GB2624407A

GB2624407A - A method of deploying a fluid heater downhole

Info

Publication number: GB2624407A
Application number: GB2217125.0A
Authority: GB
Inventors: William Mcnay Graeme; Simmister Nicholas; Lawrence Ray
Original assignee: Cavitas Energy Ltd
Current assignee: Cavitas Energy Ltd
Priority date: 2022-11-16
Filing date: 2022-11-16
Publication date: 2024-05-22
Also published as: WO2024105175A1; GB202217125D0

Abstract

A method of installing a fluid heater within a wellbore 10, the method comprising: installing a fluid heater 20 within a wellbore that comprises a wellbore casing 18 and a production tubular 14 disposed within the production casing; connecting a rotary fluid heater 24 to a deployment member 25; and, deploying the rotary fluid heater into the wellbore through the production tubular. A fluid heating system is also claimed. The thermal output of the heater may be changed by varying the rotational speed of the heater, the heater may be modular, comprise a motor, and comprise a plurality of heaters arranged in series.

Description

A Method of Deploying a Fluid Heater Downhole

FIELD

Described examples relate to methods of installation of fluid heaters, and in particular methods for installing fluid heaters in subterranean wellbores.

BACKGROUND

Significant innovation and advancements have occurred in recent years in relation to enhanced oil recovery, not only for unconventional reservoirs but also for mature fields or the like.

However, there is a continuing desire to ensure that the processes and apparatus used during enhanced oil recovery are safe, reliable, efficient and effective. For example, if the costs involved are significant, then those costs may outweigh any gains made in

developing or maintaining particular fields.

One known method of enhanced oil recovery involves the use of one or more fluid heaters disposed within a wellbore to alter the viscosity of downhole fluids found therein; to facilitate easier recovery to surface. By reducing the viscosity of downhole fluids, this may provide access to downhole fluids that were previously deemed unrecoverable', given the requirements of the pumping equipment that would be required to pump said fluids to surface, and the limited space available in the wellbore for such equipment.

Fluid heaters are commonly deployed at the lower end of production tubing installed either within a lined or open wellbores, such that produced fluid is heated at the point of entry into the production tubing, which is typically at an extended depth within the wellbore. As such, the heating effect will typically be concentrated in one area of the well, which might not necessarily facilitate optimised use of the heater. For example, optimised enhanced recovery and well management may actually require heating to be applied at a different location, other than the lower end of the production tubing.

In hydrocarbon production wells blockages can occur, often by the formation of wax blockages or liquid plugs caused by gas at a dew point in a well. Such blockages are undesirable as these may inhibit or even prevent production of wellbore/reservoir fluids.

However, blockages can be particularly problematic as it may be difficult to predict where these may occur within the wellbore, thereby making them difficult to mitigate against or resolve with downhole equipment, such as heaters, that may already be in-situ at a fixed location within the wellbore.

Known techniques to address the issue of blockages includes heating the produced fluid using a fluid heater already disposed at the end of a production tubing string to heat produced fluid at the point of entry into the string to remove the blockage by either melting the wax build up or returning the liquid plug to a gas state. This solution can be particularly inefficient, however, in view of the depths that the fluid heater may be disposed at. For example, a heater disposed at the lower end of a production tubular 3000m in length may be required to heat a fluid within a wellbore or production tubular to a clear a blockage 250m to 500m from surface. This means that, due to heat loss along the production tubular, the fluid towards the bottom of the production tubular (e.g. adjacent the fluid heater) must be heated to very high temperatures. A further downside of heating wellbore fluid in this manner is that there is a chance of overheating lower sections of the well, as wells as deep as 3000m are often already at the standard temperature limit for non-thermal cement, for example.

In wells that may not have a fluid heater present, and which subsequently require heating operations after the wellbore has been constructed, one proposed solution may be to pull the production tubular from the wellbore, and reinstall with a fluid heater installed thereon. This solution is not preferred, however, as it is likely highly expensive, and requires much 'down-time' for the reservoir. Further, given the lifting the capacity required to pull a tubular from a wellbore, appropriate lifting and other equipment may not be available to the operator to pull tubing from a wellbore, at least not within a viable timescale.

SUMMARY OF THE INVENTION

According to a first aspect of the present disclosure there is provided a method of installing a fluid heater within a wellbore that comprises a first tubular and a second tubular, wherein the second tubular is disposed within the first tubular, the method comprising: connecting a fluid heater to a deployment member; and deploying the fluid heater into the wellbore through the second tubular.

In the present example the fluid heater is thus deployed through the second tubular, which as noted below may define or comprise a production tubular. As such, the heater may be considered to be through-tubing deployable.

Deploying a fluid heater in a wellbore in this manner (i.e., through-tubing) may provide flexibility regarding the location within the wellbore that the fluid heater may be positioned. For example, deploying a fluid heater in this manner may allow the heater to be positioned at a specific location along the second tubular, and thus along the wellbore. This may allow a specific location within the wellbore to be heated, thus seeking to optimise wellbore operations and efficiencies. For example, facilitating the ability to locate the heater at a specific location within the wellbore may allow blockages such as wax build-ups and/or liquid plugs to be more directly heated and thus cleared. This may therefore provide a more focussed and efficient method of heating a wellbore, wherein only the area of interest is heated.

Heating a specific location within the wellbore may also be beneficial in mitigating against overheating of wellbore infrastructure or fluids. For example, a fixed heater remotely positioned from the point of interest may be required to apply excessive heating at the fixed location to maximise the prospect of sufficient thermal energy being available at the point of interest. This may result in regions of the wellbore being heated excessively (e.g. the regions adjacent the heater) which may cause damage to infrastructure or other operational issues. Using a heater that may be positioned to heat specific or targeted locations by virtue of being deployed through-tubing may mitigate against such over-heating, and, as outlined above, may provide more efficient means of heating fluids in a wellbore when clearing blockages.

Furthermore, by facilitating the ability for more targeted heating, the energy requirements (e.g., electrical energy requirements) may also be reduced.

