WO2024209196A1

WO2024209196A1 - Flow management assemblies, methods and well

Info

Publication number: WO2024209196A1
Application number: PCT/GB2024/050898
Authority: WO
Inventors: Les JARVIS; David Martin; Barry Watson
Original assignee: Metrol Technology Ltd
Current assignee: Metrol Technology Ltd
Priority date: 2023-04-06
Filing date: 2024-04-02
Publication date: 2024-10-10
Anticipated expiration: 2025-10-06
Also published as: GB2628857A; GB202305216D0; AU2024251549A1

Abstract

A tubular assembly for a well comprising an outer load-bearing tubular, such as a screen, and an inner tubular thereinside, thus defining an annular channel therebetween and a main production bore inside the inner tubular. An electrically controllable valve on the outer tubular controls flow of fluid between said annular channel and the main production bore thus controlling flow from the well. The tubulars are usually rigidly attached to each other and deployed into the well together. Further tubulars can be added to create an extended channel controlled by the same valve. The assembly may be connected to other such assemblies to form a tubular string. Particular embodiments can be arranged to reflect the particular well configuration.

Description

Flow Management Assemblies, Methods and Well

This invention relates to assemblies, methods, a valve and a well for managing flow in/out of wells, especially hydrocarbon producing wells or CO2 sequestration wells and wells comprising screens.

Fluids are usually recovered from/injected into wells through a main production/injection tubing bore. Such tubing is run into wells as a string of pipe segments or "joints". Each joint can be, for example, 30 feet (9.1m) or 45 feet (13.7m) long. It is generally not practical to use longer joints as they cannot be assembled for deployment into the well or indeed transported to location.

Certain joints in the string may be perforated or otherwise have one or more flowpaths in their walls to allow flow of fluid from the well into the main bore for recovery or injection. During production of oil from wells, undesirable material and/or fluids may also be produced; such as sand, water and sometimes gas. It is known to deploy screens as part of the production tubing string to inhibit undesirable production, such as sand production. A screen may be provided in the production string by a joint being formed from a perforated base pipe with wire or mesh wrapped therearound to resist sand flowing into the bore of the tubing, whilst maintaining flow of fluids from the reservoir.

It is also known to include autonomous valves with the screens. These may include rubber elements which swell in contact with water to automatically close a valve thereby inhibiting flow and production of water from wells intended to produce hydrocarbons.

According to a first aspect of the present invention, there is provided a tubular assembly comprising: an outer load-bearing tubular comprising an electrically controllable valve; an inner tubular inside at least a section of the outer load-bearing tubular, thus defining an annular channel between an inside of said section of the outer loadbearing tubular and an outside of the inner tubular, and defining a main production bore inside the inner tubular and, typically when the outer tubular extends beyond said section, inside of the outer load-bearing tubular beyond said section; the outer load-bearing tubular having a flowpath through a wall in said section which communicates with the annular channel; and a seal between the inner tubular and the outer load-bearing tubular, wherein the electrically controllable valve is arranged to control flow of fluid between said annular channel and the main production bore.

A load-bearing tubular is one which can hold the weight of a string therebelow. It may comprise a joint of production tubing as well as the electrically controllable valve.

It is normally considered easier to provide an electrically controllable valve with an inner tubular. However the inventors of the present invention have found that in certain embodiments having the outer load-bearing tubular comprising the electrically controllable valve, the tubular assembly may be more quickly run as one assembly.

Multiple-Joint Assembly

The tubular assembly may comprise at least one further joint of outer load-bearing tubular and at least one further inner tubular - thus forming a multiple-joint assembly. In this way, the annular channel is extended. For example, the annular channel may be more than 18m long. In a further aspect of the invention, there is provided a tubular assembly comprising: an electrically controllable valve; an outer load-bearing tubular having a flowpath through a wall thereof; at least one further outer load-bearing tubular having a flowpath in a wall thereof; an inner tubular and at least one further inner tubular, the inner tubulars inside at least a section of the outer load-bearing tubulars thus defining an annular channel between an inside of said section of the outer load-bearing tubulars and an outside of the inner tubulars, and defining a main production bore inside the inner tubulars and when the outer tubulars extend beyond said section, inside of the outer load-bearing tubulars beyond said section; a seal between at least one inner tubular and at least one outer load-bearing tubular, wherein the electrically controllable valve is arranged to control flow of fluid between said annular channel and the main production bore.

Features, especially optional features, for the further aspect of the invention, and the first aspect the invention are independently interchangeable and are not repeated here for brevity.

The at least one further joint of outer load-bearing tubular usually does not have a further electrically controllable valve.

The flowpath(s) in the outer load-bearing tubular and the at least one further joint of outer load-bearing tubular in the multiple-joint assembly are typically in fluid communication with said annular channel which is extended by the at least one further inner tubular, such that fluid flow through each outer load-bearing tubular in the multiple-joint assembly is controlled by the same valve.

In this way, flow from a particular zone can be controlled by the same electrically controllable valve. Moreover, it is not necessary for multiple valves to be provided for each joint of outer load-bearing tubular. Instead, for preferred embodiments, fluid from two or more outer load-bearing tubulars flow into (or from) the same annular channel and are controlled by the same valve. The multiple-joint assembly may include a variety of outer load-bearing tubulars, preferably tailored to the particular well and reservoir in which it is used. For example, the outer loadbearing tubulars may include further outer load-bearing tubular joints with flowpath(s), one or more without flowpaths, and one or more with flowpath(s) and screens. For example, in one example of a multiple-joint assembly, there can be a total of fifteen or more outer loadbearing tubular joints joined in a string, fifteen or more inner tubulars joined together in an inner string, and for those outer load-bearing tubulars with flowpath(s), all are in communication with the same annular channel and controlled by the same valve.

