insulating fluid. The vessel may be in communication with the space. The vessel may be located on a surface structure, such as an offshore platform, vessel or the like, or a seabed.
The wellbore arrangement may comprise at least one pump and/or compressor arrangement. The at least one pump and/or compressor arrangement may be comprised in the control arrangement. The pump and/or compressor arrangement may be configured to adjust the pressure of the insulating fluid in the space. The at least one pump and/or compressor arrangement may be adapted to pump and/or inject the insulating fluid into the space, e.g. from the source into the space. Alternatively or additionally, the at least one pump and/or compressor arrangement may be adapted to vent the insulating fluid from the space, for example into the source.
The pump and/or compressor arrangement or means may be located on or adjacent the upper member. In some examples, the upper member may comprise the pump and/or compressor arrangement or means. Alternatively or additionally, the pump and/or compressor arrangement may be located separately from the upper member. The pump and/or compressor arrangement may be configured for circulating, such as continuously or intermittently, circulating the insulating fluid in the space.
The control means or arrangement may control injection of the insulating fluid into the space and/or venting of the insulating fluid from the space, thereby adjusting a pressure of the insulating fluid. The control means or arrangement may control, adjust and/or maintain circulation, e.g. continuous or intermittent circulation of the insulating fluid in the space. The control means or arrangement may control, adjust and/or maintain forward and/or reverse circulation, such as continuous or intermittent forward and/or reverse circulation, of the insulating fluid in the space. The control means or arrangement may control, adjust and/or maintain circulation of the insulating fluid at a pressure, pressure differential and/or pressure gradient of the insulating fluid, which may match or complement a pressure, pressure differential and/or pressure gradient of the second fluid in the tubular member.
The wellbore arrangement may comprise at least one first conduit member for directing and/or transferring the insulating fluid into the space and/or from the space.
The wellbore arrangement may comprise at least one second conduit member for returning or venting the insulating fluid, e.g. to the source of the insulating fluid, and/or injecting the insulating fluid into the space. The at least one first and/or second conduit member(s) may be comprised in the control arrangement and/or upper member.
The first and/or second conduit member(s) may be disposed in the space. The first and/or second conduit member(s) may be in communication with the pump or compressor arrangement or means and/or control arrangement or means. The first and/or second conduit member(s) may be attached, such as releasably attached, to the tubular member. Alternatively, the first and/or second conduit member(s) may be fixed to the tubular member by one or more clamping members, e.g. coupling clamps and/or cross-coupling clamps or the like. The first and/or second conduit member(s) may extend along at least part of the length of the tubular member. In some examples, the first and/or second conduit member(s) may extend along the length of the tubular member, for example to above the lower member, e.g. the production packer. By extending the first and/or second conduit member(s) into proximity of the lower member, a fluid, such as a wellbore fluid, and/or particles, which may be present in a wellbore prior to injection of the insulating fluid, may be displaced. The wellbore fluid may comprise water, brine, drilling mud and/or combination thereof, and/or particles.
In use, injection of the insulating fluid may displace the wellbore fluid and/or particles from the space. The first and/or second conduit member(s) may enter the space through or via the upper member. The first and/or second conduit member(s) may be configured for circulating, such as continuously or intermittently circulating and/or forward and/or reverse circulating, the insulating fluid in the space. For example, the insulating fluid may be injected into the space, for example, to above the lower member, via the first conduit member and vented or transferred from the space via the second conduit member or vice versa.
The first and/or second conduit member(s) may comprise a hose, pipe, tubular, umbilical or the like.
The wellbore arrangement may comprise at least one sensing arrangement. The at least one sensing arrangement may be comprised in or part of the control means or arrangement. The at least one sensing arrangement may be disposed or provided in the space and/or on the tubular member.
The at least one sensing arrangement may sense, measure and/or monitor a pressure, pressure differential, pressure gradient, temperature, temperature gradient and/or temperature differential of the insulating fluid in the space. Alternatively or additionally, the at least one sensing arrangement may sense, measure and/or monitor a pressure, pressure differential, temperature and/or temperature differential of the second fluid in the tubular member. The at least one sensing arrangement may be configured to sense, measure and/or monitor a pressure, pressure differential, pressure gradient, temperature, temperature gradient and/or temperature differential of the insulating and/or second fluid at one or more location(s). For example, the at least one sensing arrangement may be configured to sense, measure, and/or monitor a pressure and/or temperature of the insulating and/or second fluid at one or more location(s) along the length of the tubular member. Alternatively or additionally, the at least one sensing arrangement may be configured to sense, measure and/or monitor a pressure and/or temperature of the insulating fluid at one or more location(s) between the tubular member and a well system (e.g. the further tubular member).
In use, the at least one sensing arrangement may communicate a pressure, pressure differential, pressure gradient, temperature, temperature gradient and/or temperature differential of the insulating and/or second fluid to the control arrangement or means. In response to the pressure, pressure differential, pressure gradient, temperature, temperature gradient and/or temperature differential determined by the at least one sensing arrangement, the control arrangement or means may adjust a pressure of the insulating fluid so as to achieve or reach a pre-determined pressure, pressure differential and/or pressure gradient, e.g. along at least part of a length of the tubular member and/or space, in use.
In response to the pressure, pressure gradient pressure differential, temperature, temperature gradient and/or temperature differential determined by the at least one sensing arrangement, the control arrangement may adjust a pressure of the second fluid so as to achieve or reach a pre-determined pressure, pressure differential and/or pressure gradient, e.g. along at least part of a length of the tubular member, in use. A pressure of the second fluid within the tubular member may be adjusted by choking or restricting a flow of the second fluid within the tubular member, e.g. to vary a pressure and/or back pressure of the second fluid within the tubular member. In some examples, a flow of the second fluid in the tubular member may be restricted or choked by one or more valves.
The at least one sensing arrangement may comprise one or more sensor(s), such as one or more point or discrete sensor(s). The one or more sensor(s) may comprise one or more pressure sensor(s), temperature sensor(s), such as one or more downhole gauge(s), temperature gauge(s) and/or pressure gauge(s), or combinations thereof. The one or more sensor(s) may be provided on or comprised in the tubular member.