Further, deploying a heater within a wellbore in the manner disclosed herein may allow the heater to be more readily repositioned in the wellbore by simply extending or retracting the deployment member. This may mean that multiple wellbore operations can be completed during a single trip of the heater into the wellbore. For example, the heater may be deployed into the wellbore to clear a blockage within a production tubular that may be impeding or preventing production. Once the blockage has been cleared, the heater may be lowered into the wellbore to heat the wellbore production fluid, by reducing its viscosity and allowing it to be pumped to surface more easily. Alternatively, the heater may be deployed into the wellbore to lower the viscosity of the wellbore production fluid. If a blockage is to occur in the wellbore during production, the heater may be relocated within the wellbore to remove the blockage, before being returned to its original position to resume production of the wellbore fluid.

The method may comprise locating the heater at a first location. Subsequently, the method may comprise operating the heater to apply heat within the second tubular at the first location.

The method may comprise relocating the heater within the wellbore, to a second location. Subsequently, the method may comprise applying heat within the second tubular at the second location.

The method may comprise returning the heater to the first location within the wellbore. Alternatively, the heater may be relocated to a third location within the wellbore. At said third location, heat may be applied within the second tubular by operating the heater.

The fluid heater may be moved to any number of subsequent locations, and heating operations may be performed at each location.

The present disclosed method may also reduce/prevent downtime of wells when a fluid heater is required. Previously, the production tubing within the well may have required to be pulled from the well and redeployed with a heater installed thereon. Pulling tubing from a well may be prohibitively expensive and/or overly time consuming to justify carrying out such an operation. Therefore, hydrocarbons that require heating (e.g. to lower their viscosity) to be recovered from the wellbore may be abandoned. Using a heater that may be deployed through a second tubular (e.g. a production tubular) may allow for a fluid heater to be installed without removal of the second tubular.

The first tubular may be casing or liner. The casing or liner may line a drilled wellbore. If a liner is used, the liner may be a production liner, allowing production fluid to flow from a reservoir in which the wellbore is drilled.

The second tubular may be fixed within the first tubular within the wellbore. The second tubular may be fixed in the first tubular with one or more packers disposed between the first and second tubulars. The second tubular may be fixed in position within the first tubular via any suitable means, such as via slip systems, anchor systems and/or any or system or means within the understanding of the skilled person.

An annulus may be formed between the first and second tubulars. In some examples, the method may comprise producing fluids along the annulus formed between the first and second tubulars.

The second tubular may be a production tubular. The second tubular may be used to transport fluids produced from the reservoir to surface. The fluid heater may be used to lower the viscosity of the production fluid within the second tubular. The heater may be used to heat a fluid within the second tubular to clear a blockage within the second tubular, such as wax build-up and/or the like.

The wellbore may comprise a fluid drive arrangement. The fluid drive arrangement may be disposed within the wellbore. The fluid drive arrangement may comprise one or more pumps, such as electric submersible pumps (ESPs). The method may comprise driving a fluid towards the fluid heater. The fluid drive arrangement may be configured to drive fluid to surface. The method may further comprising driving the fluid to the fluid heater via the fluid drive arrangement to be heated. The fluid drive arrangement may drive a heated fluid to surface. The fluid drive arrangement may be disposed at surface. The fluid drive arrangement may comprise a pumping arrangement disposed both within the wellbore and at surface.

The fluid heater may comprise a rotary fluid heater. The fluid heater may be of the type of rotary heater described within International Patent Application W02020/104819 Al, the disclosure of which is incorporated herein by reference. The fluid heater may comprise a fluid heating assembly. The heating assembly may comprise a heating chamber for receiving a heat transfer fluid. The fluid heating assembly may be configured to agitate fluid (e.g. mechanically agitate fluid) in the heating chamber so as to impart thermal energy and heat the fluid. Such agitation may occur by a number of alternative mechanisms. The agitation of the fluid may comprise exerting a force on the fluid so as to cause cavitation of the fluid. The force exerted on the fluid may be, for example, a shearing force. The heat transfer fluid may be any appropriate fluid. For example, the heat transfer fluid may be an oil.

The heater may comprise a first portion and a second portion arranged such that the first portion and the second potion define the heating chamber therebetween. At least one of the first portion and the second portion may comprise surface features, for example, provided in the heating chamber.

The fluid heating assembly may be configured such that the first and second portions are moveable relative to each other. Such relative movement may, in turn, cause relative movement of the surface features located in the heating chamber. As such, the fluid heating assembly, or indeed the first and second portions, may be configured to agitate fluid in the heating chamber. Such agitation may be used to impart thermal energy and heat the fluid. In similar words, the fluid heating assembly may essentially be configured to convert mechanical energy into thermal energy, for example, downhole (e.g. at a specific location downhole).

The method may comprise varying the speed (RPM) of the rotary heater dependent on the thermal energy required to be provided by the fluid heater; for example, to change the viscosity of a fluid to a 'recovery viscosity'. For example, when recovering a first wellbore fluid with a first viscosity, the method may comprise operating the heater at a first RPM to heat the fluid to its 'recovery viscosity'. When recovering a second fluid with a second viscosity, the method may then comprise operating the heater at a second RPM to heat the fluid to ensure its viscosity is at the 'recovery viscosity'. This may mean that the speed of the fluid heater is adjustable in-situ to suit the application (e.g. the fluid) for which it is required.

The method may comprise configuring the rotary heater to heat a wellbore fluid in order to remove a blockage within the wellbore. This may involve selecting the speed of the rotary heater dependent on the type of blockage present within the wellbore, such as the composition of the blockage, the location of the blockage, the size of the blockage and/or the like.

The method may comprise positioning the fluid heater within a wellbore to heat a production fluid in order to lower its viscosity and enhance recovery. The method may comprise repositioning the heater to clear a blockage within the second tubular. For example, the method may comprise selecting the RPM of the heater that efficiently allow the blockage to be sufficiently cleared, wherein the speed required to clear the blockage may differ from that required to lower the viscosity of the production fluid for enhanced recovery.