The tubular assembly can be connected to other load-bearing tubulars, and deployed as part of a tubular string in a well. Said other load-bearing tubulars usually have the same outer diameter as the outer load-bearing tubular(s) of the tubular assembly. There may be a plurality of tubular assemblies as part of the tubular string, each tubular assembly independently including the features and optional features described herein for the tubular assembly. Each tubular assembly in a string may be separated by a packer or the like.

The other load-bearing tubulars in the tubular string may include further joints with flowpath(s), joints without flowpath(s), and joints with flowpath(s) and screens.

The outer load-bearing tubular typically has, at said section, an external diameter of at least 4 inches (102 mm), more typically 5.5" to 6 5/8" (140mm - 168mm) (not including screens or joints).

The outer load-bearing tubular typically has, at said section, an external diameter of at most 9 inches (229 mm) (not including screens or joints).

The outer load-bearing tubular typically has, at said section, an inner diameter of at least 3 inches (76mm) and/or optionally at most 6.5" (165mm).

Preferably the inner tubular and outer load-bearing tubular are rigidly attached to each other, such that they can be deployed or removed from the well together below an assembling position and not separately.

There may be a plurality of flowpaths in the wall of the outer load-bearing tubular.

Normally, the annular channel extends further than the position of the flowpaths in the outer load-bearing tubular. The outer load-bearing tubular may comprise a screen. It may have a mesh thereon, for example formed from wire wrapped over the flowpath(s) of the outer load-bearing tubular.

Any seal between outer load-bearing tubular and inner tubular may be used. The seal may be formed from a seal bore extension such as a polished bore. It may include polymer sealing elements. It may include a swellable component.

The inner tubular may not extend for the entire length of the outer load-bearing tubular. For extended sections of the outer load-bearing tubular, which do not contain the inner tubular, the main production bore is defined by the inside of the outer load-bearing tubular. Thus the annular channel may not extend along the entire length of the outer load-bearing tubular. Alternatively, the inner tubular and outer load-bearing tubular may be the same length and so said section is the entire length of the outer load-bearing tubular.

The seal may be at or towards one end of the inner tubular.

The arrangement of the seal, inner tubular and valve results in the annular channel being a sealed flowpath, which is isolated from the main production bore. Said flowpath is still considered "sealed" even if the valve includes a choke, and/or there are de minimus leak paths.

The electrically controllable valve may be controllable automatically based on a timer or data from a sensor. Alternatively the electrically controllable valve may be controllable by an operator.

The electrically controllable valve may be wirelessly controllable.

The electrically controllable valve may be an electronically controllable valve.

The electrically controllable valve may be at or towards one end of the inner tubular, usually the upper/shallower end, in use.

The electrically controllable valve is usually at the opposite end of the inner tubular, to the seal.

References such as "above", "top", "below", "bottom", "uphole" and "downhole" relates to their normal in-use orientation and relative position, and when applied to deviated or horizontal wells should be construed as their equivalent in wells with some vertical orientation. For example, "above" is closer to the surface of the well through the well, even in a horizontal well.

The tubular assembly may comprise at least one sensor configured to determine the nature of fluid flow, such as pressure, temperature and/or flow rate. Sensors may also assess the proportion or amount of water, sand, gas or oil content, especially the amount or proportion of water content. The sensor may be a sensor array, such as a fibre optic or discrete sensor array such as that described in WO2017/203293, WO2017/203294, WO2017/203295 or WO2017/203296.

The tubular assembly may include a receiver. Thus it may receive signals, such as control signals for the valve. Thus in order to allow for communications, the receiver is preferably coupled, physically or wirelessly, to the valve.

The tubular assembly may include a transmitter. Thus it may transmit signals, such as data from the sensors. Thus in order to allow for communications, the transmitter is preferably coupled, physically or wirelessly, to the sensor(s).

A transceiver may be used to provide both receiving and transmitting functionality, as described. The tubular assembly may be battery powered.

Wireless

The wireless signals for the electrically controllable valve or to recover data may be acoustic, electromagnetic (EM), and/or coded pressure pulsing. Acoustic and/or EM are preferred.

Pressure pulses include methods of communicating from/to within the well/borehole, from/to at least one of a further location within the well/borehole, and the surface of the well/borehole, using positive and/or negative pressure changes, and/or flow rate changes of a fluid in a tubular and/or annular space. Coded pressure pulses are such pressure pulses where a modulation scheme has been used to encode commands within the pressure or flow rate variations and a transducer is used within the well/borehole to detect and/or generate the variations, and/or an electronic communication device is used within the well/borehole to encode and/or decode commands. Therefore, pressure pulses used with an in-well/borehole electronic interface are herein defined as coded pressure pulses. An advantage of coded pressure pulses, as defined herein, is that they can be sent to electronic interfaces and may provide greater data rate and/or bandwidth than pressure pulses sent to mechanical interfaces. Coded pressure pulses can be induced in static or flowing fluids and may be detected by directly or indirectly measuring changes in pressure and/or flow rate. Fluids include liquids, gasses and multiphase fluids, and may be static control fluids, and/or fluids being produced from or injected into the well. Acoustic signals and communication may include transmission through vibration of the structure of the well including tubulars, casing, liner, drill pipe, drill collars, tubing, coil tubing, sucker rod, downhole tools; transmission via fluid (including through gas), including transmission through fluids in uncased sections of the well, within tubulars, and within annular spaces; transmission through static or flowing fluids; mechanical transmission through wireline, slickline or coiled rod; transmission through the earth; transmission through wellhead equipment. Communication through the structure and/or through the fluid are preferred.

Acoustic transmission may be at sub-sonic (<20 Hz), sonic (20 Hz - 20kHz), and ultrasonic frequencies (20kHz - 2MHz). Preferably the acoustic transmission is sonic (20Hz - 20khz).

