EXTRACTION OF FLUIDS FROM WELLS
This invention relates to controlling the flow of fluids in a well. It is particularly, but
not exclusively, related to controlling the flow of hydrocarbons.
An oil or gas well, hereinafter referred to as a well, is constructed by drilling a borehole and then lining it with a steel casing which is cemented into position. A conduit for carrying hydrocarbons from a lower region of the well to the surface, referred to as production tubing, is inserted into the casing and extends from the surface to the lower region from where hydrocarbons are extracted. The space created between the casing and the production tubing is referred to as the annulus.
Intake of hydrocarbons into the production tubing is either via an open lower end, one or more regions provided with ports along its length or both. Devices referred to as packers are provided between the production tubing and the casing to prevent hydrocarbons flowing up the annulus rather than up the production tubing.
It should be noted that material other than hydrocarbons, whether in liquid or gaseous form, can flow along the production tubing. It may convey debris remaining from
drilling, released interstitial water, sand or particles of rock. The term hydrocarbons
is used purely for convenience, although it should be understood that these other
materials may be present. Furthermore, materials may be conveyed from the surface to the lower region, such as chemicals, including water, which are provided to assist 2 in the extraction of hydrocarbons.
In view of the high cost of extracting hydrocarbons from wells it is desirable to recover
as high a proportion of hydrocarbons as is possible from in-place reserves.
It has been recognised that the amount of hydrocarbons which is extracted from a well
can be increased if flow control means are provided in the well to control the flow of
hydrocarbons. An example is an annular isolation valve. These flow control means are referred to as chokes. To locate such chokes in the well, it is convenient to provide them on the production tubing to control the flow of hydrocarbons from the exterior of the tubing into its interior. To improve operation of a well further, it has been proposed to make measurements of flow rate of hydrocarbons in the production tubing and temperature and pressure of hydrocarbons in the well and to use this information to control the chokes. Devices located in the well are referred to as downhole devices.
A simple version of a choke comprises a body provided with a set of holes carrying a
moveable sleeve. Movement of the sleeve relative to the body exposes or covers the
holes. In another embodiment the body is provided with a first set of holes and the
sleeve is provided with a second set of holes. Relative movement of the body and
sleeve allows the first and second series of holes to move in to and out of registration
with each other, thus enabling and disabling flow of hydrocarbons through the choke.
The relative movement can be parallel to the axis of the production tubing or about it. 3
An example of a known choke-controlled well 100 is shown in Figure 1. The well 100
has a wellhead 102 controlling a main bore 103 which extends down into a
hydrocarbon bearing zone 104. Although the zone 104 may not be very thick (for
example 10 to 100m) it has a considerable lateral extent (for example several
kilometres). There is another hydrocarbon bearing zone 106 which is in the form of
an isolated pocket. The zone 104 is large enough to justify the cost of drilling the well
100. In order to maximise extraction of the hydrocarbons, on entering the zone 104,
the well extends in the form of a horizontal leg 108 to extract hydrocarbons from a significant extent of the zone 104. However, hydrocarbon bearing zones are rarely
uniform and it is common for water to break into a long horizontal well at some point along its horizontal length before extraction of hydrocarbons is complete along its entirety. Therefore, the leg 108 is provided with a number of chokes 110 in respective sealed regions 112 which control the intake of hydrocarbons into the leg 108. The regions may not necessarily be hermetically sealed. Should water break into any sealed region, its choke can be activated so as to prevent fluid extraction from that sealed
region. The zone 106 is not large enough to justify the cost of drilling a separate well
and so the well is provided with a branch or lateral 114 to extract hydrocarbons from
the zone 106. Flow of hydrocarbons from the lateral 114 into the main bore 103 is
controlled by a choke 116.
It should be noted that the horizontal leg 108 can extend for many kilometres. The
longer the leg is, the more uneven is fluid flow along it. Therefore, rather than having
a long horizontal leg, a similar length of horizontal well can be provided by two 4 shorter horizontal legs branching off into the zone 104 in opposite directions from a
common junction point. The shape of the well is similar to an inverted T. The
common junction point may be controlled by a choke.