The method may comprise heating a fluid to be injected downhole. This may comprise delivering a fluid to the heater by a fluid drive arrangement (e.g. fluid pumps). This may further comprise injecting said heated fluid down a production tubular and into the reservoir. Said heated fluid may be used for cleaning purposes of the well.

The method may comprise deploying the heater via a reelable deployment member.

The deployment member may be any deployment member used in deploying tools into a wellbore, within the understanding of the skilled person. Using a deployment member that may be deployed from a reel may help to reduce the footprint of the deployment apparatus. This may be beneficial when the deployment member is located upon a floating vessel, or road vehicle, wherein space may be limited.

The method may comprise deploying the fluid heater via a wireline deployment member. Using a wireline deployment member may be advantageous as it may serve to both power the fluid heater (and any ancillary equipment connected to the heater, such as a motor), while also acting as the deployment member. Given the relatively low diameters of wireline deployment members, the footprint of a wireline deployment member when in a storage configuration (e.g. when it is disposed upon a reel) is relatively small. This may make deployment using a wireline means of deployment a highly versatile method of deployment given that wireline deployment equipment can be disposed upon a wide variety of vehicles or vessels, given its relatively small footprint.

The method may comprise deploying the fluid heater via a slickline deployment member. The slickline deployment member may be a braided wire rope, or the like. The slickline deployment member may be any slickline deployment member within the understanding of the skilled person. A slickline deployment equipment may occupy a relatively small footprint on the vessel or vehicle upon which it is disposed. Slickline deployment may offer a highly versatile method of deployment, as slickline deployment equipment can be disposed on a wide variety of vehicles or vessels, given its relatively small footprint. Slickline deployment may offer a more cost effective solution for deployment of tools into a wellbore than others currently used within the oil and gas industry, such as the use of a workover unit.

The method may comprise deploying the heater via one or more self-supporting cables. The self-supporting cable may be or form part of the deployment member. The self-supporting cable may comprise one or more electrical conductors within a jacket, wrap or the like, such as a metal jacket or wrap or the like. The jacket or wrap may be formed of corrosion resistant steel. This may allow the self-supporting cable to withstand the corrosion related damage in the downhole environment and be resistant to mechanical forces, such as crushing, whilst also remaining flexible. Further, providing electrical conductors within the self-supporting cable may allow power to be transmitted to the fluid heater that is being deployed on the self-supporting cable. The self-supporting cable with the capability of delivering power to a downhole fluid heater may have any configuration within the understanding of the skilled person.

Self-supporting cable deployment equipment may also occupy a relatively small footprint on the vessel or vehicle upon which it is disposed. Self-supporting cable deployment may offer a highly versatile method of deployment, as self-supporting cable deployment equipment can be disposed on a wide variety of vehicles or vessels, given its relatively small footprint. This deployment method may also offer a deployment member with a high tensile strength, which also has the capability to deliver power to a downhole fluid heater.

The method may comprise installing the fluid heater via coiled tubing. This may be beneficial as coiled tubing can be used to support a degree of axial compression, which may allow pushing forces to be imparted on the heater deployed within the wellbore, which may facilitate deployment in deviated wellbores. For example, when deploying the heater, restrictions may be present within the tubular through which the heater is being deployed. Therefore, by having a deployment member such as coiled tubing that may be able to impart pushing forces on the heater during deployment, said restrictions may be overcome. Further, in a case wherein the outer diameter of the heater is only marginally smaller than the inner diameter of the tubular through which the heater is to be deployed, pushing forces may be required at times to advance the heater along the tubular to its desired location.

The method may further comprise producing wellbore fluids to surface along the coiled tubing upon which the heater has been deployed.

The method may comprise installing the fluid heater disposed on a rod string. The rod string may comprise an extended length of spoolable rod. The rod string may comprise a plurality of interconnected rods, forming a string, of a length that allows the fluid heater to be deployed to a required location within the wellbore. Rods may be added or removed from the rod string to alter the position of the heater within the wellbore. The rods may be configured to withstand environmental conditionals found within the wellbore. For example, the rods may be formed of a material that is corrosion resistant and/or resistant to high temperatures. Further, the rods may be formed of a material that allows for sufficient elastic deformation of the rod string to allow the fluid heater to be deployed in a wellbore that may be deviated. The rods may be formed of any suitable material within the understanding of the skilled person.

One or more electrical cables to power the fluid heater may be deployed with the rod string. For example, one or more electrical cables may be attached to the rod string. One or more electrical cables may be banded to the rod string, and/or attached via any suitable means within the understanding of the skilled person.

The method may comprise using the deployment member to retain the fluid heater in a desired position within the wellbore. For example, the method may comprise deploying the fluid heater to a required location within a wellbore, for example to clear a blockage, such as a wax blockage, as described above. Once the fluid heater has reached the desired location, the deployment member may be used to hold the heater in said location until the blockage has been cleared. This may avoid or reduce the requirement for alternative anchoring means, such as slips, hangers and/or the like, although in some examples additional anchoring means may be utilised.

The method may comprise anchoring or fixing the heater in place with the wellbore following deployment. Following anchoring or fixing the heater in place, the method may further comprise detaching the deployment member. The deployment member may then be retracted from the wellbore.

Optionally, the method may further comprise reattaching the deployment member to the heater. The anchoring or fixing means (such as those described above) may then be removed, and the heater repositioned within the wellbore, or being recovered to surface. Having the ability withdraw and redeploy the deployment member is advantageous, as this mitigates against the deployment member obstructing fluid flowing within the second tubular, or the deployment member being damaged by fluid flowing within the second tubular once the heater is at its desired location.