Electromagnetic (EM) (sometimes referred to as Quasi-Static (Q.S)) wireless communication is normally in the frequency bands of: (selected based on propagation characteristics) sub-ELF (extremely low frequency) <3Hz (normally above 0.01Hz);

ELF 3Hz to 30Hz;

SLF(super low frequency) 30Hz to 300Hz;

ULF (ultra-low frequency) 300Hz to 3kHz; and,

VLF (very low frequency) 3kHz to 30kHz.

These forms of wireless signals are described in further detail in WO2017/203285.

Electrically controllable valve

Normally, the electrically controllable valve is provided between the annular channel and the main production bore.

The electrically controllable valve may be a plug valve. Alternatively or additionally the electrically controllable valve may comprise a sleeve. Optionally the valve may comprise fixed or adjustable chokes. The valve is preferably a proportional valve so can choke fluid flow to various degrees, rather than only having open/close positions.

Preferably a valve assembly comprises the electrically controllable valve. The valve assembly may comprise multiple plugs or sleeves, which may be independently controlled. The valve assembly may have at least three connectors. The valve assembly may comprise a first outer connection for connection with other load-bearing tubulars in a tubular string, a second connector for connection with the outer load-bearing tubular, and/or a third inner connector for connection with the inner tubular.

According to a second aspect of the present invention there is provided a valve assembly comprising an electrically controllable valve, a first outer connection for connection with other load-bearing tubulars in a tubular string, a second connector for connection with the outer load-bearing tubular, and a third inner connector for connection with the inner tubular.

Features, especially optional features, of the first, further and second aspects of the invention are independently interchangeable and are not repeated here for brevity.

The tubular assembly may include a 3-way crossover connector, especially for embodiments where the valve assembly is run into the well at the lower end of the tubular assembly. For such embodiments, the 3-way crossover connector is usually deployed at the upper end of the tubular assembly, to terminate the annular channel. It may have a first outer connection for connection with other load-bearing tubulars in the tubular string, a second connector for connection with the outer load-bearing tubular, and a third inner connector for connection with the inner tubular.

Preferably the first connector (of the valve assembly or the 3-way crossover connector) to the tubular string comprises a threaded connection. Optionally the second connector (of the valve assembly or the 3-way crossover connector) to the outer load-bearing tubular comprises a stab-connection. Preferably the third connector (of the valve assembly or the 3- way crossover connector) to the inner tubular is a threaded connection. The second connector may also include a threadedly mounted nut collar moveable over the stabconnection to transfer the load. Deployment

According to a third aspect of the invention, there is provided a method for deploying a tubular assembly as described herein into a borehole, the method comprising running the outer load-bearing tubular and inner tubular into the borehole together, rigidly attached to each other below an assembly position near the surface of the borehole.

In a yet further aspect, the invention provides a method for deploying a tubular assembly into a borehole, the tubular assembly comprising: an electrically controllable valve; an outer load-bearing tubular having a flowpath through a wall thereof; an inner tubular inside at least a section of the outer load-bearing tubular, thus defining an annular channel between an inside of said section of the outer load-bearing tubular and an outside of the inner tubular, and defining a main production bore inside the inner tubular and when the outer tubular extends beyond said section, inside of the outer load-bearing tubular beyond said section; a seal between the inner tubular and the outer load-bearing tubular, and the electrically controllable valve arranged to control flow of fluid between said annular channel and the main production bore; the method comprising: running the outer load bearing tubular and inner tubular into the borehole together, rigidly attached to each other below an assembling position near the surface of the borehole.

The outer load-bearing tubular and inner tubular may be assembled together near the surface of the well at an assembling/assembly position, then run into the borehole together. Therefore they may be run in together for over 90% of the length of the borehole.

The methods of the third and yet further aspects may independently include features, especially optional features, of the tubular assemblies described herein, and the valve according to the second aspect, and these are not repeated here for brevity.

The method may further comprise: a) suspending at least one outer load-bearing tubular, the outer load-bearing tubular having one of a seal assembly and a seal bore extension; b) optionally connecting at least one further outer load-bearing tubular(s) to said at least one load-bearing tubular, to form a string of outer load-bearing tubulars; c) suspending an inner tubular, partially inside the outer load-bearing tubular, the inner tubular having the other of a seal assembly and a seal bore extension; d) rotatably connecting a valve assembly to the inner tubular; e) lowering the inner tubular to engage the seal assembly and seal bore extension; f) connecting one end of the valve assembly to the outer load-bearing tubular; g) typically lowering the outer load-bearing tubular and connected inner tubular; h) attaching a second opposite end of the valve assembly to a tubular string; i) typically deploying the tubular string with attached tubular assembly further into the well.

Further inner tubulars may also be added, as required. Steps e) and f) can be performed simultaneously or in either order. Otherwise, the steps are preferably performed successively in the given order.

For embodiments where the valve assembly is at the bottom (as run in) of the tubular assembly, the 3-way crossover connector is provided at upper end of the assembly and, for such embodiments, the method may comprise: a) suspending at least one outer load-bearing tubular comprising a valve assembly, the at least one outer load-bearing tubular also having one of a seal assembly and a seal bore extension; b) optionally connecting the at least one outer load-bearing tubular to a tubular string therebelow via a downhole connector of the valve assembly; c) optionally connecting at least one further outer load-bearing tubular(s) to said at least one load-bearing tubular to form a string of outer load-bearing tubulars; d) suspending at least one inner tubular partially inside the at least one outer loadbearing tubular, the at least one inner tubular having the other of the seal assembly and the seal bore extension; e) rotatably connecting one downhole connector of the 3-way crossover connector to the inner tubular; f) lowering the inner tubular, and attached 3-way crossover connector, to engage the lower seal assembly and seal bore extension; g) connecting a further downhole connector of the 3-way crossover connector to the at least one outer load-bearing tubular or to said string of outer load-bearing tubulars; h) typically lowering the at least one outer load-bearing tubular and connected at least one inner tubular; i) attaching an uphole connector of the 3-way crossover connector to a tubular string; and, j) typically deploying the tubular string with attached tubular assembly further into the well.

