U.S. patent application number 12/221999 was filed with the patent office on 2009-02-19 for remote actuation of downhole tools using fluid pressure from surface.
This patent application is currently assigned to Petrowell Limited. Invention is credited to Daniel Purkis.
Application Number | 20090044937 12/221999 |
Document ID | / |
Family ID | 38566475 |
Filed Date | 2009-02-19 |
United States Patent
Application |
20090044937 |
Kind Code |
A1 |
Purkis; Daniel |
February 19, 2009 |
Remote actuation of downhole tools using fluid pressure from
surface
Abstract
An apparatus for and a method of transmitting signals from the
surface of a well to a location downhole in the well utilize a
downhole fluid pressure sensor, a signal processing means located
downhole in electrical connection with the pressure sensor and a
downhole programmable logic unit capable of counting at least two
signals received by the downhole pressure sensor. Typically,
signals transmitted from the surface comprise a peak in pressure of
downhole fluid located in production tubing run into a well bore
and these signals are sensed by the downhole fluid pressure sensor.
The logic unit outputs a signal to a tool to be actuated if it
receives a number of signals within a particular time period,
wherein the logic unit actuates the tool by the frequency of
signals received rather than the amplitude of the signals
received.
Inventors: |
Purkis; Daniel;
(Aberdeenshire, GB) |
Correspondence
Address: |
DRINKER BIDDLE & REATH;ATTN: INTELLECTUAL PROPERTY GROUP
ONE LOGAN SQUARE, 18TH AND CHERRY STREETS
PHILADELPHIA
PA
19103-6996
US
|
Assignee: |
Petrowell Limited
|
Family ID: |
38566475 |
Appl. No.: |
12/221999 |
Filed: |
August 8, 2008 |
Current U.S.
Class: |
166/72 ;
166/250.15 |
Current CPC
Class: |
E21B 34/10 20130101;
E21B 47/18 20130101 |
Class at
Publication: |
166/72 ;
166/250.15 |
International
Class: |
E21B 34/10 20060101
E21B034/10; E21B 43/12 20060101 E21B043/12 |
Foreign Application Data
Date |
Code |
Application Number |
Aug 16, 2007 |
GB |
0715970.0 |
Claims
1. An apparatus for transmitting signals from the surface of a well
to a location downhole in the well, the apparatus comprising: a
downhole fluid pressure sensor; a signal processor located downhole
in electrical connection with the pressure sensor; and a downhole
programmable logic unit capable of counting at least two signals
received by the downhole pressure sensor.
2. Apparatus as claimed in claim 1, wherein the programmable logic
unit is capable of instructing actuation or operation of a tool
based upon previously programmed logic.
3. Apparatus as claimed in claim 1, wherein the signals transmitted
from the surface comprise a peak in pressure of downhole fluid
located in production tubing run into a well bore.
4. Apparatus as claimed in claim 1, further comprising a mechanism
to increase pressure of fluid at the surface such that the pressure
is transmitted through the fluid to the downhole location.
5. Apparatus as claimed in claim 1, wherein the signal processor
comprises a filter to strip away the value of pressure sensed below
a pre-determined filter level and furthermore the processor
comprises a converter function to convert the value of pressure
sensed from an analogue value into a digital value that can be
input into the logic unit.
6. Apparatus as claimed in claim 1, wherein the logic unit is
adapted to output a signal to a tool to be actuated if it receives
a number of signals within a particular time period, wherein the
logic unit actuates the tool by the frequency of signals received
rather than the amplitude of the signals received.
7. Apparatus as claimed in claim 1, wherein the programmable logic
unit is adapted to observe a peak in pressure and further comprises
a timer adapted to monitor the time elapsed between a pair of peaks
in pressure.
8. Apparatus as claimed in claim 1, wherein the logic unit is
adapted to output a signal to a tool to be actuated if it observes
a particular number of signals received with each signal counting
toward the total observed if it meets certain criteria.
9. Apparatus as claimed in claim 1, wherein a peak in pressure is
regarded as a positive value of change in pressure divided by
change in time and if the actual pressure sensed is greater than a
minimum value.
10. Apparatus as claimed in claim 9, wherein the logic unit
comprises a counter adapted to store a value, wherein the value
stored is indicative of the number of positive peaks in pressure
that are greater than a minimum value that have been observed
wherein only separate peaks that occur within a particular time
interval will count towards the said stored value.