The at least one sensing arrangement may comprise a sensing member, such as an elongated sensing member. The sensing member may be attached, such as releasably attached, to the tubular member. Alternatively or additionally, the sensing member may be fixed to the tubular member by one or more clamping members, e.g. coupling clamps and/or cross-coupling clamps or the like. The sensing member may extend along at least part of the length of the tubular member. In some examples, the sensing member may extend along the length of the tubular member to above the lower member. In some examples, the sensing member may comprise a distributed sensing arrangement, e.g. a distributed temperature sensing arrangement and/or a distributed pressure sensing arrangement, for monitoring the temperature, temperature differential, temperature gradient, pressure, pressure differential and/or pressure gradient of the insulating fluid and/or the space. Alternatively or additionally, the sensing member may comprise an acoustic sensing arrangement. The sensing member may be disposed opposite the insulating and/or second conduit member in the space. By disposing the sensing member opposite the insulating and/second further tubular members, injection, venting and/or pumping of the insulating fluid in or out of space may not interfere with the monitoring of the temperature and/or pressure of the insulating fluid and/or space.
According to a second aspect of the present invention there is provided a method for controlling heat transfer between a tubular member located in a wellbore and a well system, according to claim 14.
The method may comprise circulating, e.g. intermittently or continuously circulating, of the insulating fluid in the space.
The method may comprise forward and/or reverse circulating, such as continuously or intermittently forward and/or reverse circulating, of the insulating fluid in the space. By continuously or intermittently forward and/or reverse circulating the insulating fluid, e.g. into or from the space, thermal insulation between the tubular member and a well system may be increased.
The tubular member may be arranged to transport and/or contain a second fluid, such as a hydrocarbon fluid, e.g. oil or a gas condensate or the like.
The step of providing a pressure differential and/or pressure gradient of the insulating fluid may comprise selecting an insulating fluid with substantially the same or similar hydrostatic pressure as a hydrostatic pressure of the second fluid.
By adjusting the pressure differential and/or pressure gradient of the insulating fluid to be substantially the same as the pressure differential and/or pressure gradient of the second fluid, pressure loading to produce the second fluid, such as in-situ pressure loading, which may act or be exerted on the tubular member, may be reduced.
The method may comprise circulating, such as continuously or intermittently and/or forward and/or reverse circulating, of the insulating fluid in the space at a pressure, pressure differential and/or pressure gradient of the insulating fluid, which may match or complement a pressure, pressure differential and/or pressure gradient of the second fluid in the tubular member.
The method may comprise controlling, adjusting and/or varying a flow or flow rate of the insulating fluid into the space and/or from the space.
The method may comprise controlling, adjusting and/or varying flow or flow rate of the insulating fluid to at least partially fill or substantially fill the space.
The method may comprise controlling, adjusting and/or varying the flow or flow rate based on properties of a well system, e.g. a length or depth of the space, radial extension of the space, diameter of a wellbore and/or a volume of the space.
The method may comprise controlling, adjusting and/or varying the flow or flow rate of the insulating fluid to minimise heat transfer between the tubular member and a well system and/or a wellbore formation, e.g. adjacent to a well system.
The method may comprise identifying or determining a specific and/or predetermined flow or flow rate, e.g. based on the properties of a well system, e.g. a length or depth of the space, diameter of the space and/or a volume of the space or the like.
The method may comprise injecting and/or circulating the insulating fluid in the space at the specific and/or pre-determined flow rate.
The method may comprise adjusting, varying and/or controlling the flow or flow rate of the insulating fluid in the space to reach a specific and/or pre-determined value of the flow rate. At the specific and/or pre-determined value of the flow rate, heat transfer between the tubular member and a well system may be minimised and/or decreased.
The method may comprise controlling a temperature of the insulating fluid injected and/or circulated in the space.
The method may comprise adjusting, varying and/or controlling the temperature of the insulating fluid injected and/or circulated in the space to minimise heat transfer between the tubular member and a well system and/or a wellbore formation, e.g. adjacent to a well system. For example, a decrease in temperature of the insulating fluid in the space may cause or lead to a decrease in thermal conductivity of the insulating fluid, thereby decreasing heat transfer between the tubular member and a well system.
In some examples, the method may comprise injecting and/or circulating of the insulating fluid in the space at a temperature of about or below 273.15 K (0° C), e.g. to below 200 K (-73 °) or below 100 K (-173 °C). By controlling, varying and/or adjusting the temperature of the insulating fluid in the space, the thermal conductivity of the insulating fluid may be varied.
The method may comprise identifying or determining a specific and/or predetermined temperature of the insulating fluid injected and/or circulated in the space, e.g. based on the properties of a well system, e.g. the length or depth of the space, diameter of the space and/or volume of the space or the like.
The method may comprise injecting and/or circulating the insulating fluid in the space at the specific and/or pre-determined temperature.
The method may comprise adjusting, varying and/or controlling the temperature of the insulating fluid injected and/or circulated in the space to reach the specific and/or pre-determined value of the temperature. At the specific and/or pre-determined value of the temperature, heat transfer between the tubular member and a well system may be minimised and/or decreased.
The method may comprise adjusting, varying and/or controlling the temperature and/or flow rate of the insulating fluid, which may be injected and/or circulated into the space, to lead or cause a change in temperature, e.g. a decrease in temperature, of the tubular member and/or the second fluid flowing in the tubular member.
The method may comprise adjusting, varying and/or controlling the temperature and/or flow rate of the insulating fluid to vary and/or control a temperature of the tubular member and/or the second fluid flowing in the tubular member.
For example, the method may comprise decreasing a temperature of the insulating fluid, which may be injected and/or circulated in the space, to cause or lead to a decrease in temperature of the tubular member and/or the second fluid flowing in the tubular member.
The method may comprise increasing of the flow rate of the insulating fluid, which may be injected and/or circulated in the space, to cause or lead to a decrease in temperature of the tubular member and/or the second fluid flowing in the tubular member.
The method may comprise controlling, adjusting and/or varying a pressure of the second fluid in the tubular member to achieve a pre-determined and/or specific pressure of the second fluid in the tubular member. A pressure of the second fluid may be adjusted to a pre-determined pressure, pressure differential and/or pressure gradient, e.g. along at least part of a length of the tubular member by choking or restricting a flow of the second fluid within the tubular member, e.g. to vary a pressure and/or back pressure of the second fluid within the tubular member.