The method may comprise deploying the heater into an offshore subsea wellbore. The method may comprise deploying the heater from a floating production, storage and offloading vessel (FPSO), jack-up rig, semi-submersible rig, or the like. Alternatively, the method may comprise deploying the heater from fixed offshore platform. Given the simplicity of the deployment means of the fluid heater (e.g. wireline, slickline or coiled tubing deployment), heavy lifting equipment may not be required to deploy the heater downhole. Such heavy lifting equipment for downhole deployment may only be commonly found on offshore oil and gas rigs, such as jack-up, semi-submersible or fixed platforms. Therefore, the heater may be deployed from a wide variety of offshore vessels -even those that do not have heavy lifting equipment for downhole deployment. Therefore, it can be said that the fluid heater may be installed and retrieved using conventional light intervention equipment, such as those described in the examples above, or any others within the understanding of the skilled person.

Alternatively, the method may comprise deploying the heater into an onshore subterranean wellbore. The heater may be deployed from a land vehicle, such as an articulated heavy goods vehicle (HGV) or the like.

The method may comprise deploying a centraliser with the heater when the heater is deployed into the wellbore. Deploying the heater with a centraliser may allow the heater to be maintained substantially concentrically within the second tubular. By doing so, fluid may pass evenly around the heater, and the heater may provide uniform heating to the fluid within the second tubular, and/or fluid surrounding the heater, and/or fluid being delivered to the heater.

The method may comprise deploying the heater into a wellbore as part of a heater system. Said heater system may comprise a motor connected to the fluid heater. The motor may be any motor suitable for use with a downhole fluid heater, within the understanding of the skilled person. The method may comprise deploying the heater system with the motor being deployed uphole of the fluid heater. The motor may be an electric motor. The motor may be an alternating current motor. The alternating current motor may be a permanent magnet motor. Use of a permanent magnet motor may be advantageous as such a motor is generally small and lightweight, offering a high speed range and regulation. Therefore, when a permanent magnet motor is used with a rotary fluid heater, a wide range of heater speeds may be achieved, which may be more easily regulated than with traditional induction motors. Further, permanent magnet motors may have a small moment of inertia. Therefore, when a permanent magnet motor is used to power a rotary heater, the high acceleration of both the motor and the heater may be obtained. Given the relatively large power output that may be achieved in relation to the size of a permanent magnet motor, a permanent magnet motor may also be used to improve the efficiency of heating a fluid downhole.

Alternatively, the motor may be a direct current motor. Power may be supplied to the motor via a wireline connected from surface to the motor. The wireline may also be used as the deployment member for the motor and the heater. Alternatively, power may be supplied to the motor via one or more batteries, or a power source disposed within the wellbore.

Alternatively, the motor may be a hydraulic motor. One or more hydraulic control fluids may be delivered to the motor via a flow path. Said flow path may be formed of coiled tubing. The coiled tubing may also function as the deployment member for the motor or for the motor and the heater. Use of a hydraulic motor with a rotary heater may be advantageous. Hydraulic motors may offer quick and easy speed adjustments over a wide range of speeds, while the power source may be operating at a constant, more efficient speed. Further, using a hydraulic motor may offer smooth acceleration or deceleration of the fluid heater, thereby helping to prolong the life of the downhole fluid heater. Hydraulic motors may also offer superior control of the maximum torque and power output by the motor, which thereby may offer improved control of the downhole fluid heater to which the motor may be connected. Use of a hydraulic motor in connection with a downhole fluid heater may also avoid deploying electric cables into the wellbore environment, which may not always be desirable.

Alternatively, the method may comprise deploying the motor downhole separately from the fluid heater, with the method further comprising connecting to the motor to the heater at or near the location at which the heater is required.

The method may comprise measuring the temperature within the wellbore. The temperature measured within the wellbore may be the temperature of the fluid within the second tubular, which is to be recovered. By measuring the temperature of the fluid within the second tubular that is to be recovered, it can be determined if the fluid is at the correct viscosity to be recovered to surface. If it is determined that the fluid to be recovered is not at the correct viscosity (i.e. given its temperature), action may be taken to alter the viscosity of the fluid. The RPM of the fluid heater may be changed to alter the temperature of the fluid -e.g. the RPM of the heater may be increased to increase the temperature of the fluid, and thereby increase the viscosity of the fluid.

The method may comprise measuring the pressure within the wellbore. By measuring the pressure within the wellbore, an indication may be provided of a blockage/partial blockage present within the wellbore, for example by showing an increased pressure within the second tubular; which may be stopping/hindering production.

Measuring downhole pressure may provide an indication of the rate of delivery of fluid to surface. For example, a drop in the dynamic pressure of fluid being delivered to surface may indicate that less production fluid is being recovered due to increased viscosity of the production fluid. Therefore, this pressure measurement may be used to determine the required speed of the downhole fluid heater. For example, the RPM of the fluid heater may be increased to reduce the viscosity of the production fluid, to thereby increase the rate at which fluid is delivered to surface (which in turn provides an increase in the dynamic pressure measurement taken from the production fluid).

The method may comprise delivering one or more gauges downhole to the location of the fluid heater. The method may comprise delivering one or more gauges downhole with the fluid heater.

The method may comprise using said one or more gauges to provide temperature measurements within the wellbore. The method may comprise using said one or more gauges to provide pressure measurements within the wellbore. The method may comprise using said one or more gauges to provide both the temperature and pressure measurements within the wellbore.

The readings provided by the one or more gauges may be used in the control of the speed (RPM) of the heater, as outlined above. For example, the readings provided may be used as input data for a feedback control loop for controlling the RPM of the heater (e.g. said readings may be interpreted by an operator who uses the data to remotely alter the RPM of the heater).

The readings provided by the one or more gauges may be used to autonomously control the RPM of the heater, without the need for user/operator intervention. For example, readings may be taken by the one or more gauges at set intervals, with said readings being used as the data input of a feedback control loop, to provide both autonomous and remote control the RPM of the fluid heater. The RPM of the heater may be altered accordingly, based on the user input limits and/or requirements, and the input data provided by the one or more gauges. Such a data feedback based control system may be a Supervisory Control and Data Acquisition (SCADA) system, although any appropriate control system or methodology that allows input data provided by one or more gauges to be used for the purposes of autonomous and/or remote control may be used.