In controlling a two zone well, typically an upper hydrocarbon layer separated from
a lower hydrocarbon layer by an intermediate impermeable layer, generally it is not
efficient to extract hydrocarbons in one continuous operation from one zone until it is
exhausted and then extract in another continuous operation from the other zone until
that also is exhausted. It is usually more efficient to alternate extraction operations a number of times between the two zones. Once an extraction operation from a first zone has occurred, the zone is left to recover whilst an extraction operation from the other (second) zone takes place. When the first zone has recovered it can undergo another extraction operation. Proportionally more in-place hydrocarbon reserves can be extracted if the zones are allowed to recover. Furthermore, a greater proportion of extracted hydrocarbons is extracted earlier in the lifetime of the well. Remotely
controlled chokes are highly suited to alternate extraction operations.
The reliability of downhole devices is of considerable commercial importance. Firstly,
the production lifetime of a well can be in the region of decades and so downhole
devices can be in situ for a long period of time. Secondly, any repair or replacement
operation can affect the operation of the well and can, in most cases, require the well
to be shut down whilst a part of the whole of the production tubing is removed.
Intervention costs for a well can cost in the region of $1 million per day. Clearly, it 5 is desirable for a well to be shut down as infrequently as possible during its lifetime.
Endeavours to improve reliability of downhole flow control systems have so far
concentrated on improving the choke so as to reduce the likelihood of it jamming and
also improving the reliability of the mechanism used to actuate the choke.
According to a first aspect of the present invention there is provided a control system for controlling flow of fluid in a well comprising a first control circuit, a second
control circuit, a downhole device and selection means, the selection means switching control of the downhole device from the first control circuit to the second control circuit, in which one of the control circuits is hydraulic and the other of the control
circuits is electrical.
Preferably the downhole device is a choke.
Preferably the first control circuit is wholly hydraulic. Conveniently the first control circuit includes a hydraulic actuator for controlling the downhole device. Preferably
the second control circuit is wholly electrical. Conveniently the second control circuit
includes an electrical actuator for controlling the downhole device. Alternatively the
second control circuit is electro-hydraulic. It may include a hydraulic actuator to
control the downhole device which is itself controlled by at least one electrical control
signal. 6
Preferably there are a plurality of downhole devices. There may be two, three, four,
five or six. There may be more than six.
In embodiments of the invention having a plurality of downhole devices individual
devices or individual groups of devices can be selected to operate. They may be
selected to operate by selection logic such as hydraulic addressing by the hydraulic
control circuit or electrical addressing by the electrical control circuit.
Preferably control of the downhole device is switched from the first control circuit to the second control circuit in the event of failure occurring which prevents normal operation of the downhole device by the first control circuit. Therefore the system is provided with redundancy in the event of failure. Alternatively switching control may simply be as a result of considerations other than failure such as a matter of choice by an operator or automated control system.
According to a second aspect of the invention there is provided a control module for
controlling a downhole device the control module having a hydraulic actuator and an
electrical actuator.
Preferably the control module also comprises the downhole device.
According to a third aspect of the invention there is provided a well comprising at least
one control module in accordance with the second aspect of the invention. 7 According to a fourth aspect of the invention there is provided a well comprising at
least one control system in accordance with the first aspect of the invention.
According to a fifth aspect of the invention there is provided a method of operating a
well comprising the steps of controlling a downhole device by a first control circuit and
switching control to a second control circuit in which one of the control circuits is a
hydraulic control circuit and the other of the control circuits is an electrical control
circuit.
Preferably the well is a production well. It may be for producing oil, gas or both. Alternatively it may be an injection well.
Preferably the control circuits control separate actuators which, in turn, control the downhole device. Alternatively the control circuits control the same actuator.