Further inner tubulars may also be added, as required.

The outer load-bearing tubular may be suspended from the drill floor, rotary table or from any other suitable means.

The inner tubular can be suspended from the drill floor, rotary table, a further "false" rotary or from any other suitable means.

Normally, to rotatably form the connection between the valve assembly (when positioned at the top or the 3-way crossover connector if present when the valve is at bottom), the inner tubular is held rotationally stationary (relative to the outer load-bearing tubular) and the valve assembly or the 3-way crossover connector is rotated.

Alternatively, for embodiments where the valve assembly is at bottom, the valve assembly is normally held stationary as the load bearing tubular/string is rotated.

Normally the valve assembly is stabbed into the outer load-bearing tubular. An outer rotational nut collar may be provided to secure the connection, and/or transfer the load.

Thus neither the outer load-bearing tubular, or the valve assembly with attached inner tubular, need to rotate in order to form the connection between the valve assembly and the outer load-bearing tubular. Accordingly, rotation of the connected seal assembly/seal bore extension in the well can be avoided. Moreover, the tubular assembly may be deployed into the borehole in a single trip. For many embodiments there is a maximum of one valve assembly controlling flow between the annular channel and main production bore, per tubular assembly, the or each tubular assembly optionally including two or more joints of outer load bearing tubulars (further optionally including two or more screens), and two or more joints of inner tubular.

However for certain embodiments, a valve assembly may be provided both at the top and at the bottom of the tubular assembly (taking the place of the 3-way crossover connector described above).

Therefore, embodiments preferably therefore have a maximum of two valve assemblies controlling flow between the annular channel and main production bore per tubular assembly; the or each tubular assembly optionally including two or more joints of load bearing tubulars (further optionally including two or more screens), and two or more joints of inner tubular.

For certain embodiments a combined valve assembly may provide one lower end of a valve assembly for an upper tubular assembly, and an upper end of a valve assembly for a lower tubular assembly. Such a combined valve assembly may share components of the valve assembly required for both the upper and lower tubular assemblies, such as a transceiver.

Well

According to a fourth aspect of the present invention, there is provided a well comprising a tubular string and a tubular assembly as described herein.

The tubular assembly of the fourth aspect of the invention, independently includes optional and preferred features of the tubular assemblies according to the first and further aspects of the invention, the valve according to the second aspect of the invention, and the methods of the third and yet further aspects, and these are not repeated here for brevity.

The well may comprise a plurality of tubular assemblies, each tubular assembly including an associated annular channel and an associated valve. Where there are two or more tubular assemblies, there are respectively two or more annular channels, forming a discontinuous annular path, rather than a continuous annular channel extending through the well. As well as one or more tubular assemblies, the string of outer load-bearing tubulars can also include slotted pipes, perforated pipes, blank pipes and packers including swellable packers; the order and number of each can be tailored to reflect particular well zones and length etc.

Packers

Each tubular assembly may be separated by a packer or the like and optionally by a packer therebelow. The packer may be a pressure-set packer which is adapted to be set by using an applied higher pressure on the inside of the outer load-bearing tubular/tubular string. Such pressure set-packers include inflatable packers where the pressure inflates a sealing element, hydraulically-set packers where the applied pressure activates a piston acting on a compression-set sealing element and metal-expandable packers where pressure expands metal to engage with the outer casing or bore.

Compared to swellable packers, pressure-set packers can usually function with a higher pressure differential, are usually quicker to set (which can reduce valuable rig-time) and often have improved long-term reliability. However, they were hitherto difficult to activate in certain well positions. Embodiments of the invention can use a pressure-set packer below (or above) one or more tubular assemblies usually by closing the electrically controllable valve thereabove (or therebelow) to prevent pressure loss to the reservoir. Elevated pressure in the bore is then used to activate the pressure-set packer(s) below (or above).

According to a fifth aspect of the present invention, there is provided an assembly comprising the tubular assembly of the first or further aspects of the invention and a pressure-set packer.

The assembly of the fifth aspect of the invention may independently include features, especially optional features, of the other aspects of this invention described herein and these are not repeated here for brevity.

The assembly of the fifth aspect may be provided in a well.

There may be a plurality of pressure-set packers in said assembly. There may be a pressureset packer between a first and a second tubular assembly. The pressure-set packer may be mounted on the same string as the tubular assembly. The pressure-set packer may be provided above or below the tubular assembly, especially in a position which has pressurecommunication with the production bore of the tubular assembly. For certain embodiments, the pressure-set packer is below the tubular assembly.

Optionally all flowpaths in the outer load-bearing tubular(s) of the fifth aspect of the invention, are controlled by the valve assembly.

Certain embodiments, especially those with multiple flowpaths in the outer load-bearing tubular(s), may be combined with autonomous valves, chokes or plugs in the flowpaths of the screens to further optimise flow to/from the formation. For example, such valves may include rubber elements which swell in contact with water to automatically close a valve thereby inhibiting flow and production of water from wells intended to produce hydrocarbons. In another example, flowpaths in the outer load-bearing tubular(s) proximate to the valve may be choked to a greater extent than those remote from the valve. In another example a screen to be positioned in a higher flow position may be plugged or choked to a greater extent than other screens to be positioned in a lesser flow position.

The well may be a multi-lateral well. In the event that a lateral bore is not producing the desired fluids, it can be more easily shut off using the electrically controllable valve.

Control of the lateral bore can also be afforded by wireless communication from the main bore, reducing the difficult requirement to deploy cables into lateral bores.

Embodiments are particularly suited for use in subsea wells. Embodiments are usually used in a production well.

Flow

According to a sixth aspect of the invention, there is provided a method of producing fluid from a reservoir, comprising: providing a tubular string comprising a tubular assembly as described herein in a well; producing fluid from a reservoir into the well, through flowpath(s) in the outer loadbearing tubular of the tubular assembly into the annular channel; flowing fluid through the annular channel towards the electrically controllable valve; optionally adjusting said electrically controllable valve to change the flow rate of fluids from the annular channel to the main production bore.