The method may comprise installing the heater in an inverted orientation. If the heater is installed in an inverted orientation, the method may further comprise disposing a motor downhole of the heater to drive the fluid heater. This configuration may be particularly advantageous within liquid loaded wells. For example, when a gas well may have become so loaded with liquid that gas has stopped flowing from the well, production gas may be trapped within the liquid. To rectify this, the liquid and gas therein may be heated, allowing the gas to rise to the surface to be heated. Given that gas may have poor thermal conductivity though, this process may take significant heating of the liquid and gas within the wellbore to allow the gas to flow to surface to be recovered. If the heater was to be disposed above the fluid heater during this process, such high temperature liquid and gas may damage the motor via over-heating as the liquid and gas flows over the motor as the heated liquid and gas flows to surface. Therefore, the heater may be inverted so that the motor may be disposed further downhole than the heater, which may prevent such high temperature liquid and gas over-heating the motor as the liquid and gas flows to surface.

The method may comprise installing the heater downhole a series of individual modules. Thus, the fluid heater may be modular; installed via multiple runs into the wellbore. Installing a heater in a modular fashion may help to reduce the deployment weight of the heater, as the weight may be split over multiple trips downhole. This may allow for slickline deployment to be used as the deployment means, given that the overall weight of the heater is split over multiple trips downhole. Further, this may allow for slickline deployment of higher powered fluid heaters, which may be generally of too high weight to be deployed in a single trip using slickline deployment equipment.

The method may comprise installing a plurality of heaters in the wellbore. The method may comprise installing the plurality of heaters in series connection, operating from a common drive. Alternatively, the method may comprise installing the heaters in such a manner wherein one or more of the plurality of heaters may be independently operable.

According to a second aspect of the present disclosure, there is described a method of heating a fluid downhole, the method comprising: connecting a fluid heater to a deployment member, deploying the fluid heater through a tubular, wherein the tubular is disposed within a wellbore that is lined or cased, and activating the fluid heater to heat a fluid within the tubular.

According to a third aspect of the present disclosure, there is described a method of removing an obstruction within a production tubular, the method comprising: detecting an obstruction within a production tubular, wherein the production tubular is disposed within a wellbore that has been cased or lined, and wherein the production tubular is at least partially fluid filled; connecting a fluid heater to a deployment member; deploying the fluid heater to the location of the obstruction within the production tubular, and activating the fluid heater to heat the fluid within the production tubular to a temperature suitable to remove the obstruction.

The method may comprise using any suitable measuring or detecting equipment to find the obstruction and/or determine the desired location of the heater.

The method may comprise deploying a temperature gauge with the fluid heater, in order to monitor the temperature of the fluid downhole adjacent the heater.

According to a fourth aspect of the present disclosure, there is described a method of installing a wellbore fluid heating system, the method comprising: lining or casing a drilled wellbore, installing a tubular within the lined or cased wellbore, and deploying a fluid heater on a deployment member within the tubular to a desired location along the tubular within the wellbore, wherein the deployment member is configured to alter the position of the heater in the wellbore According to a fifth aspect of the present disclosure, there is described a fluid heating system for a wellbore, the system comprising: a first tubular disposed within the wellbore, a second tubular disposed through the first tubular, and a fluid heater disposed within the second tubular, wherein the fluid heater is connected to a deployment member, the deployment member configured to alter the position of the heater in the wellbore.

According to a sixth aspect of the present disclosure, there is described a wellbore, the wellbore comprising: a first bore, the first bore being lined or cased with a first tubular; a second tubular disposed through the first tubular, and a fluid heater disposed within the second tubular.

Features defined in relation to one aspect may be provided in combination with any other aspect.

BRIEF DESCRIPTION OF THE FIGURES

These and other aspects of the present disclosure will now be described, by way of example only, with reference to the accompanying drawings, in which: Figures 1A to 1D show the steps of installing a fluid heater within a wellbore, wherein the fluid heater is deployed on coiled tubing.

Figures 2A to 2D show the steps of installing a fluid heater within a wellbore, wherein the fluid heater is deployed on a wireline.

Figures 3A to 3E show the steps of installing a fluid heater within a wellbore, wherein the fluid heater is deployed on a slickline.

Figures 4A to 4E show the steps of installing a fluid heater within a wellbore, and subsequently changing the location of said heater within the wellbore.

Figures 5A to 5C show the steps of installing a fluid heater within a wellbore, wherein the fluid heater is deployed from a floating vessel.

Figures 6A to 6C show the steps of installing a fluid heater within a wellbore, wherein the fluid heater is deployed from a land based vehicle.

DETAILED DESCRIPTION OF THE FIGURES

Figures 1A to 1D show a first method of heater installation into a wellbore, according to an aspect of the present invention.

Figure 1A shows a wellbore 10 that has been drilled and cased/lined, with a final liner/section of casing 12 installed. All equipment to be used in the recovery of hydrocarbons from the wellbore 10 will be transported downhole through the final liner/casing 12.

A tubular 14 is installed in the well 10, through the final liner/casing 12. Said tubular 14 may be a production tubular. The tubular 14 is fixed in place using packers 18, creating an isolated annulus between the final liner/casing 12 and the tubular 14. It will be appreciated by one skilled in the art that any appropriate method of securing a tubular in place within a liner/casing of a wellbore may be used. The tubular 14 comprises flow port 17. Said flow ports 17 allow fluid flowing through the wellbore liner 12 to enter the production tubular for transportation to surface.

Figure 1A further shows a fluid heater assembly 20 being transported downhole, as indicated by the arrows 22 present, through the tubular 14 within the wellbore 10. The conveyance member 25 used in this example is coiled tubing, connected between the fluid heater assembly 20 and the deployment source (at surface, not shown). In this example, the fluid heater assembly 20 comprises a fluid heater 24, a motor 26 to drive the fluid heater 24, a gauge 28 (which may be used to measure temperature or pressure downhole, for example), and a centraliser 29, provided to ensure the heater assembly 20 remains substantially concentric within the tubular 14.