An embodiment of the invention will now be described by way of example only with
reference to the accompanying drawings in which:
Figure 1 shows a schematic illustration of a production well;
Figure 2 shows a schematic illustration of a control system;
Figure 3 shows a diagrammatic representation of a production well;
Figure 4 shows a choke;
Figure 5 shows a cross section of a flat pack control cable;
Figure 6 shows in schematic form a control system for a production well; 8 Figure 7 shows a hydraulic decoder;
Figure 8 shows a number of control modules of the control system in a ring
arrangement; and
Figure 9 shows detail of one of the control modules of Figure 8.
In the following description, the invention is described in relation to subsea use. In
such an application a part of the control system is located downhole and a part of the
control system is located on the seabed and a final part which supplies power and control signals is located on a platform or land based installation. However, the
invention also applies to a wholly autonomous intelligent well in which processing means are provided downhole to analyse operating parameters of the well and control its operation accordingly with little or no intervention from outside of the well.
Figure 2 shows a schematic illustration of a control system 220 providing control of a well 222 from a platform 224. In this specific embodiment of the invention, the
platform is an oil rig. Located on the platform 224 is an electrical power supply unit
226, a hydraulic power supply unit 228 and an electrical control unit 230. Outputs
from each of these units are routed to a junction box 232 at which they are combined
and packaged into an umbilical 234 which passes from the platform 224 to the seabed
238. There is also provided a chemical injection unit 229 on the platform which
supplies chemicals to be pumped into the well 222 to assist in extraction of
hydrocarbons. 9
The umbilical 234 is terminated at an umbilical termination assembly 240 which
distributes hydraulic and electrical power and control signals to a subsea control
module (SCM) 242. The subsea control module provides control for actuators located
on a tree 244, also known as a Christmas tree or xmas tree, which is located on the
wellhead. These actuators are used to open and close valves which are used to control
the flow of chemicals and hydrocarbons through the tree. The SCM also provides the
hydraulic and electrical power and control signals to operate a downhole device 246
in the well 222. It also monitors and/or interrogates a number of sensors located on the tree. In addition any electrical or optical power/control for the downhole equipment can be sourced or routed via the SCM.
A diagrammatic representation of a known well 10 is shown in Figure 3. This shows a bore 12 lined with a casing 14 which contains production tubing 16. The casing extends from the surface 18 until the end or toe 20 of the bore 12. It should be
understood that in this described embodiment the surface 18 is the seabed. The casing 14 supports a tubing hanger 22 which in turn supports the production tubing 16. The
casing 14 and production tubing 16 are separated by a space 24 which is referred to as
an annulus. The annulus serves a number of purposes. It can be used to detect fluid
leakage from the production tubing 16. When extracting viscous liquid hydrocarbons
pressurised gas can be introduced down the annulus and introduced into the production
tubing through one-way valves along its length so as to provide a gas lift and assist
extraction. 10
Tubing hanger 22 accommodates a bore for the production tubing 16, a bore to allow
access to the annulus 24 and one or more bores to allow passage of lines for downhole
control and sensing operations. Therefore in plan area much of the tubing hanger is
occupied.
At about 300m from the surface 18 the production tubing 16 has a SCSSV (surface
controlled subsurface safety valve) 25. This is an emergency shut-off valve which
closes on loss of hydraulic power to the SCM to provide a barrier to the uncontrolled flow of hydrocarbons. The barrier is intentionally located below the wellhead to protect the aquatic environment in the event of a failure of the tree or wellhead.
Along its extent the casing 14 passes through a number of hydrocarbon bearing zones 26 and 28 from which hydrocarbons such as oil and gas are extracted. Within each zone a part or region of the casing 14 is open such that hydrocarbons can flow into its
interior. Within zone 26 the wall of the casing 14 is perforated. Within zone 28 the casing has an open end 30. The production tubing 16 is likewise provided with ports
which correspond to those present in the casing 14. Therefore the production tubing
16 has ports in zones 26 and 28.
In known wells the production tubing may be provided with an electrical submersible
pump (ESP) at the well toe to pump hydrocarbons from the lower region of the well.
This is convenient if the hydrocarbon bearing zone being abstracted is at low pressure.