The tubular assembly of the sixth aspect of the invention may independently include features, especially optional features, as described with respect to the other aspects of the invention, and are not repeated here for brevity.

In particular, there may be more than one tubular assembly, or more than one multiplejoint assembly, each with a respective annular channel and valve and each normally associated with a respective zone. Thus an operator can optimise fluid flow from different tubular assemblies/multiple-joint assemblies usually from different zones into the main production bore.

The method may include sensing at least one property of the fluids from the reservoir. The electrically controllable valve may be adjusted, either automatically or by an operator, at least partly in response to the sensed property of the fluid. The nature of fluids produced after adjusting the electrically controllable valve may be monitored at or near the surface. The nature of the fluids produced (e.g. water/gas/sand cut) can then be used to verify or further optimise the desired produced fluid.

According to a seventh aspect of the invention, there is provided a method of injecting fluid into a geological formation, comprising: providing a tubular string comprising a tubular assembly, as described herein, in a borehole, wherein the production bore is an injection bore; injecting fluid from the injection bore into a portion of the geological formation, through the annular channel and flowpath(s) in the outer load-bearing tubular of the tubular assembly; and, optionally adjusting said valve to change the flow rate of fluids from the injection bore into the annular channel to the geological formation.

The tubular assembly of the seventh aspect of the invention may independently include optional features as described with respect to the other aspects of the invention, and are not repeated here for brevity. The borehole according to the seventh aspect of the invention may have previously been a production well. Such a production well may have flowpaths to a plurality of zones. Thus, it may remain in communication with a plurality of zones, and the injection of fluids into the geological formation of a chosen zone may be controlled using the tubular string as described.

Embodiments of the present invention will now be described by way of example only, with reference to the accompany drawings, in which:

Fig. 1 is a part-sectional view of a first embodiment of a tubular string with two tubular assemblies in accordance with an aspect of the present invention;

Fig. 2 is a part-sectional view of a second embodiment of a tubular string with two tubular assemblies in accordance with an aspect of the present invention;

Fig. 3 is an enlarged view of a valve assembly in accordance with an aspect of the present invention;

Fig. 4a is a part-sectional view of an embodiment of a tubular assembly formed as a multiple-joint assembly in accordance with an aspect of the present invention;

Fig. 4b is an enlarged sectional view of a valve used in the Fig. 4a multiple-joint assembly;

Fig. 5 is a part-sectional view of a further embodiment of a tubular assembly in accordance with an aspect of the present invention;

Fig. 6 is a perspective view of a yet further embodiment of a tubular string in accordance with an aspect of the present invention;

Fig, 7a is a part-sectional view of another embodiment of a tubular string in accordance with an aspect of the present invention;

Fig. 7b is an enlarged view of a valve assembly forming part of the Fig. 7a embodiment; and,

Fig. 7c is an enlarged view of a connector sub-assembly forming part of the Fig. 7a embodiment. A tubular screen assembly 1 is shown in Fig. 1 including outer load-bearing tubulars in the form of base pipe 10a and sections of inner tubing or stinger 10b, 10b'. On the base pipe 10a, there is provided a first group of two screens 11a, lib and a second group of further screens 12a, 12b. Each group of screens has a respective inflow control valve (ICV) 13, 14 and connector 15, 16 upstream of the screens; and seal bores 17, 18 and packers 19, 20 downstream. Each group, with associated components, forms a multiple-joint sub-assembly and generally produces from a respective reservoir zone.

Sensors (not shown), such as a water cut gauge or pressure/temperature sensor, may be provided with each ICV 13, 14 to determine or infer water cut and/or flow rate. A transceiver (not shown) sends data to the operator at the surface, and can receive control signals to close or choke each ICV 13, 14 independently.

Respective annular channels 21, 22 are formed on the inside of the base pipe 10a and outside of the inner tubulars 10b, 10b'. The screens 11a & lib, 12a & 12b communicate with respective annular channels 21, 22 allowing fluid flow through the screens into the channel towards the respective ICV 13, 14.

An enlarged view of a valve assembly 40 comprising the inflow control valve (ICV) 13, 14 is shown in Fig. 3 and will be described with respect to the first group of screens/sub-assembly noting the others have the same features. The valve assembly 40 also includes a first uphole connecter 41 for connection to the base pipe 10a thereabove, a second outer string connector 42 for connection to the base pipe 10a therebelow, and a third inner string connector 43 for connection to the inner tubular 10b therebelow. A controller 44 controls the inflow control valve 13 and includes the wireless transceiver (not shown). The valve controls fluid flow between the annular channel 21 and an inner production bore 30 of the base pipe 10a, via porting 45, 46 respectively.

In use, fluids flow through the screens 11a & lib, 12a & 12b to the inside of the base pipe 10a, into the respective annular channel 21, 22 and through the respective inflow-control valves 13, 14 (when open) and onwards into the main production bore 30 of the base pipe 10a to the surface.

In the event that there is undesirable flow through one particular sub-assembly, the operator can choose to choke back or stop the flow from that sub-assembly/zone by adjusting the associated ICV 13/14. In this way, a more optimised flow from the well can be achieved or it can be shut-off if required.

Fig. 2 is a second embodiment of a tubular screen assembly with like parts sharing the same reference numeral except preceded by a '1'. In this embodiment packers 119/120 are above the respective seal bores 117/118. This arrangement can be used where there is, for example, limited space to set the seal bore in the particular zone. Otherwise, the Fig 2 embodiment functions as described for Fig. 1.

Fig. 4a is a third embodiment of a tubular screen assembly with like parts sharing the same reference numeral except preceded by a '2'. In this embodiment, five screens 211a, 211b, 211c, 211d, 211e make up the sub-assembly. Thus such an embodiment may be used for zones which extend for a longer extent of the well. Other embodiments may have many more screens in the same sub-assembly and associated with the same valve.