To deploy the heater assembly 20 downhole, the coiled tubing 25 (i.e. the deployment member) is simply unreeled from a deployment mechanism (not shown) of a vehicle/vessel (not shown) upon which the reel of coiled tubing is disposed -as will be described below in further detail. The coiled tubing 25 will be unreeled until the fluid heater assembly 20 has reached its desired location within the wellbore 10, as shown within Figure 1B. Upon reaching said desired location, the heater 24 will be activated to heat the production fluid that is flowing from the reservoir (not shown) into the tubular 14, as indicated by the arrows 19. The heater 24 will be activated to heat the production fluid to a temperature required to reduce the viscosity of the production fluid to a level wherein it can be recovered to surface (e.g. by a pump array disposed downhole or that has been transported downhole with the fluid heater assembly 20). The reduced viscosity production fluid it then transported to surface via the flow path 15 defined between the tubular 14 and the coiled tubing 25 that has been used to deploy the fluid heater assembly 20.

Figure 1C demonstrates a point at which the production fluid has all been recovered, or no more recovery is required. At this point, the coiled tubing 25 to which the heating assembly 20 is connected is reeled back on to its deployment mechanism and recovered to surface (to the vehicle/vessel from which it was deployed), as indicated by the arrows 17.

Figure 1D simply shows the wellbore 10 once the fluid heater assembly 20 has been removed and recovered to surface, with the tubular 14 now free for new equipment to be passed through, such as intervention or fishing equipment; or for cleaning or injection fluids to be passed downhole.

It will be appreciated by one skilled in the art that the heater assembly 20 does not require all of the equipment listed above. For, the motor 26, gauge 27 and centraliser 28 are all optional to assist with the deployment and operation of the heater 24, and have simply been include for exemplary purposes. In examples where a motor may be disposed with the fluid heater 24 and part of the heater assembly 20, the motor 26 may be a hydraulic motor, which may be supplied with hydraulic drive fluid via the coiled tubing that is used as a deployment means 15. It will be appreciated that any means of powering a motor 26 to drive a fluid heater 24 within the understanding of the skilled person may be used though, with a selection of others described further below.

Additionally, in this example, the fluid heater 24 shown is a rotary fluid heater, which is preferred. Such a rotary fluid heater is shown with International Patent Application W02020/104819 Al, incorporated herein by reference. It will be appreciated by one skilled in the art though that any suitable fluid heater may be used with this method though.

The example method of deployment shown within Figures 2A to 2E shows a fluid heater assembly 40 being deployed to clear a blockage 31 from the tubular 34 of a wellbore assembly 30. Within this example, the wellbore has been constructed and a tubular 34 installed in the wellbore 30 in the same manner as that described within the example of Figures 1A to 1D.

As outlined above, and as shown in Figure 2A, a blockage 31 has formed within the tubular of a wellbore 30. As also described above, said blockage may have been formed by a wax build up within the tubular 34, or a liquid plug that has been formed from gas flowing up the tubular 34 reaching its dew point (and thereby being transformed back into its liquid state) as the temperature decreases as flow path of the tubular 34 gets closer to surface.

In the example shown by Figures 2A to 2E, the only difference in the method of deployment from the example of Figures 1A to 1D is that the heater assembly 40 is deployed using a wireline deployment member 45, instead of using coiled tubing as the deployment member.

Within Figure 2B, it is shown that the heater assembly 40 has been deployed downhole through the tubular 34 (with deployment indicated by the direction arrows 42), with the production tubular 34 being disposed though the final well liner/casing 32. Wireline deployment is another example of a reelable deployment means, therefore when the heating assembly is to be moved further downhole, the wireline is simply unreeled further from the vehicle/vessel upon which it is stored; and when the heating assembly 40 is to be retracted, the wireline 45 is simply reeled back onto the vehicle/vessel upon which it is stored.

Again, the heater assembly 40 in this example comprises a motor 46 (to drive the fluid heater 44), a fluid heater 44, a gauge 47 and a centraliser 48, all as described in relation to Figures 1A to 1D. Again, it will be appreciated that all components ancillary to the fluid heater 44 are not essentially required, and have merely been provided for exemplary purposes. In this example, the heater 44 provided is also a rotary heater, of the kind outlined above.

Once the heater assembly 40 has reached the blockage 31, a fluid 39 may be pumped downhole to be heated by the heater 44. Following this, the heater 44 is activated to heat the fluid 39 that has been pumped downhole, and subsequently remove the blockage 31. In this example, wherein wireline deployment 45 has been used, the wireline may also be used to drive the motor 46 that powers the heater 44. It will be appreciated that other means of powering the heater 44 may be used though.

In this method of blockage clearance within a tubular 34 using a fluid heater 44, an intermediate method step may be used, wherein the location of the blockage 31 (e.g. the depth the blockage 31 is located at) downhole may be determined, so that the length of deployment member 45 required to reach the blockage 31 can be determined.

As shown in Figure 20, once the blockage 31 has been removed, the deployment member 45 may be reeled out further to deploy the heating assembly 40 further down the tubular 34, wherein the heater may then be used to heat a production fluid in order for it to be recovered to surface (i.e. by lowering its viscosity); as also described in relation to Figures 1A to 1D. During production, fluid will flow through the wellbore liner 32 and into the production tubing 34 through the flow ports 37.

Once fluid heating operations downhole have been completed, the fluid heater assembly 40 is retracted from the wellbore, indicated by the direction arrows 37; as shown in Figure 2D. Retracting the heater assembly 40 involves reeling the deployment member 45 (e.g. the wireline) back on to its storage means (not shown), located on the vehicle/vessel (not shown) from which the heater assembly 44 was deployed.

Finally, Figure 2E shows the wellbore assembly 30 free of blockages, and with the fluid heater assembly 40 removed, free for other equipment to be passed through the tubular, or cleaning or injection fluids to be pumped downhole, for example.