It is important to monitor the temperature of the pump to check that it is not 11 overheating. This is because in the event of the ESP failing a workover of the well is
required.
It is important to isolate the hydrocarbon bearing zones 26 and 28 from non-
hydrocarbon bearing zones 32 and 34. If these zones contain aquifer layers from
which water is extracted, allowing communication between the aquifer layers and the
zones 26 and 28 can cause their contamination. Therefore the annulus 24 is divided
into compartments 36, 38 and 40 divided by packers 42, 44 and 46 which prevent transfer of material between hydrocarbon bearing zones 26 and 28 and non- hydrocarbon bearing zones 32 and 34 occurring along the annulus 24.
Hydrocarbons present in the zones 26 and 28 may be at different pressures. If the pressures are considerably different, hydrocarbons could flow from one zone to another rather than up the production tubing 16 if there is unrestricted communication between
the zones. For this reason variable chokes 48 and 49 are provided to restrict flow from zones 26 and 28 into the production tubing 16. Two chokes are needed to control
extraction of hydrocarbons from two zones. Generally, n chokes can control n zones.
In order to control the flow of hydrocarbons, a sensor is provided to measure
temperature and pressure in the production tubing 16. Typically, the sensor is placed
in the annulus 24 adjacent to a packer 42, 44 and 46 in a region of the annulus 24
isolated from hydrocarbon bearing zones. This is because the hydrocarbons may be
under pressure and may be corrosive. The sensor takes its measurements through a 12 port provided in the wall of the production tubing 16.
Figure 4 shows a choke in greater detail. It comprises a non-perforated sleeve 410
between an open configuration (a) in which ports 412 in the production tubing 16 are
exposed and a closed configuration (b) in which the ports 412 are covered. In the
closed configuration the interior of the production tubing 16 is isolated from the
annulus 24. In the open configuration hydrocarbon flow can occur through the ports
and into the production tubing 16. The choke described in Figure 4 is a simple on/off
device. An alternative embodiment of a choke has a number of intermediate positions definable between the open and closed configurations. These positions allow a variable choking effect on the fluid flow, thus enabling a variable pressure drop to be applied.
Although Figure 4 shows a sleeve which moves in a direction parallel to the longitudinal axis of the production tubing, a sleeve which moves circumferentially
about the production tubing could be used to align and misalign two sets of ports.
A flat pack is used to supply hydraulic power, electrical power and communications,
that is control signals, to downhole devices. A cross-section of a flat pack is shown
in Figure 5 and designated by the numeral 510. The flat-pack contains a hydraulic
fluid power line 512, an electrical power line 514 and a communications line 516
containing a twisted pair 518 and 520. All of the lines 512, 514 and 516 comprise
steel jackets or tubes. Due to space constraints within the tubing hanger 22, and in the
annulus 24 between the production tubing 16 and casing 14, the flat pack has a 13 maximum size. Therefore there is a limitation on the number of lines and the outer
diameter of their steel tubes (which is typically less than 1cm).
Figure 6 shows a control system 50 for a production well. The control system 50 has
two flat packs 52 and 54 which extend down the annulus 24. The use of two flat packs
provides an additional level of redundancy within the system. With two flat packs
there are, in total, two hydraulic lines, two electrical power lines and two communication lines extending down the well. Each flat pack extends down the
annulus 24 as far as the most distant choke. In a practical embodiment of the system the flat packs 52 and 54 are strapped to the outside of the production tubing 16 on opposite sides. In this way a damaging impact to one side of the production tubing is less likely to damage both flat packs.
The flat packs enable control of downhole control modules 56 and 58 incorporating
chokes 60 and 62 respectively. The control modules are integrated into the production tubing 16 as individual sections to be connected in-line allowing through-flow of
hydrocarbons. The chokes 60 and 62 are controlled by either a hydraulic actuator 64
or an electrical actuator 66 each of which is controlled by respective hydraulic and
electrical decoders 68 and 70. Both the hydraulic and electrical actuators share a
common coupling to the moving section of the chokes 60 and 62.