The method may comprise sealing or closing of the space to prevent flow of the insulating fluid in an uphole and/or downhole direction.
The method may comprise providing and/or installing an upper member. In some examples, the upper member may comprise a wellhead member. The wellhead member may comprise a wellhead, tubing hanger, casing hanger, Christmas tree, blowout preventer or the like.
The upper member may restrict flow of the insulating fluid in an uphole direction. The upper member may provide a further substantially pressure (tight) seal of the insulating fluid in the space.
The method may comprise disposing and/or installing a first and/or second conduit member(s) in the space.
The method may comprise injecting of the insulating fluid into the space. The insulating fluid may be injected into the space via the first and/or second conduit member(s).
The method may comprise providing and/or installing a control means or arrangement. The control means or arrangement may control, adjust and/or vary the pressure of the insulating fluid in the space.
The method may comprise installing at least one sensing arrangement for monitoring a pressure, pressure differential, pressure gradient, temperature, temperature differential and/or temperature gradient of the insulating fluid and/or the second fluid.
The method may comprise providing one or more sensor(s) on or associated with the tubular member to monitor a pressure, pressure differential, pressure gradient, temperature, temperature differential and/or temperature gradient of the second fluid. The one or more sensor(s) may be comprised in the sensing arrangement.
The method may comprise displacing a fluid, such as a wellbore fluid and/or particles contained within the space prior to injection of the insulating fluid into the space. The wellbore fluids may be displaced by injecting the insulating fluid into the space using the first and/or second conduit member(s), e.g. subsequently to installing of the upper member. The wellbore fluid may be injected into the space during installation of the tubular member, wellhead member, control means or arrangement and/or sensing member. The wellbore fluid may be a completion fluid, such as water, brine, drilling mud or combination thereof. By displacing the wellbore fluid from the space, damage and corrosion of the tubular member and/or a well system may be reduced or even prevented.
The method may comprise installing the lower member.
The method may comprise locating and/or installing a lower member. The lower member may comprise a sealing member, such as a packer or production packer. In some examples, the lower member may be pre-installed on the tubular member, such as pre-installed in an unset and/or retracted configuration. In other examples, the lower member may be provided separately from the tubular member.
The method may comprise setting of the lower member. For example, the step of setting the lower member may comprise actuating, such as hydraulically and/or mechanically actuating, the lower member (e.g. a packer or production packer) from the retracted configuration to an expanded configuration, e.g. at a desired and/or predetermined position in a well system. In the expanded configuration of the lower member, the lower member may engage a wall of a well system and/or a further tubular member. The further tubular member may surround the tubular member.
The method may comprise isolating and/or sealing the space containing the insulating fluid from a space or zone containing the second fluid, such as a hydrocarbon bearing zone, wellbore fluids or particles, or the like, by actuating the lower member into the expanded configuration. In use, the lower member may provide a substantially pressure (tight) seal to maintain a pressure of the insulating fluid in the space. The lower member may restrict flow of the insulating fluid in a downhole direction.
The method may comprise testing, such as pressure testing, the space.
The method may comprise controlling a pressure of the insulating fluid contained in the space using a control means or arrangement.
The method may comprise injecting or transferring the insulating fluid into the space to achieve or maintain a pre-determined pressure, pressure differential and/or pressure gradient of the insulating fluid.
The method may comprise venting of the insulating fluid from the space to achieve or maintain a pre-determined pressure, pressure differential and/or pressure gradient of the insulating fluid.
The insulating fluid may be vented from the space via the first and/or second conduit member(s).
The method may comprise monitoring and/or sensing a pressure, pressure differential, pressure gradient, temperature, temperature gradient and/or temperature differential of the insulating fluid in the space and/or the second fluid in the tubular member. The method may comprise adjusting the pressure, pressure differential, and/or pressure gradient of the insulating fluid in response to a pressure, pressure differential, pressure gradient, temperature, temperature differential and/or temperature gradient determined by the sensing arrangement.
The method may comprise adjusting or varying the pressure of the insulating fluid to reach or achieve a predetermined pressure and/or temperature value.
The method may comprise monitoring and/or sensing a pressure, pressure differential, pressure gradient, temperature, temperature gradient and/or temperature differential of the second fluid in the tubular member. The method may comprise adjusting the pressure differential, and/or pressure gradient of the second fluid in response to a pressure, pressure differential, pressure gradient, temperature, temperature differential and/or temperature gradient value determined by the sensing arrangement.
The method may comprise adjusting a pressure, pressure differential, pressure gradient of the second fluid to a pre-determined pressure, pressure gradient and/or pressure differential, e.g. along at least part of a length of the tubular member by choking or restricting a flow of the second fluid within the tubular member, e.g. to vary a pressure and/or back pressure of the second fluid within the tubular member.
Features defined in above in relation to the first aspect may be applied to the second aspect. The method of the second aspect may be implemented in the wellbore arrangement of the first aspect.
It should be understood that the features defined above in accordance with any aspect of the present invention or below in relation to any specific embodiment of the invention may be utilised, either alone or in combination with any other defined feature, in any other aspect or embodiment of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other aspects of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which:

Figure 1 is a longitudinal cross-sectional diagrammatic representation of a completion system in accordance with an embodiment of the invention;
Figure 2 is a diagrammatic representation of reservoir temperature over surface pressure of high pressure high temperature hydrocarbon reservoirs;
Figure 3 is a diagrammatic representation of depth over density of an insulating fluid for use in the wellbore arrangement of Figure 1;
Figure 4 is a diagrammatic representation of thermal conductivity versus pressure of Nitrogen at temperatures from about 60 to 350 °F (15°C to 175°C) in a space defined by the completion system of Figure 1;
Figures 5 (a) and 5 (b) are schematic representations of a tubular member including an insulating chamber in accordance with an embodiment of the invention;
Figures 6 (a) to 6(c) are schematic representations of the tubular member of Figure 1 arranged at different location within a casing; and
Figure 7 is a flow chart of a method for installing the wellbore arrangement of Figure 1.