In alternative embodiments, the ICV can be configured to be closed or choked back automatically in response to detection of water or other undesirable fluid flow from one or more zone/associated sub-assembly.

Fig. 5 shows a fourth embodiment of a tubular screen assembly with like parts sharing the same reference numeral except preceded by a '3'. In this embodiment, the sub-assembly comprises two screens 311a, 311b.

Moreover, instead of or in addition to sensors associated with an ICV assembly 340, a continuous or discrete line of sensors 323 extends along a base pipe 310a, past the ICV assembly 340, past a connector 315, through the screens 311a & 311b, past a seal bore 317 and a packer 319 and onwards to any further sub-assembly below (not shown).

This sensor line 323 can similarly provide information on the nature of fluids produced through the screens of a particular sub-assembly/zone, the data being used to optimise recovery of particular fluids from the well.

Fig. 6 shows a fifth embodiment of a tubular screen assembly in perspective view, with like parts sharing the same reference numeral except preceded by a '4'. In this embodiment, the sub-assembly further comprises a mechanical sliding sleeve 425 below an ICV assembly 440 and above a connector 415, screens 411 and a seal-bore extension 417. In the event that the valve fails closed, such a sleeve can be opened.

The length and nature of the tubular assemblies and associated tubular string exemplified herein can be tailored according to well length and zone position etc. For explanatory purposes, relatively short tubular assemblies are described but may in practise be much longer. For example, in one embodiment, there is one tubular assembly with ten joints of outer load-bearing tubular and twelve joints of inner tubular. In another embodiment, there are three tubular assemblies, with four, twenty and fifty joints of outer load-bearing tubulars/inner tubulars respectively. Each assembly may be separated by pressure-set packers and the fifty joint section comprised of screens sub-sectioned by two swellable packers. In a third embodiment there are ten tubular assemblies, joined together with other load-bearing tubulars including blank pipes and slotted pipes.

Figs. 7a and 7b show a further embodiment of the present invention with like parts using the same reference numerals except preceded by a '5'. The Figs 7a/7b embodiment functions generally as described for earlier embodiments with an annular channel 521 formed between a base pipe 510a and an inner tubular 510b. However, one difference is that the valve assembly 540 is towards the bottom of the tubular assembly below screens 511a, 511b, rather being towards the top. This may be useful to align the screens with a zone of interest. The outer load-bearing pipe 510a including the valve 540 attaches to a joint of pipe therebelow.

As shown in Fig. 7b, the valve assembly 540 includes a first downhole connecter 541 for connection to an other load-bearing tubular therebelow, a second outer string connector 542 for connection to the outer load-bearing tubular 510a thereabove, and a third inner string connector 543 for connection to the inner tubular 510b thereabove. A controller 544 controls an inflow control valve 513 and includes the wireless transceiver (not shown). The valve 513 likewise controls fluid flow between the annular channel 521 and an inner production bore 530 of the base pipe 510a, via porting 545, 546 respectively.

Towards the top end of this embodiment, there is 3-way connector / crossover-assembly, shown in more detail in Fig. 7c. It includes similar connections as the valve assembly of Fig.

3 albeit without a valve. Such connections use the same reference numeral except preceded by a '6'. The 3-way crossover connector 640 has a first uphole connecter 641 for connection to an other load-bearing tubular thereabove, a second outer string connector 642 for connection to outer load-bearing tubular, and a third inner string connector 643 for connection to the inner tubular therebelow.

Embodiments can be arranged to reflect the particular well configuration. For example, suitable numbers of screens can be used for each zone, suitable numbers of sub-assemblies to reflect each zone. Blank base pipe may also be used.

Embodiments of the invention also benefit in that existing screen designs may be used with little or no alteration and the screens may comprise flow control mechanisms, such as check valves, chokes, and autonomous inflow control devices.

The tubular screen assembly 1 is assembled at the rig floor (not shown) before deployment. Deployment of a tubular screen assembly 1 will now be described with particular reference to the lower sub-assembly shown in Fig. 1 and valve assembly shown in Fig. 3.

The outer base pipe 10a is first assembled and run into the top of a well (not shown), that is the packer 20, seal bore extension 18, and screens 12b/12a; which remains suspended in a primary rotary table (not shown).

The inner tubular 10b' or inner string is then assembled and fed into the outer string using a false rotary (not shown) which lowers the inner tubular 10b' within the base pipe 10a until it is engaged in the seal bore extension 18. It is then suspended from the false rotary.

The third connector 43 on the valve assembly 40 is then rotatably connected to the upper end of the inner tubular 10b. The second connector 42 of the valve assembly 40 is then stabbed into the outer string or base pipe 10a to form the connection 15.

The ICV assembly 40 with attached inner tubular 10b' is lowered. At the upper end, an external locking nut (not shown) is rotated and locked completing the connection 15. The inner tubular 10b' is then sealed between the seal bore extension 18 and the ICV assembly 40 inlet, defining the channel 22, which forms a sealed flowpath. The entire assembly is run in hole further.

The false rotary is then removed and the assembly (with base pipe 10a and connected inner tubular 10b') suspended from the primary rotary table. The uphole connector 41 of the valve assembly is then engaged with an other load-bearing tubular. The entire sub-assembly is then run in together. Further sub-assemblies, such as the upper assembly shown in Fig. 1 can be assembled in the same way.

In this way, assembly can be completed without rotation of the assembly whilst the inner tubular 10b' is inside of the base pipe 10a.

For embodiments such as the Fig 7a-7c embodiment where the valve is towards the bottom of the tubular string, the order of assembly usually has some changes. The outer loadbearing tubular with the valve assembly is first suspended in the well, further outer loadbearing tubulars are successively added, such as one or more joints of base pipe with screens.