The flat packs 52 and 54 each have a hydraulic control line 72 or 74, an electrical
power line 76 and a communications line 78. Each flat pack terminates at the top of 14 each control module and then extends onward from its bottom. The lines 72, 74, 76
and 78 extend through the control module which can extract appropriate power and
signals.
The control system has a hydraulic control circuit comprising hydraulic control lines
72 and 74, the hydraulic decoder 68 and the hydraulic actuator 64. The control system
also has an electrical control circuit comprising the electrical power lines 76, the
communications lines 78, the electrical decoder 70 and the electrical actuator 66. Each control circuit is capable of over-riding the other.
Hydraulic operation of the chokes 60 and 62 by the hydraulic control circuit is the primary control mode of the control modules 56 and 58. An example of a hydraulic decoder 68 and hydraulic actuator 64 combination is shown in Figure 7. The hydraulic
control lines 72 and 74 each feed into respective pairs of valves 80 and 82 and 84 and 86. Hydraulic control line 72 provides a standing hydraulic supply to control the
hydraulic actuator 64. Hydraulic control line 74 provides a variable hydraulic supply
which is used to control, that is switch on and off, the hydraulic actuator 64. Referring
now to valves 80 and 82, they are configured such that, in the absence of the variable
hydraulic supply valve 80 is closed (that is it does not transmit the standing hydraulic
supply) and valve 82 is open (that is it does transmit the standing hydraulic supply).
Naive 80 is configured to energise at lOOOpsi and valve 82 is configured to energise
as 1200psi. If hydraulic supply from line 72 is increased to be between 1000 and
1200psi, valve 80 energises into an open state. Since valve 82 is already open, the 15 standing hydraulic supply is transmitted through the decoder 68 to provide the actuator
64 with a control signal 88. Once the variable hydraulic supply exceeds 1200psi, valve
82 energises into a closed state thus preventing transmission of the standing hydraulic
supply to the actuator 64. The functionality provided by the pairs of valves 80 and 82
and 84 and 86 could be incorporated into a single valve assembly for each pair.
The valves 84 and 86 are in a similar "one open, one closed" configuration in the
absence of the variable hydraulic supply. Valves 84 and 86 are configured to activate
at 1500psi and 1700psi respectively. Therefore, the standing hydraulic supply is transmitted through the combination of valves 84 and 86 when the variable hydraulic supply is between 1500psi and 1700psi thus providing the actuator 64 with a control signal 90. When the actuator 64 receives the control signal 88 it actuates so as to open the choke. When the actuator 64 receives the control signal 90 it actuates so as to close the choke. Therefore opening and closing of the choke is a wholly hydraulic operation. The electrical power and communications lines in the flat packs are
redundant for normal hydraulic operation of the choke. It is preferred to have a control
module which opens and closes the choke in response to separate positive signals. In
this way if the control module fails it fails in an "as is" condition.
The hydraulic decoders in each control module are activated at different pressures
applied by the variable hydraulic supply. Therefore a number of control modules can
be selectively operated by applying an appropriate hydraulic supply along line 72. 16
Electrical operation of the chokes 60 and 62 by the electrical control circuit is the
secondary control mode of the control modules 56 and 58. In the embodiment
described in relation to Figure 6 each electrical decoder 70 is provided with an
individual address. Addressing an individual decoder electrically is a well known
technique and industry standard communications protocols and signal encoding can be
employed. Figure 6 shows the control modules 56 and 58 taking their electrical power
from electrical power lines 76 and communications lines 78 from both of the flat packs
52 and 54. In secondary control mode the control modules are controlled by the
provision of electrical power and control signals along a single flat pack.
It should be noted that a number of actuators, whether hydraulic or electrical, are dropped off the same hydraulic and electrical lines. In this way the number of lines required to operate a number of downholes devices is kept to a minimum.
In the event of a failure of hydrauHc control, caused by, for example, breakage of one
of the flat packs 52 or 54, primary hydraulic control is no longer possible because both
hydraulic lines 72 and 74 are needed in order to address individual hydraulic actuators.