DETAILED DESCRPITION OF THE DRAWINGS

Reference is first made to Figure 1(a) in which there is shown a well system that includes a completion system, generally identified by reference numeral 10, in accordance with an embodiment of the present invention, wherein the completion system 10 is shown installed within a well system 12. In this respect, the well system 12 includes a drilled bore or wellbore 14 and a number of concentric and cemented casing strings 16a, 16b (two shown in the exemplary embodiment). A liner 18 extends from the inner and lowermost casing string 16b and through a subterranean reservoir 20 which contains hydrocarbons to be produced to surface via the completion system 10. The casing strings 16a,16b and liner string 18 are anchored and sealed in wellbore 14 by a number of cement sheaths 17a, 17b, 17c (three shown in the exemplary embodiment).
The completion system 10 includes a tubular member 22, in the form of a production tubing string, which extends from a wellhead region 24 and into the liner 18. When installed as illustrated in Figure 1(a), a space or annulus 26 is defined between the production tubing string 22 and the innermost casing string 16b. This annulus is typically referred to in the art as the A annulus.
A lowermost region of this annulus 26 is sealed via a lower member in the form of a production packer 28 mounted on a lower region of the production tubing string 22. The production packer 28 may be initially arranged in a retracted or unset configuration to permit deployment of the completion system 10, and then subsequently set to the form shown in Figure 1(a). Once set, a tail region of the production tubing string 22 extends below the production packer 28 in into the liner 18. The production packer 28 isolates the annulus 26 from the subterranean reservoir 20.
Referring to Figure 1(b), the production tubing string 22 is suspended from a wellhead 30 via a tubing hanger 32. This tubing hanger 32 may function to seal an upper region of the annulus 26.
A production tree 34 is mounted on the wellhead 30, and functions to cap the well system 10, and assist in controlling production of fluids from the reservoir 20. During production, reservoir fluids may enter the liner 18 via perforations 35, and flow into the lowermost region of the production tubing 22 to be flowed to surface.
In this example, the reservoir 20 is a high pressure high temperature (HPHT) hydrocarbon reservoir and the reservoir fluids 32 can have a temperature greater than 350°F (205° C). An HPHT reservoir 20 can have a pressure, which is greater than a hydrostatic gradient of 0.8 psi/ft (0.18 bar/m) or a surface pressure in excess of 15,000 psi (1,380 bar). Figure 2 shows an example of high temperature high pressure wellbore or reservoir classifications. It will be appreciated that the system 10 can be used in a wellbore reservoir having a temperature less than 350°F (205° C) and/or a surface pressure less than a hydrostatic gradient of 0.8 psi/ft (0.18 bar/m) or 15,000 psi (1,380 bar). Alternatively or additionally, the system 10 may be used in a ultra-high pressure high temperature (ultra-HPHT) wellbore, e.g. in a wellbore having reservoir temperatures in excess of 500°F (260° C) and/or surface pressures in excess of 35,000 psi (2,413 bar), and/or extreme high pressure high temperature (HPHT-hc) wellbore, e.g. in a wellbore having reservoir temperatures in the region or excess of 600°F (315° C) and/or surface pressures in the region or excess of 40,000 psi (2,760 bar).
During the production of HPHT reservoir fluids, heat may be transferred from the reservoir fluids to the production tubing 22, liner string 18, casing strings 16a,16b cement sheaths 17,a,17b,17c and to the wellbore formation 14 adjacent to the cement sheaths 17a, 17b, 17c. The heat transfer may results in thermal loads, for example acting on the casing strings 16a,16b, liner string 18, cement sheaths 17a,17b,17c and the production tubing 22 during production of the reservoir fluids to a surface. The thermal loads may cause thermal expansion, for example of the casing 16a,16b, tubing string 18, cement sheaths 17a,17b,17c and can lead to damages of well system 12.
The heat transfer from the reservoir fluids can be minimised by filling annulus 26 with an insulating fluid 36.
Referring to Figure 1 (a), the insulating fluid 36 can be injected into the annulus 26 by a first conduit 52a and may substantially fill the annulus 26. It will be appreciated that in further examples, the insulating fluid 36 may partially fill the annulus 26. When injected, the insulating fluid 36 at least partially surrounds the production tubing 22 and/or extends at least partially along a length of the production tubing 22. The production tubing 22 can be completely immersed in the insulating fluid 36. It will be appreciated that in further examples, the production tubing 22 may be partially immersed in the insulating fluid 36. The insulating fluid 36 provides a first insulating, such as a thermally insulating, barrier or region between the production tubing 22 and the well system 12, thereby minimising heat transfer to the well system 12.
The insulating fluid 36 comprises a low thermal conductivity fluid. Here, a thermal conductivity of the insulating fluid can be in the range of, for example 3 x 10^-3 to 50 x 10^-3 W/(m K), for example about 25.8 x 10^-3 W/(m K). In some examples, the insulating fluid includes a gas, e.g. an inert gas. The insulating fluid can be Nitrogen, Krypton, Argon and/or Xenon, such as gaseous Nitrogen, Krypton, Argon and/or gaseous Xenon or the like. It will be appreciated that in further examples a different insulating fluid, e.g. a different low thermal conductivity fluid, than that described may be used. In other examples, the insulating fluid 36 can comprise one or more insulating fluids 36 and/or a combination of one or more insulating fluids 36. By combining one or more insulating fluids 36 the thermal conductivities and/or properties of the insulating fluid 36 may be controllable or variable.
In this example, the insulating fluid 36 is pressurised to have a pressure, which may be the same or similar to a pressure of the reservoir fluids in the production tubing 22. It will appreciated that in further examples, a pressure of the insulating fluid 36 may be different from a pressure of the reservoir fluids flowing in the production tubing 22.
Here, the insulating fluid 36 is pressurised by a controller 38 which can include a pump or compressor arrangement 50, as will be described below. The controller may be part of the production tree 34 but is shown in Figure 1 (b) as being coupled to the production tree 34. In some examples, the controller 38 can create a pressure differential between a pressure of the reservoir fluids in the production tubing 22 and the insulating fluid 36 in the annulus 26. In other examples, the insulating fluid 36 can also be pressurised to match or track a pressure of the reservoir fluids in the production tubing 22.