11. Apparatus as claimed in claim 10, wherein the counter is reset
if the time since the last peak or the time between a pair of peaks
is greater than a particular maximum time value wherein the said
particular maximum time value is determined surface prior to
running in to the well bore.
12. Apparatus as claimed in claim 10, wherein the logic unit is
further adapted to hold an actuation value, wherein the logic unit
compares the counter value with the set actuation value and does
not actuate the tool until the counter value matches the set
actuation value at which point the logic unit instructs actuation
of the tool.
13. A method of transmitting signals from the surface of a well to
a location downhole in the well, the method comprising: providing a
downhole fluid sensor capable of sensing changes in downhole fluid
and installing said sensor downhole; providing a signal processor
and installing said processor downhole in electrical connection
with said sensor; and providing a programmable logic unit capable
of counting at least two signals received by the downhole sensor
and installing said logic unit downhole in electrical connection
with said signal processor.
14. A method according to claim 13, wherein the downhole fluid
sensor comprises a downhole fluid pressure sensor.
15. A method according to claim 13, wherein the programmable logic
unit is connected with a tool to be actuated and is capable of
instructing actuation of the downhole tool based upon previously
programmed logic.
16. A method according to claim 13, wherein the signals transmitted
from the surface comprise a peak in pressure of downhole fluid
located in the well bore and the signals are sent from the surface
of the well through the well bore fluid by increasing the pressure
of the fluid at the surface such that the pressure is transmitted
through the fluid to the downhole location where it is sensed by
the downhole fluid sensor.
17. A method according to claim 16, wherein the signal processor
strips away the value of pressure sensed below a filter level.
18. A method according to claim 13, wherein the signal processor
converts the value of pressure sensed from an analogue value into a
digital value that is input into the logic unit.
19. A method according to claim 13, wherein the logic unit outputs
a signal to the tool to be actuated if it receives a number of
signals within a particular time period such that the logic unit is
operated by the frequency of signals received.
20. A method according to claim 13, wherein the programmable logic
unit observes a peak in pressure and monitors the time elapsed
between a pair of peaks in pressure.
21. A method according to claim 13, wherein the logic unit outputs
a signal to a tool to be actuated if it observes a particular
number of signals received with each signal counting toward the
total observed if it meets certain criteria.
22. A method according to claim 13, wherein a peak in pressure is
regarded as a positive value of change in pressure divided by
change in time if the actual pressure sensed is greater than a
minimum value.
23. A method according to claim 13, wherein the logic unit stores a
value indicative of the number of positive peaks in pressure that
are greater than a minimum value that have been observed wherein
only separate peaks that occur within a particular time interval
will count towards the said stored value.
24. A method according to claim 23, wherein the count is reset if
the time since the last peak or the time between a pair of peaks is
greater than a particular maximum time value wherein the said
particular maximum time value is determined prior to running in to
the well bore.
25. A method according to claim 23, wherein the logic unit holds an
actuation value and the logic unit compares the counted value with
the held actuation value and does not actuate the tool until the
counted value matches the held actuation value.
Description
FIELD OF THE INVENTION
[0001] The present invention relates to an apparatus and method of
remotely actuating downhole tools from the surface by using pulses
or signals of pressure.
BACKGROUND TO THE INVENTION
[0002] Conventionally, it is known in the oil and gas production
industry to use downhole tools such as choke valves and the like
that can be remotely actuated from the surface by pressure.
Typically, such tools are mechanically actuated in that the
actuation mechanism comprises a ratchet mechanism which is attached
to a piston wherein an operator at the surface can pressure up
fluid in the production tubing and the pressure will force the
piston to move one length up the ratchet. Such conventional
pressure operated ratchet mechanisms require a certain amplitude of
pressure to move the piston sufficiently to cycle it and can
therefore be thought of as amplitude dependent. Such conventional
systems are usually arranged such that the downhole tool will only
operate after the pressure of the fluid in the production tubing
has been cycled a number of times e.g. five or ten times.
[0003] As shown in FIG. 1, such conventional systems can suffer
from the disadvantage that they become inoperative or their
performance is impaired if debris forms on top of or above the
mechanically arranged pressure operated system in that the debris
can prevent the pressure signal, sent from the surface, registering
the sufficient amplitude against the piston. Such an attenuation of
the downhole fluid pressure is shown in FIG. 3 compared with the
pressure seen at surface as shown in FIG. 2.
[0004] Accordingly, the debris prevents such a conventional
mechanical pressure mechanism from indexing/cycling and causes the
downhole tool to fail to open on command.