In this event, the control system 50 switches to the secondary control mode. If
hydraulic failure occurs topside (that is in the tubing hanger or above), the electrical
power and communications lines in either of the flat packs 52 or 54 may be used. If
the failure occurs due to a break in a flat pack, this causes one of the communications
lines 78 to be lost and so the communications line in the remaining flat pack is used to
control the well. 17 Failure may be detected in a number of ways. Detecting loss of hydraulic power in the
line may indicate a break. A position sensor connected to a moveable part of the choke
such as the sliding sleeve may indicate that it is not moving in response to instructions
to do so. Sensors in the production tubing may indicate that there is no change in
pressure or flow rate or both in response to a command being given for the choke to
change its configuration. Failure detection means are provided to detect failure and to
control selection means to switch control from the primary to the secondary control
mode. The failure detection means and the selection means can conveniently be located in the electrical control unit 230 shown in Figure 2.
In the embodiment of the invention described above control is either exclusively hydrauhc or electrical. It does not use electro-hydraulic control in which an electrical signal controls an electrical control valve which drives a hydraulic actuator to control the choke. A disadvantage of electro-hydraulic control is that it requires a maintained provision both of electrical and hydraulic power. Failure of either causes failure of
electro-hydraulic control. However, in other embodiments of the invention, electro-
hydraulic control may be employed. In such an embodiment the control modules 56
and 58 are provided with hydraulic switching means to switch hydraulic supply to the
hydraulic decoder to feed directly an electro-hydraulic actuator which controls the
hydraulic supply by using an electrical control signal. The hydraulic switching means
may be activated by an electrical signal. Because a single flat pack contains hydraulic
and electrical power supplies and electrical control signals, electro-hydraulic control
is still possible in the event of one of the flat packs breaking or failing. 18
Associated with the choke assembly is a series of sensors. Typically these would
monitor the following physical parameters:
(i) configuration of the choke;
(ii) pressure and temperature inside the choke (in the production tubing);
(iii) pressure and temperature in the annulus; and
(iv) flow rate of hydrocarbons in the production tubing.
The sensors are monitored and/or interrogated locally by the control module on the
choke and information derived is sent to the SCM. However, they may be monitored and/or interrogated remotely from the wellhead or the platform. Such remote
interrogation would be appropriate for sensors which are optical in nature and relay an optical signal by one or more optical fibres. Other downhole devices can be operated (that is controlled, monitored or both) by the control system. Conveniently they can be integrated with the control and communication infrastructure of the control system. Examples of such downhole devices are flow meters, remotely set production packers and gas lift valves. It is necessary for regulatory purposes to have one flowmeter for
each zone to measure hydrocarbon flow rate in the production tubing. Although a
position sensor is also provided to detect the configuration (open or closed) of the
choke, if pressure is measured both inside and outside of the production tubing, the
configuration of the choke can be confirmed independently.
It is preferred for the control modules which are disposed along the production tubing
to have their electrical control signals connected in a ring architecture. This can be
observed in Figure 8. Hydraulic services and electrical power are connected in series 19 with each control module tapping into the hydraulic and electrical power lines which
pass through it. A number of control modules 810 are connected by flat pack 812
which provides an outward leg connecting a master controller 814 located in the SCM
to the control modules 810 in series. Another flat pack 816 provides a return leg
travelling from one of the control modules 810 back to the master controller 814. The
flat packs each comprise a hydraulic power line 872 or 874, an electrical power line
876 and a communications line 878. It should be understood that all of the control
modules are located in a strict serial arrangement along the length of the production tubing (which is not shown in this Figure). The flat packs are not continuous but
terminate at each control module and re-start another length to the next control module or to the master controller.
Figure 9 shows a schematic illustration of one of the control modules of Figure 8.
Two flat packs 912 and 916 enter the control module 900 from above. The flat packs 912 and 916 carry respective hydraulic power lines 972 and 974, electrical power lines
976 and communications lines 978.