The reservoir fluids can include a high pressure high temperature gas condensate. Production of a HPHT gas condensate from a reservoir through the production tubing 22 to the wellbore region 24 can result in a temperature and/or pressure change of the gas condensate in the production tubing string 22. As described above, a pressure of the insulating fluid 36 can be adjusted or modified to match or track a pressure and/or pressure change of the gas condensate flowing in the production tubing 22. In further examples, a pressure of the insulating fluid may be higher or lower than a pressure of the reservoir fluids in the production tubing 22.
During production, a pressure of the reservoir fluids can vary along the length of the production tubing 22, thereby exhibiting a pressure gradient along the length of the production tubing 22. The pressure gradient of the reservoir fluids may be due to the hydrostatic pressure of the reservoir fluids. A density of the HPHT gas condensate may increase due to the increasing hydrostatic pressure, e.g. due to an increase in vertical depth of the wellbore 14.
The insulating fluid 36 may be selected to have the same or similar hydrostatic pressure as gas condensate. Figure 3 illustrates a change of density of the insulating fluid 36, here Nitrogen, with increasing vertical depth due to increasing pressure of the wellbore 14. Here, the change in density and/or the hydrostatic pressure of the insulating fluid 36 may be similar to the change in density and/or hydrostatic pressure of the HPHT gas condensate. This may allow the pressure gradient of the insulating fluid 36 to be matched to the pressure gradient of the HPHT gas condensate to be substantially the same as or similar to the pressure gradient of the gas condensate flowing in the production tubing 22. By adjusting the pressure gradient of the insulating fluid 36 to be substantially the same as or similar to the pressure gradient of the gas condensate, pressure loading, such as in-situ pressure loading, which may be due to production of the reservoir fluids, may be reduced. The pressure gradient of the insulating fluid 36 can also be matched or tracked to a decreasing or increasing pressure (pressure gradient) of the reservoir fluid in the production tubing 22, for example, when the hydrocarbon reservoir depletes over time.
In use, the insulating fluid 36 can be pressurised to a pre-determined pressure and/or specific pressure. At the pre-determined and/or specific pressure, the insulating fluid 36 may minimise thermal loading, e.g. thermal in-situ loading, on the production tubing 22. In this example, the pre-determined and/or specific pressure is in a range of a shut-in pressure, e.g. a pressure measured at or near the wellhead region 24 when the wellbore 14 is closed, to a flowing pressure, measured at or near the wellhead region 24 of the wellbore over the a lifetime of the wellbore, and/or to a minimum surface back pressure or less.
Referring to Figure 4, there is shown a diagrammatic representation of thermal conductivity of the insulating fluid, here Nitrogen, versus pressure. Each solid line in Figure 4 represents a dependency of the thermal conductivity of Nitrogen on pressure (here shown for a range of about 0 to 14,000psi (about 970 bar)) for a constant temperature, ranging between about 60 to 350 °F (15 to 175 °C). The dotted line in Figure 4 represents the dependency of thermal conductivity on pressure, ranging from a surface pressure of about 5,000psi (about 350 bar) to a bottom hole pressure of about 6,500psi (about 450 bar) in annulus 26 at a constant temperature.
As described above, the pressure and/or pressure gradient of the insulating fluid 36 can be varied or is variable, in use. By pressurising the insulating fluid 36, the thermal conductivity of the fluid may be varied so as to adjust or control the thermal insulating capabilities of the insulating fluid 36. For example, by increasing a pressure of the insulating fluid in the space, a thermal conductivity and/or density of the insulating fluid 36 may increase, as shown in Figure 4. Alternatively, a decrease in a pressure of the insulating fluid 36 in the space 26 may provide a decrease of a thermal conductivity and/or density of the insulating fluid, which may increase a thermal insulation between the production tubing 22 and a well system 12.
Referring to Figures 5(a) and 5(b), the production string 22 can include an insulating chamber 40. Here, the insulating chamber 40 of the production string 22 provides a second insulating, e.g. thermally insulating, barrier or region between an interior of the production tubing 22 and the wellbore system 12. By providing the first and/or second thermally insulating barriers or regions between the production tubing 22 or interior thereof and the wellbore system 12, transfer of heat/thermal energy between the production tubing 22 and wellbore system 12 may be reduced.
The insulating fluid 36 and/or the insulating chamber 40 of the production tubing 22 can minimise heat/thermal energy transfer from the reservoir fluids to the casing strings 16a,16b, liner string 18 and/or the wellbore 14. By minimising heat/thermal energy from being transferred to the casing strings 16a,16b and liner string 18, thermal loading or expansion of the casing strings 16a,16b and/or liner strings 18 may be minimised. The first and/or second insulating barriers may lead to a reduction of thermal heating of the casing strings 16a, 16b and/or liner string 18, which may reduce or minimise weakening of the structural properties of the wellbore system 12, including the casing strings 16a, 16b and/or liner string 18.
Referring to Figure 5, the insulating chamber 40 surrounds the production tubing 22. It will be appreciated that in further examples, the insulating chamber 40 may at least partially surround the production tubing 22. The insulating chamber 40 can be an annular insulating chamber 38, extending at least partially along the length of the production tubing 22. Here, the insulating chamber 40 is integral with the production tubing 22. It will be appreciated that in further examples, the insulating chamber 40 may be separate from the production tubing 22. In some examples, the insulating chamber 40 can comprise a vacuum or partial vacuum. Alternatively, the insulating chamber 40 may comprise a third fluid, such as an (inert) gas or the like. By providing the production tubing 22 with an insulating chamber 40, heat and/or thermal energy transfer from the reservoir fluids to the wellbore system may be minimised or reduced.
Figures 5 (a) and 5 (b) show an example of a connection 42 between one or more portions of the production tubing 22 (two shown In Figure 5 (a) and 5 (b)). In this example, each production tubing portion 22a,22b includes at least part of the insulating chamber 40, which is formed between an inner production tubing 23a and an outer production tubing 23b of the two production tubing portions 22a,22b. The insulating chamber can be closed or sealed by welding together the inner production tubing 23a and outer production tubing 23b, as shown in Figures 5 (a) and 5 (b). Welding points between the inner and outer production tubing 23a,23b are indicated by reference numeral 44 in Figures 5 (a) and 5 (b). It will be appreciated that in further examples, the insulating chamber 40 may be sealed by one or more bonds or joints or the like. The connection 42 between the production tubing portions 22a,22b may be thermally insulated to minimise heat transfer from the reservoir fluids flowing in the production tubing 22 to the wellbore system 12 via coupling thermal cover 42.