Figures 3A to 3E show an example of slickline deployment of a fluid heater within a wellbore, wherein the fluid heater is installed in modules and assembled within the wellbore 50. Given the load capacity of some slickline deployment systems, a fluid heater system (which may include multiple heater modules, a motor, a gauge and/or a centraliser) may not be deployed in one trip down hole. Therefore, modules of the fluid heater assembly may be deployed in multiple trips down hole, with the heater being assembled at its required location within the wellbore. In an alternative example, multiple fluid heaters may be required to be connected in series given the heating requirements of the fluid within the wellbore. Therefore, fluid heaters may be deployed via multiple trips downhole, and connected at the required location.

As shown in Figure 3A, a first module 64a of a fluid heater 64 is deployed into a wellbore 50 via a slcikline deployment member 65. Said wellbore 50 is of the same structure as those outlined above, wherein the wellbore has been drilled and cased, with a tubular 54 disposed within the final liner/casing 52 of the wellbore. The tubular 54 is held in place within the wellbore 50 via packers 58, although any appropriate means of fixing a tubular 54 within a cased/lined wellbore 50 may be used. Further, it will be appreciated that any form of slickline deployment within the understanding of the skilled person may be used, for example braided wire slickline deployment, or the like.

The first module of the fluid heater module 64a is deployed via the slickline deployment member 65 as shown by the direction arrows 62 to its required location, wherein it is held.

Within Figure 3B, a second module 64b of the fluid heater 64 is deployed into the wellbore 50 via slickline deployment, to be assembled with the first heater module 54a.

This process is repeated within Figure 30, wherein a third heater module 64c is deployed into the wellbore 50 to be assembled with the first 64a and second 64b fluid heater modules.

As shown within Figure 3D, the final fluid heater module 64d is being deployed into the wellbore 60, with a motor 66, to be assembled with the first 64a, second 64b and 64c fluid heater modules, via slickline deployment. As outlined above, the motor 66 may be any appropriate motor that may be used to power a downhole fluid heater 64 (that may comprise multiple fluid heater modules) within the understanding of the skilled person.

Figure 3E shows the fully assembled fluid heater 64 within the wellbore 50, complete with the motor 66. The fluid heater 64 may now be used for any required fluid heating operations within the wellbore 50. Although not shown within the figures, it will be appreciated that, if required, the heater 64 may be recovered via any conventional wellbore intervention/fishing means.

Figures 4A to 4E demonstrate the process of installing a fluid heater assembly 80 within the wellbore 70, anchoring the fluid heater assembly 80 in place, disconnecting retracting the deployment member 85, and then redeploying the deployment member 85 to alter the position of the heater within the wellbore.

As shown by Figure 4A, a wellbore 70 has been prepared in the manner as described above, with a bore being drilled and lined, and a production tubular 84 disposed through the liner 72. Also shown is a heater assembly 80 being disposed downhole via a deployment member 85, to a required location.

Once the heater has reached the desired location, and as shown by Figure 4B, the heater assembly 80 is held in place by holding means 89. Said holding means 89 may be any appropriate holding means to maintain the position of the fluid heater assembly 80 within the tubular, while still allowing fluid flow between the surface and the production reservoir (not shown), via the production tubular 74, or vice versa. Within this example, the fluid heater assembly 80 comprises a fluid heater 84 (of the type as described above, for example), a motor 86 to power the fluid heater 84, a gauge 87 and a centraliser 88; although it will be appreciated that any of the motor 86, gauge 87 and centraliser 88 components may be optional.

Figure 4C demonstrates a point in the production process in which it is required that the heating assembly 80 be moved to a new location within the wellbore 70. As shown, the deployment member 85 is being redeployed towards the heater assembly 80, in order for the deployment member 85 to be reconnected to the heater assembly 80.

Following reconnection between the deployment member 85 and the fluid heater assembly 80, the anchor/fixing means 89 is removed.

Once the anchor/fixing means 89 has been removed, the deployment member 85 may be operated to relocate the fluid heater 80 within the wellbore 70. Once relocated within the wellbore 70, and as shown within Figure 5E, anchoring/fixing means 89 may again be used to hold the fluid heater assembly 80 in place at its new location; and production may again begin, as indicated by the arrows 79. It will be appreciated that when the fluid heater assembly 80 is moved to its new location within the wellbore, anchoring/fixing means 89 may not be required, and the heater assembly 80 may simply be held in place at the new location within the wellbore via the deployment member 85.

Figures 5A to 5C show the deployment and recovery of a fluid heater assembly 222 from a floating vessel, such as a ship/boat 210. Such a ship/boat 210 may be a floating production, storage and offloading vessel (FPSO), or a simple transportation/carrier vessel fitted with appropriate deployment equipment.

Within Figure 5A, a ship/boat 210 fitted with a deployment winch 212 is deploying a fluid heater to a subsea wellbore 240, via a reelable deployment member 214 connected to the winch 212. To deploy the deployment member 214, the winch 212 is simply turned in an anti-clockwise direction to pay out more of the deployment member 214. This allows the heater unit 220 (which comprises the heater assembly 222 and a means of attachment to, and deployment through, wellhead structure 247, (e.g. a deployment unit 224) to be deployed towards the wellbore 240. The wellhead structure may be provided 247 by a BOP structure, or the like.

Again, the wellbore structure of this example is the same as those outlined in the examples above, with a wellbore 240 being drilled and lined, and a tubular 244 being disposed though the final liner/casing 242 of the wellbore 240.

Figure 5B shows the point at which the deployment unit 224 of the heater unit 220 attached to the wellhead structure 247, and the fluid heater is deployed within the wellbore 240, inside the wellbore tubular 244. The heater assembly 222 is still connected to the ship/boat 210 via the deployment member 214, which runs from the winch 212 of the ship/boat 210, through the deployment unit 224, through the wellhead structure 247, and through the tubular to the heater assembly 222.