The inner tubular is then suspended inside the string of outer tubulars. And further inner tubulars can be successively added to form a string of inner tubulars. Towards the top of the tubular assembly, an inner downhole connector of a 3-way crossover connector is rotatably connected to the stationary inner tubular.

The inner tubular is then lowered and a seal assembly /seal bore extension at the lower valve assembly on the outer tubular and the inner tubular are engaged.

One downhole connector of the 3-way connector is then connected to the outer loadbearing tubular to connect the tubulars. An outer rotational nut collar is provided to allow the load to be transferred. The connected tubulars are then lowered.

An uphole connector of the 3-way crossover connector is then attached to a tubular string above. The tubular assembly with connected tubulars can then be run into the well.

Improvements and modifications may be made within the scope of the appended claims and their equivalents. For example, whilst embodiments here are generally described in the context of production wells, alternative embodiments can be used for injection, such as water/steam injection or CO2 sequestration.

Claims

1. A tubular assembly comprising: an outer load-bearing tubular comprising an electrically controllable valve, the outer load-bearing tubular having a flowpath through a wall thereof; an inner tubular inside at least a section of the outer load-bearing tubular, thus defining an annular channel between an inside of said section of the outer loadbearing tubular and an outside of the inner tubular, and defining a main production bore inside the inner tubular and, when the outer tubular extends beyond said section, inside of the outer load-bearing tubular beyond said section; a seal between the inner tubular and the outer load-bearing tubular, wherein the electrically controllable valve is arranged to control flow of fluid between said annular channel and the main production bore.

2. A tubular assembly as claimed in claim 1, wherein the inner tubular and outer loadbearing tubular are rigidly attached to each other, such that they are deployed or removed from the well together and not separately.

3. A tubular assembly as claimed in any preceding claim, wherein the outer load-bearing tubular comprises a screen.

4. A tubular assembly as claimed in any preceding claim, wherein the outer load-bearing tubular extends in length beyond the length of the inner tubular, and for sections of the outer load-bearing tubular extending beyond the inner tubular in length, the main production bore is defined by the outer load-bearing tubular.

5. A tubular assembly as claimed in any preceding claim, wherein the outer load-bearing tubular has an external diameter of at least 4 inches (102 mm).

6. A tubular assembly as claimed in any preceding claim, comprising at least one further outer load-bearing tubular having a flowpath in a wall thereof, and at least one further inner tubular; thereby forming a multiple-joint assembly and extending the annular channel to form an extended annular channel.

7. A tubular assembly as claimed in claim 6, wherein the flowpath in the outer loadbearing tubular and the flowpath in the at least one further outer load-bearing tubular are in fluid communication with said extended annular channel, such that fluid flow through the load bearing tubular and the at least one further outer load-bearing tubular is controlled by the same electrically controllable valve.

8. A tubular assembly as claimed in any preceding claim, wherein the electrically controllable valve is controllable automatically based on a timer or data from a sensor.

9. A tubular assembly as claimed in any one of claims 1 to 7, wherein the electrically controllable valve is controllable by an operator.

10. A tubular assembly as claimed in any preceding claim, wherein the electrically controllable valve is an electronically controllable valve.

11. A tubular assembly as claimed in any preceding claim, wherein the seal is formed in part using a seal bore extension such as a polished bore.

12. A tubular assembly as claimed in any preceding claim, wherein the seal is at or towards one end of the inner tubular.

13. A tubular assembly as claimed in any preceding claim, wherein the electrically controllable valve as part of the load bearing tubular, is at or towards one end of the inner tubular.

14. A tubular assembly as claimed in claim 13 wherein the electrically controllable valve is at the opposite end of the inner tubular, to the seal.

15. A tubular assembly as claimed in any preceding claim, comprising at least one sensor configured to determine the nature of fluid flow, such as pressure, temperature and/or flow rate.

16. A tubular assembly as claimed in claim 15, wherein the at least one sensor assesses the proportion or amount of water, sand, gas or oil content, especially the amount or proportion of water content.

17. A tubular assembly as claimed in any one of claims 15 to 16, wherein the sensor comprises a sensor array, such as a fibre optic or discrete sensor array.

18. A tubular assembly as claimed in any one of claims 15 to 17, wherein the tubular assembly includes a transmitter to transmit signals and the transmitter is coupled, physically or wirelessly, to the sensor(s).

19. A tubular assembly as claimed in any preceding claim, wherein the tubular assembly includes a receiver for receiving control signals for the electrically controllable valve, and the receiver is coupled, physically or wirelessly, to the electrically controllable valve.

20. A tubular assembly as claimed in any preceding claim, wherein the electrically controllable valve is wirelessly controllable.

21. A tubular assembly as claimed claim 20, wherein the wireless control is achieved through one or more of acoustic signals, electromagnetic (EM) signals, or coded pressure pulsing.

22. A tubular assembly as claimed claim 21, wherein the wireless control is achieved through one or more of acoustic signals and electromagnetic (EM) signals.

23. A tubular assembly as claimed in any preceding claim, which is battery powered.

24. A tubular assembly as claimed in any preceding claim, wherein there is a plurality of flowpaths in the wall of the outer load-bearing tubular.

25. A tubular assembly as claimed in any preceding claim, wherein the electrically controllable valve is a proportional valve operable to choke fluid flow to various degrees.

26. A tubular assembly as claimed in any preceding claim, wherein a valve assembly comprises the electrically controllable valve, the valve assembly comprising a first outer connection for connection with other outer load-bearing tubulars in a tubular string, a second connector for connection with the outer load-bearing tubular, and a third inner connector for connection with the inner tubular.

27. A tubular assembly as claimed in any preceding claim, connected to other load bearing tubulars, and deployed as part of a tubular string in a well.

28. A tubular string as claimed in claim 27, wherein there is a maximum of two valve assemblies controlling flow between the annular channel and main production bore per tubular assembly.