Referring to Figures 1 and 6(a) to 6(b), as described above, the production packer 28 is located above the reservoir 20 and confines insulating fluid 36 within the annulus 26, by preventing downhole flow of the insulating fluid 36.
In use, the production packer 28 provides a substantially pressure (tight) seal to maintain a pressure of the insulating fluid 36 in the annulus 26.
The production packer 28 orients and maintains a position of the production tubing 22 within the casing strings 16a, 16b and/or liner string 18. Figures 1, 6(a) to 6 (c) show different examples, of deployment of the production pack 28 in the wellbore system 12. Figures 1 and 6(c) show the production packer 28 in engagement with the liner string 18, whereas Figures 6(a) and 6(b) show the production packer in engagement with casing string 16b. It will be appreciated that in further examples, the production packer may be located a different positions in the wellbore system 12. The production packer 28 can orient and/or maintain a position of the production tubing 22 within the casing string 16b and/or liner string 18.
As described above, the tubing hanger 32 may function as a seal of an upper region of the annulus 26. The tubing hanger 32 restricts or prevents uphole flow of the insulating fluid 36 from the annulus 26 and can maintain a pressure of the insulating fluid 36 in the annulus 26. In use, the tubing hanger 30 provides a substantially further pressure (tight) seal to maintain a pressure of the insulating fluid 36 in the annulus 26.
In this example, the production tree 34 is configured to control, adjust and/or maintain a pressure of the insulating fluid 36 in the annulus 26. The production tree 34 can be configured to control, adjust and/or maintain a pressure of the reservoir fluids in the production tubing 22.
Referring to Figure 1 (b), the system 10 can include a vessel or chamber 46, which may be a pressure vessel or chamber and can be part of or included in the controller 38. The vessel 46 is in communication with annulus 26 via the production tree 34 and wellhead 30. The vessel or chamber 46 includes a source or reservoir 48 of the insulating fluid 36. In this example, the vessel 46 is located on a seabed. In other examples, the vessel may be located on a surface structure, such as an offshore platform, vessel or the like.
The system 10 includes a pump or compressor arrangement 50, which may be included in the controller 38. The pump or compressor arrangement 50 is adapted to pump and/or inject the insulating fluid 36 from the source 48 into the annulus 26. The pump or compressor arrangement 50 can also be adapted to vent the insulating fluid 36 from the annulus 26, for example back into the source 48. The pump or compressor arrangement 50 can be configured to adjust the pressure of the insulating fluid 36 in the annulus 26. In some examples, the pump or compressor arrangement 50 may be part of the production tree 34. In other examples, the pump or compressor arrangement 50 is located separately from the production tree 34. Here, the controller 38 controls injection of the insulating fluid 36 into the annulus 26 and/or venting of the insulating fluid 36 from the annulus 26, thereby adjusting the pressure of the insulating fluid 36 in the annulus 26.
In use, the controller 38 can control a flow or flow rate of the insulating fluid 36 into the annulus 26 and/or from the annulus 26. In use, the controller 38 can adjust, vary and/or control the flow or flow rate of the insulating fluid 36 to at least partially fill or substantially fill the annulus 26. In some examples, the flow or flow rate of the insulating fluid is controlled, adjusted and/or varied by the controller 38 based on properties of the well system 12, such as a length or depth of the annulus 26, radial extension of the annulus 26 or diameter of the wellbore 14 and/or a volume of the annulus 26. In use, the controller 38 adjusts, varies and/or controls the flow or flow rate of the insulating fluid 36 to minimise heat transfer between the production tubing 22 and the well system 12. For example, the controller 38 may adjust, variy and/or control the flow or flow rate of the insulating fluid 36 in the annulus 26 to reach a specific and/or pre-determined value of the flow rate, at which heat transfer between the production tubing 22 and the well system 12 may be minimised and/or decreased.
In use, the controller 38 can control a temperature of the insulating fluid 36 injected and/or circulated in the annulus 36. The controller 36 can adjust, vary and/or control the temperature of the insulating fluid 36, which is injected and/or circulated in the annulus 26, to minimise heat transfer between the production tubing and a well system 12. For example, a decrease in temperature of the insulating fluid 36 in the annulus 26 can cause or lead to a decrease in thermal conductivity of the insulating fluid 36, thereby decreasing heat transfer between the production tubing and the well system 12. In some examples, the temperature the insulating fluid 36, which is injected and/or circulated in the annulus is about or below 273.15 K (0° C), e.g. to below 200 K (-73 °) or below 100 K (-173 °C). It will be appreciated that in further examples, the temperature of the insulating fluid may be above 273.15 K (0° C). By controlling, varying and/or adjusting the temperature of the insulating fluid in the annulus 26, the thermal conductivity of the insulating fluid 36 may be varied.
In use, the controller 38 can adjust, vary and/or control the temperature of the insulating fluid 36, which is injected and/or circulated in the annulus 26, to reach a specific and/or pre-determined value of the temperature. At the specific and/or predetermined value of the temperature, heat transfer between the production tubing 22 and the well system 12 may be minimised and/or decreased.
In use, in the controller 38 can vary, adjust and/or control the temperature and/or flow rate of the insulating fluid 36, which is injected and/or circulated in the annulus 26 to vary and/or control a temperature of the production tubing 22 and/or the reservoir fluid within the production tubing 22. In some examples, a decrease in temperature of the insulating fluid 36, which is injected and/or circulated in the annulus 26 leads and/or causes a decrease in temperature of the production tubing 22 and/or the reservoir fluid within the production tubing 22. In other examples, an increase in the flow rate of the insulating fluid 36, which is injected and/or circulated in the annulus 26 can lead and/or cause a decrease in temperature of the production tubing 22 and/or the reservoir fluid flowing within the production tubing 22. It will be appreciated that in further examples temperature and/or the flow rate of the insulating fluid 36 may be varied, adjusted and/or controlled to cause or lead a change in temperature, such as decrease in temperature, of the production tubing 22 and/or the reservoir fluid.