The hydraulic power lines 972 and 974 are supplied to a hydraulic decoder 968. If the
control module 900 is operating in primary control mode and the decoder 968 is
addressed it activates hydraulic actuator 964 to drive common drive means 902 to
change the configuration of the choke 960. 20 The electrical power lines 976 and a single communications line 978 are supplied to an
electrical decoder 970. If the control module 900 is operating in secondary control
mode and the decoder 970 is addressed by an electrical control signal it activates
electrical actuator 966 to drive the common drive means 902 to change the
configuration of the choke 960.
A position sensor 904 is connected to the common drive means 902 to sense if the choke 960 is open or closed.
The control module 900 is also provided with a pressure sensor 906 and a temperature sensor 908 to measure the pressure and the temperature of the hydrocarbons flowing in the production tube.
Signals from all of the sensors 904, 906 and 908 are combined together at a multiplexer 909 and transmitted to the wellhead, SCM or platform by a sensor
communications line 910.
It should be noted that although the flat packs stop and start at each control module (in
which electrical and hydraulic services are extracted), the electrical power lines and
hydrauhc power lines pass straight through. Electrical and hydraulic power are tapped
off by each control module. One of the communications lines 978 likewise passes
straight through each control module. However, the other communications line 978
provides an input to the electrical decoder 970 to enable it to determine if it is being 21 addressed. Once the electrical decoder 970 has analysed a series of control signals, it
passes them on along a continuation of communications line 978. At the bottom of the
control module, the lines 972, 974, 976 and 978 are repackaged into the flat packs 912
and 914 to go to the next control module or to the master controller.
Referring back now to Figure 8, the ring architecture of the communications lines will
be described. In the following description the control modules 810 are referred to as
nodes. Electrical control signals can be routed around the ring bidirectionally. As can
be appreciated, if a first flat pack is used to connect all of the nodes in series from a first node (which is closest to the surface) to an nth node, (which is closest to the toe of the well) and the other (second) flat pack serves as a return leg running from the nth
node to the master controller then a break occurring in the first flat pack close to the surface requires communication to nodes which are immediately below the break to be
routed down the second flat pack to the nth node and then up the first flat pack and to the node immediately below the break. In the arrangement of Figure 8, the first flat pack has a first connection made to the first node 820, and the second flat pack has a
first connection made to the second node 822. The third and further nodes are
connected in series from the first node by the first flat pack. Since all of the nodes are
grouped relatively far down the well, connecting the master controller 814 to the first
and second nodes by different flat packs results in the maximum distance between a
node and the master controller being kept to a minimum.
The nodes serve as repeaters for electrical control signals. Since the communications 22 lines are arranged in a ring electrical control signals are received by an electrical
processor in each control module which extracts control signals specific to it and passes
on the electrical control signal to the next control module in the ring.
The control modules each receive an electrical power supply provided by both flat
packs. Since power need only be drawn from one of the flat packs, each control
module has an arrangement of diodes to consolidate the electrical power supply and
prevent flow of electrical power from one electrical power line to the other. In an embodiment having electro- hydraulic control, only one hydraulic supply is required, and so the two hydraulic power supplies can be consolidated by analogous techniques such as controlling each supply with a check valve (non-return valve) and combining
the two supplies. Consolidation of the two hydraulic lines is only a requirement for electro-hydraulic control because only one hydraulic power line is required.
The choke can be operated by two independent control circuits, one being hydraulic
and the other being electrical. Loss of either hydraulic or electrical power will not
prevent operation of the choke. If full redundancy is required between the flat packs,
then an electro-hydraulic control circuit is required in order to switch electrically the
hydraulic supply to operate the choke. In this way the functionality of the first flat
pack can be fully repeated in the second, thus providing full redundancy for each flat
pack on its own.
In the foregoing the invention has been described applied to a production well. It may 23 equally apply to an injection well in which water or another fluid is pumped into a
region of a production zone distant from a region where extraction is occurring in order
to maintain pressure in the production zone and to flush out the zone. Although the
invention has been described in relation to subsea wells and installations, it is not
limited to such use. It may, with appropriate modifications, be used in a land based
well.