29. A tubular string as claimed in claim 28, wherein the tubular assembly includes at least two joints of outer load-bearing tubular and at least two joints of inner tubular.

30. A tubular string as claimed in any one of claims 27 to 29, wherein a packer is provided below the tubular assembly, the packer being a pressure-set packer.

31. A tubular string as claimed in any one of claims 27 to 30, wherein there is a plurality of tubular assemblies as part of the tubular string.

32. A tubular string as claimed in claim 31, comprising a pressure-set packer between two tubular assemblies.

33. A well comprising a tubular string as claimed in any one of claims 27 to 32.

34. A well as claimed in claim 33, wherein the tubular assembly is provided in a lateral section of the well.

35. A method for deploying a tubular assembly as claimed in any one of claims 1 to 27 into a borehole, the method comprising running the outer load bearing tubular and inner tubular into the borehole together, rigidly attached to each other below an assembling position.

36. A method for deploying a tubular assembly as claimed in claim 35 comprising: a) suspending at least one outer load-bearing tubular from a rotary table, the outer load-bearing tubular having one of a seal assembly and a seal bore extension; b) optionally connecting at least one further outer load-bearing tubular to said at least one load-bearing tubular, to form a string of outer load-bearing tubulars; c) suspending an inner tubular from a second rotary table, partially inside the outer load-bearing tubular, the inner tubular having the other of a seal assembly and a seal bore extension; d) rotatably connecting a valve assembly to the inner tubular; e) lowering the inner tubular to engage the seal assembly and seal bore extension; f) connecting one end of the valve assembly to the outer load-bearing tubular; g) lowering the outer load-bearing tubular and connected inner tubular; h) attaching a second opposite end of the valve assembly to a tubular string; i) typically deploying the tubular string with attached tubular assembly further into the well.

37. A method as claimed in claim 36, wherein in step d), the valve assembly is rotated as the inner tubular is held rotationally stationary in order to form the third inner connection.

38. A method as claimed in claim 36 or 37, wherein in step f) the valve assembly is stabbed into the outer load-bearing tubular.

39. A method as claimed in claim 38, wherein an outer rotational nut collar is provided to secure the connection between the valve assembly and outer load-bearing tubular.

40. A valve assembly comprising an electrically controllable valve, a first outer connection for connection with a load-bearing tubular in a tubular string, a second connector for connection with the outer load-bearing tubular, and a third inner connector for connection with the inner tubular.

41. A valve assembly as claimed in claim 40, wherein the first connector to the tubular string comprises a threaded connection.

42. A valve assembly as claimed in claim 40 or 41, wherein the second connector to the outer load-bearing tubular comprises a stab-connection.

43. A valve assembly as claimed in claim 42, wherein the second connector also includes a threaded ly mounted nut collar moveable over the stab-connection to secure it.

44. A valve assembly as claimed in any one of claims 40 to 43, wherein the third connector to the inner tubular is a threaded connection.

45. A tubular assembly comprising: an electrically controllable valve; an outer load-bearing tubular having a flowpath through a wall thereof; at least one further outer load-bearing tubular having a flowpath in a wall thereof; an inner tubular and at least one further inner tubular, the inner tubulars inside at least a section of the outer load-bearing tubulars thus defining an annular channel between an inside of said section of the outer load-bearing tubulars and an outside of the inner tubulars, and defining a main production bore inside the inner tubulars and, when the outer tubulars extend beyond said section, inside of the outer load-bearing tubulars beyond said section; a seal between at least one inner tubular and at least one outer load-bearing tubular, wherein the electrically controllable valve is arranged to control flow of fluid between said annular channel and the main production bore.

46. A tubular assembly as claimed in claim 45, which is battery powered.

47. A tubular assembly as claimed in claim 45 or 46, wherein the electrically controllable valve is wirelessly controllable.

48. A tubular assembly as claimed in any one of claims 45 to 47, wherein the annular channel extends for at least 18m.

49. A tubular assembly as claimed in any one of claims 45 to 48, connected to other load bearing tubulars, and deployed as part of a tubular string in a well.

50. A tubular string as claimed in claim 49, wherein there is a maximum of two valve assemblies controlling flow between the annular channel and main production bore per tubular assembly.

51. A method for deploying a tubular assembly as claimed in any one of claims 45 to 50 into a borehole, the method comprising running the outer load bearing tubular and inner tubular into the borehole together, rigidly attached to each other below an assembling position.

52. A method for deploying a tubular assembly into a borehole, the tubular assembly comprising: an electrically controllable valve; an outer load-bearing tubular having a flowpath through a wall thereof; an inner tubular inside at least a section of the outer load-bearing tubular, thus defining an annular channel between an inside of said section of the outer loadbearing tubular and an outside of the inner tubular, and defining a main production bore inside the inner tubular and when the outer tubular extends beyond said section, inside of the outer load-bearing tubular beyond said section; a seal between the inner tubular and the outer load-bearing tubular, and the electrically controllable valve arranged to control flow of fluid between said annular channel and the main production bore; the method comprising: running the outer load bearing tubular and inner tubular into the borehole together, rigidly attached to each other below an assembling position.

53. A method for deploying a tubular assembly as claimed in claim 52 comprising: a) suspending at least one outer load-bearing tubular from a rotary table, the outer loadbearing tubular having one of a seal assembly and a seal bore extension; b) suspending an inner tubular from a second rotary table, partially inside the outer load-bearing tubular, the inner tubular having the other of a seal assembly and a seal bore extension; c) rotatably connecting a valve assembly to the inner tubular; d) lowering the inner tubular to engage the seal assembly and seal bore extension; e) connecting one end of the valve assembly to the outer load-bearing tubular; f) lowering the outer load-bearing tubular and connected inner tubular; g) attaching a second opposite end of the valve assembly to a tubular string; h) typically deploying the tubular string with attached tubular assembly further into the well.