Referring back to Figure 1 (a), the system 10 includes the first conduit 52a for injecting the insulating fluid 36 into the annulus 26. It will be appreciated that in further examples, the first conduit 52a may also direct or transfer the insulation fluid from the annulus 26 to source 48. The first conduit 52a can be part of or included in the production tree and enter the annulus 26 via the tubing hanger 32. The first conduit 52a is disposed in the annulus 26 and is in communication with the pump or compressor arrangement 50 and/or controller 28. Here, the first conduit 52a is attached to the production tubing 22 by one or more clamping members, e.g. coupling clamps and/or cross-coupling clamps or the like (not shown). It will be appreciated that in further examples, the conduit 52 may be releasably attached to the production tubing 22.
As shown in Figure 1 (a), the first conduit 52a extends along the production tubing 22 to above the production packer 28. By extending the first conduit 52a into proximity of the production packer 28, wellbore fluids and/or particles, which may be present in the annulus 26 and/or a wellbore 14 prior to injection of the insulating fluid 36, may be displaced, as will be described below.
In some examples, the system 10 includes a second conduit 52b, which may be disposed in the annulus 26 via the tubing hanger 32, e.g. for returning or venting at least a portion of the insulating fluid 36 to the source 48 of the insulating fluid.
The controller 38 allows for circulation, such as intermittent or continuous, circulation, of the insulating fluid 36 in the annulus 26 via the first and/or second conduit 52a,52b.
In some examples, the insulating fluid 36 is forward and/or reverse circulated, e.g. continuously or intermittently forward and/or reverse circulated, in the annulus 26, e.g. by the controller 38. For example, forward circulation of the insulating fluid 36 can include the insulating fluid 36 being injected into the annulus 26 to above the production packer 28 via the first conduit 52a and vented or transferred from the annulus via the second conduit 52b, or vice versa. Reverse circulation of the insulating fluid 36 can include the insulating fluid 36 being injected into the annulus 26 via the second conduit 52b and vented or transferred from the annulus 26 via the first conduit 52a, or vice versa. By continuously forward and/or reverse circulating the insulating fluid, thermal insulation between the production tubing 22 and the well system 12 may be increased.
Referring to Figures 1 and 6(a) to 6 (c), the system 10 includes a sensing arrangement 52, which can be disposed in the space via the tubing hanger 32. The sensing arrangement 52 can be included in or be part of the controller 38 or the production tree 34. The sensing arrangement may sense, measure and/or monitor a pressure, pressure differential, pressure gradient temperature, temperature gradient and/or temperature differential of the insulating fluid 36 in the annulus 26. The sensing arrangement 52 can be configured to sense, measure and/or monitor a pressure, pressure differential, temperature and/or temperature differential of the insulating fluid 36 at one or more location(s) in the annulus 26, for example along a length of the production tubing 22 and/or between the production tubing 22 and the casing string 16b or tubing string 18.
As shown in Figures 6(a) to 6 (c), the sensing arrangement 52 includes a sensor 54, e.g. a pressure sensor or temperature sensor, which may include a pressure and/or temperature gauge. It will be appreciated that in further examples, the sensor may include an acoustic and/or optical sensor. The sensor 54 may be provided on the production tubing 22, for example at different positions or locations, for sensing, measuring and/or monitoring a temperature and/or pressure of the reservoir fluids flowing in the production tubing 22.
The sensing arrangement 52 can also include an elongate sensor 56, which is attached to the production tubing 22. In some examples, the elongate sensor 56 is fixed to the production tubing 22 by one or more clamping members, e.g. coupling clamps and/or cross-coupling clamps or the like (not shown). Here, the elongate sensor 56 extends along the length of the production tubing 22 to above the production packer 28. The elongate sensor 56 may include a distributed temperature sensing (DTS) and/or distributed pressure sensing (DPS) arrangement for monitoring the temperature and/or pressure of the insulating fluid 36 in the annulus 26. Referring to Figures 6(a) to 6(c), the system 10 includes one or more valves 58, such as downhole valve(s), downhole safety valve(s) and/or lubricator valve(s) or the like, which may be provided on the production tubing 22 for controlling and/or varying flow of the reservoir fluids in the production tubing string 22. It will be appreciated that in further examples the system may comprise one or more further valves (not shown), such as flow control valves or the like, for controlling and/or adjusting the flow of the second fluid in the production tubing 22.
In use, the sensing arrangement 52 communicates a pressure, pressure differential, pressure gradient temperature, temperature gradient and/or temperature differential of the insulating 36 and/or reservoir fluids to the controller 38. In response to a pressure (pressure differential and/or gradient) and/or temperature (temperature differential and/or gradient) determined by the sensing arrangement 52, the controller 38 adjusts a pressure of the insulating fluid 36 so as to achieve or reach a predetermined pressure or pressure differential and/or gradient. The pre-determined pressure can include a pressure differential and/or gradient, e.g. along at least part of a length of the production tubing 22 and/or in the annulus 26, in use.
In response to a pressure (pressure differential and/or pressure gradient) and/or temperature (temperature differential and/or pressure gradient) determined by the sensing arrangement 52, the controller 38 adjusts a pressure of the reservoir fluids in the production tubing 22 so as to achieve or reach a pre-determined pressure or pressure differential and/or gradient, e.g. along at least part of a length of the production tubing 22, in use. For example, a pressure of the reservoir fluids within the production tubing 22 can be adjusted by choking or restricting a flow of the reservoir fluids, e.g. by one or more further valve(s) (not shown), and/or varying a back pressure of the reservoir fluids within the production tubing 22.
A method for installing the system 10 in the wellbore 14 is depicted in Figure 7. As described above, the production packer 28 may be mounted on the production tubing string 22 in the unset or retracted configuration to permit deployment of the production tubing string in the wellbore 14.
Subsequently to locating and/or installing the production tubing 22 in the wellbore 14, the production tree 34 and wellhead 30, including the tubing hanger 32, can be installed to provide a substantially pressure (tight) seal of the insulating fluid 36 in the annulus 26 and preventing up-hole flow of the insulating fluid 36, in use.
Installation of the production tree 34 and wellhead 30 can include the installation of the controller. The first and/or second conduits 52a,52b are disposed in the annulus 26 through the tubing hanger 32. The sensing arrangement may be installed by deploying the elongate sensor 56 and/ or sensor 54 in the annulus 26. In some examples, the sensor 54 may be pre-installed on the production tubing 22.