Within Figure 5C, once fluid heating operations have been completed, the winch 212 of the ship/boat 210 is operated (turned clockwise) to reel the deployment member 214 back on to the winch 212, thereby retracting the heater assembly 222 from the wellbore. The heater assembly 222 is recovered through the wellhead structure 247, back into the deployment unit 224, and back to the ship/boat 210, for storage.

In this example, it will be appreciated that any reelable deployment member may be used, such as any of those described above. Further, the fluid heater of this example is again a rotary fluid heater, of the kind described above. Any suitable heater may be used though.

The final example shown, as depicted within Figures 6A to 6C, is a fluid heater assembly 522 being deployed into a wellbore 540 from a land based vehicle 510 (such as a heavy good vehicle (HGV)). In this example, while the wellbore 540 has been drilled on land, it is still constructed in a similar manner to those described above, wherein the wellbore 540 has been drilled and lined/cased, with a tubular 544 installed through the final liner/casing 542. The tubular 544 is then held in place via packers 548.

Within Figure 6A, a heater assembly 522 (the same as that described above) is being deployed towards the wellbore 540 via a deployment member 514 connected to the deployment mechanism 512 (e.g. a winch) located upon the HGV 510. The deployment member 514 is passed over a wellbore equipment deployment structure 516 (such as a gooseneck), and lowered towards the wellhead structure 547 (as indicated by the direction arrows 530).

Figure 6B shows the fluid heater 522 once it has passed through the wellhead structure 547, and deployed through the wellbore tubular 544 to its desired location. Once at the desired location, the required fluid heating operation is performed (such as those described above).

Upon completion of the required fluid heating operation, the winch 512 of the HGV 510 is used to reel in the deployment member 514, and thereby recover the fluid heater assembly 522 through the wellbore tubular 544, through the wellhead structure 547, around the wellbore equipment deployment structure 516, and back for storage on the HGV 510; as indicated by direction arrow 535. Upon removal of the heater assembly 522 from the wellbore 540, normal wellbore operations may be resumed, such as production/recovery of wellbore fluids; as demonstrated within Figure 60.

It should be understood that the examples described herein are merely exemplary and that various modifications may be made thereto within the understanding of the skilled person, without departing from the scope of the present disclosure.

Claims

CLAIMS: 1. A method of installing a fluid heater within a wellbore, the method comprising: installing a fluid heater within a wellbore that comprises a wellbore casing and a production tubular disposed within the production casing; connecting a rotary fluid heater to a deployment member; and, deploying the rotary fluid heater into the wellbore through the production tubular.
2. The method of claim 1, comprising locating the heater at a first location.
3. The method of claim 2, comprising operating the heater to apply heat within the production tubular at the first location.
4. The method of any one of claims 2 or 3, comprising relocating the heater from the first location to a second location.
5. The method of claim 4, comprising operating the heater to apply heat within the production tubular at the second location.
6. The method of any one of claims 5 or 6, comprising relocating the heater from the second location to a third location.
7. The method of claim 6, comprising operating the heater to apply heat within the production tubular at the third location.
8. The method any one of claims 6 or 7, wherein the third location is the same as the first location.
9. The method of any preceding claim, comprising operating the heater to heat a fluid within the wellbore.
10. The method of any preceding claim, comprising varying the rotational speed of the heater to vary the thermal energy emitted by the heater.
11. The method of any preceding claim, comprising deploying a pumping arrangement with the fluid heater.
12. The method of claim 11, wherein the pumping arrangement comprises an electrical submersible pump (ESP).
13. The method of any one of claims 11 or 12, including pumping a fluid produced by the wellbore along the second tubular past the fluid heater.
14. The method of any one of claims 11 or 12, including pumping a fluid not produced by the wellbore along the second tubular past the fluid heater.
15. The method of any preceding claim, comprising deploying the heater on a reelable deployment member
16. The method according to claim 15, wherein the reelable deployment member is a wireline deployment member.
17. The method according to claim 16, comprising powering the fluid heater via the wireline deployment member.
18.. The method according to claim 15, wherein the reelable deployment member is a slickline deployment member.
19. The method according to claim 15, wherein the reelable deployment member is a self-supporting cable.
20. The method according to claim 19, comprising delivering power to the fluid heater via the self-supporting cable.
21. The method according to claim 15, wherein the reelable deployment member is a rod string, formed of one or more rods.
22. The method according to claim 15, wherein the reelable deployment member is coiled tubing.
23. The method according to any preceding claim, comprising deploying the fluid heater as individual modules and assembling the heater at a required downhole location
24. The method according to claim 23, comprising installing the modules of the fluid heater into the wellbore in plurality of deployments.
25. The method according to any preceding claim, comprising installing the heater into a subsea wellbore.
26. The method according to one of claims 1 to 24, comprising installing the heater into a wellbore formed on terra firma.
27. The method according to any preceding claim, comprising deploying a motor into the wellbore, said motor provided to drive the fluid heater.
28. The method according to claim 27, wherein the motor is an alternating current motor.
29. The method according to claim 28, wherein the alternating current motor is a permanent magnet motor.
30. The method according to claim 27, wherein the motor is a hydraulic motor.
31. The method according to any one of claims 27 to 30, comprising disposing the motor uphole of the fluid heater.
32. The method according to one of claims 27 to 30, comprising installing the fluid heater in the wellbore in an inverted configuration, wherein the motor is disposed downhole of the fluid heater.
33. The method according to any preceding claim, comprising deploying a plurality of heaters into the wellbore.
34. The method according to claim 33, comprising connecting the plurality of heaters in series, operable from a common drive.
35. The method according to any preceding claim, comprising deploying the fluid heater from an FPSO, jack-up rig, semi-submersible rig or fixed platform.
36. The method according to any one of claims 1 to 34, comprising deploying the fluid heater from a land based vehicle.
37. A fluid heating system for a wellbore, the system comprising: a casing disposed within the wellbore; a production tubular, wherein the production tubular is disposed through the first tubular; and, a rotary fluid heater disposed within the production tubular, wherein the rotary fluid heater is connected to a deployment member, the deployment member configured to alter the position of the rotary fluid heater in the wellbore.