Subsequent to installation of the controller 38 and/or the sensing arrangement 52, the insulating fluid 36 is injected into the annulus 26 using the first and/or second conduits 52a,52b, thereby displacing wellbore fluids and/or particles contained within the annulus 26. The wellbore fluids may include water, brine, drilling mud or combinations thereof, which were injected during drilling and/or completion of the wellbore 14. By displacing the wellbore fluids from the annulus 26, damage and corrosion of the production tubing 22 and/or the wellbore system 12 may be reduced or even prevented.
Once installed at a desired position in the casing strings 16a,16b and/or liner string 18, the production packer 28 can be set. For example, the production packer 28 can be set by actuating, such as hydraulically and/or mechanically actuating, the production packer 28 from the retracted configuration to an expanded configuration. In the expanded configuration of the production packer 28, the production packer 28 engages with the liner string 18, as shown in Figure 1 (a). It will be appreciated that in further examples, the production packer 28 may engage with the casing strings 16b, as shown in Figures 6 (a) and 6 (b).
It should be understood that the embodiments described herein are merely exemplary and that various modifications may be made thereto without departing from the scope of the invention.
For example, the tubular member may be or comprise tubing, such as production tubing, a conduit, casing, conductor or the like.
The further tubular member may comprise a casing string, liner, conduit, conductor or the like.
It will be appreciated that in further examples, the lower region of the annulus may be sealed by a plug, flow control device or the like.
It will also be appreciated that in further examples, the upper region of the annulus may be sealed by a further packer, plug, flow control device or the like.
In alternative examples, the first conduit and/or second conduits may include a hose, pipe, tubular, umbilical or the like.

Claims

A wellbore arrangement (10) for controlling heat transfer between a tubular member (22) located in a wellbore (14) and a well system (12), the arrangement (10) comprising:
a tubular member (22) arranged to transport a produced fluid from a subterranean reservoir (20) to a surface structure, wherein the produced fluid comprises or exhibits a pressure gradient in a direction along the length of the tubular member (22);

a lower member (28) provided between the tubular member (22) and a wall (18) of a well system (12);

a space (26) extending in an uphole direction from the lower member (28) and between the tubular member (22) and a wall (18) of the well system (12);

an insulating fluid (36) at least partially filling the space (26); and

a control arrangement (38) for adjusting a pressure of the insulating fluid (36) in the space (26) such that a pressure gradient of the insulating fluid (36) in a direction along the length of the tubular member (22) is controlled to match or track the pressure gradient of the produced fluid.
The wellbore arrangement according to claim 1, wherein the control arrangement (38) is operable to facilitate control of heat transfer between the tubular member (22) and the well system (12) and/or a wellbore formation (14) adjacent the well system.
The wellbore arrangement according to claim 1 or 2, wherein the control arrangement (38) is operable to intermittently or continuously circulate the insulating fluid (36) in the space (26), optionally
wherein the insulating fluid (36) is forward and/or reverse circulated in the space (36).
The wellbore arrangement according to any preceding claim, wherein the insulating fluid (36) comprises or defines a low thermal conductivity fluid, optionally
wherein the insulating fluid (36) comprises at least one of Nitrogen, Krypton, Argon and Xenon.
The wellbore arrangement according to any preceding claim, wherein the insulating fluid (36) assists to minimise heat transfer from the produced fluid to the well system (12) and/or a wellbore formation (14).
The wellbore arrangement according to any preceding claim, wherein the pressure gradient of the produced fluid is matched or tracked by selecting an insulating fluid (36) comprising substantially the same or similar hydrostatic pressure as the produced fluid.
The wellbore arrangement according to any preceding claim, wherein the tubular member (22) is configured to reduce transfer of thermal energy/heat from the produced fluid contained or flowing therein to the well system (12) and/or a wellbore formation (14), optionally wherein the tubular member (22) comprises an insulating chamber (40) for minimising heat/thermal energy transfer from the produced fluid to the well system (12).
The wellbore arrangement according to any preceding claim, wherein the lower member (28) provides a seal between the tubular member (22) and the well system (12), optionally
wherein the lower member (28) comprises a production packer.
The wellbore arrangement according to any preceding claim, comprising an upper member (32), wherein the space (26) is an annular space extending between the lower (28) and upper (32) members, wherein the upper member (32) provides a further seal to flow of the insulating fluid (36) in an uphole direction, optionally
wherein the upper member (32) comprises a tubing hanger.
The wellbore arrangement according to any preceding claim, comprising a vessel or chamber (46) comprising a source (48) of the insulating fluid (36).
The wellbore arrangement according to any preceding claim, comprising at least one pump and/or compressor arrangement (50) configured to control the pressure of the insulating fluid (36) in the space (26).
The wellbore arrangement according to any preceding claim, comprising at least one first conduit member (52a) for directing and/or transferring the insulating fluid (36) to/from the space (26), the first conduit member (52a) extending along the length of the tubular member (22) to above the lower member (28).
The wellbore arrangement according to any preceding claim, comprising at least one sensing arrangement (52) disposed or provided in the space (26) and/or on the tubular member (22).
A method for controlling heat transfer between a tubular member (22) located in a wellbore (14) and a well system (12), the method comprising:
locating a tubular member (22) within the wellbore (14);

providing a lower member (28) between the tubular member (22) and a wall (18) of the well system (12);

flowing a produced fluid through the tubular member (22) from a subterranean reservoir (20) to a surface structure, wherein the produced fluid comprises or exhibits a pressure gradient in a direction along the length of the tubular member;

at least partially filling a space (26) with an insulating fluid (36), the space (26) extending in an uphole direction from the lower member (28) and between the tubular member (22) and a wall (16b) of a well system (12), and

adjusting a pressure of the insulating fluid (36) in the space (26) such that a pressure gradient of the insulating fluid in a direction along the length of the tubular member (22) is controlled to match or track the pressure gradient of the produced fluid.
The method according to claim 14, comprising adjusting, varying and/or modifying the pressure gradient of the insulating fluid (36) to match or track the pressure gradient of the produced fluid.