[0005] Furthermore, it should be noted that such downhole tools may
require to remain in situ in for example the closed position for
some time whilst other operations within the wellbore are
conducted, such as the upper completion being run above the closed
downhole tool, before they are due to be actuated. Accordingly,
failure of the downhole tool to operate will clearly be a
significant problem and will likely result in rig down time and
various intervention operations which are very costly.
SUMMARY OF THE INVENTION
[0006] According to the present invention there is provided a
method of transmitting signals from the surface of a well to a
location downhole in the well, the method comprising:
[0007] providing a downhole fluid sensor capable of sensing changes
in downhole fluid and installing said sensor downhole;
[0008] providing a signal processing means and installing said
processing means downhole in electrical connection with said
sensor; and
[0009] providing a programmable logic unit capable of counting at
least two signals received by the downhole sensor and installing
said logic unit downhole in electrical connection with said signal
processing means.
[0010] Preferably, the downhole fluid sensor is a downhole fluid
pressure sensor.
[0011] According to the present invention there is provided an
apparatus for transmitting signals from the surface of a well to a
location downhole in the well, the apparatus comprising:
[0012] a downhole fluid pressure sensor;
[0013] a signal processing means located downhole in electrical
connection with the pressure sensor; and
[0014] a downhole programmable logic unit capable of counting at
least two signals received by the downhole pressure sensor.
[0015] Preferably, the programmable logic unit is capable of
instructing actuation or operation of a tool based upon previously
programmed logic.
[0016] Typically, the programmable logic unit is in connection with
(and preferably is in electrical connection with an actuator unit
such as a motor for mechanical actuation or an amplifier for
electrical actuation) a tool to be actuated.
[0017] Preferably, the signals transmitted from the surface
comprise a peak in pressure of the downhole fluid located in the
well bore and more preferably the downhole fluid located in
production tubing run into the well bore.
[0018] Typically, the signals are sent from the surface of the well
through the well bore fluid and more preferably, the signals are
sent by increasing the pressure of the fluid at the surface such
that the pressure is transmitted through the fluid to the downhole
location.
[0019] The signal processing means may comprise an amplifier to
amplify the electrical output of the pressure transducer. The
signal processing means may comprise a filter such as a high pass
filter to strip away the value of pressure sensed below the filter
level. The signal processing means may comprise a converter means
to convert the value of pressure sensed from an analogue value into
a digital value that can be input into the logic unit.
[0020] Preferably, the logic unit is adapted to output a signal to
the tool to be actuated if it receives a number of signals within a
particular time period. In other words, the logic unit is
preferably operated by the frequency of signals received rather
than the amplitude of the signals received as is the case with
conventional methods of actuating downhole tools.
[0021] Typically, the programmable logic unit is adapted to observe
a peak in pressure and is further adapted to monitor the time
elapsed between a pair of peaks in pressure. More preferably, the
logic unit is adapted to output a signal to a tool to be actuated
if it observes a particular number or value of signals received
with each signal counting toward the total observed if it meets
certain criteria.
[0022] Typically, a peak in pressure is regarded as a positive
value of change in pressure divided by change in time. Typically,
the logic unit is adapted to further regard a peak in pressure as
such if the actual pressure sensed is greater than a minimum or set
value.
[0023] Typically, the logic unit comprises a counter adapted to
store a value, wherein the value stored is indicative of the number
of positive peaks in pressure that are greater than a minimum value
that have been observed wherein only separate peaks that occur
within a particular time interval will count towards the said
stored value.
[0024] Preferably, the counter is reset, typically to zero if the
time since the last peak or the time between a pair of peaks is
greater than a particular maximum time value wherein the said
particular maximum time value may be pre-determined or may be set
at the surface prior to running in to the well bore by the
operator.
[0025] Typically, the logic unit is further adapted to hold an
actuation value which may be a pre-determined value or a value set
by an operator at the surface, wherein the logic unit compares the
counter value with the set actuation value and does not actuate the
tool until the counter value matches the set actuation value.
Preferably, once the counter value matches the set actuation value,
the logic unit instructs actuation of the tool by any suitable
means such as chemical, mechanical or electrical means.
BRIEF DESCRIPTION OF THE DRAWINGS
[0026] Embodiments of the present invention will now be described,
by way of example only, with reference to the accompanying
drawings, in which:
[0027] FIG. 1 is a schematic representation of a conventional
downhole mechanical pressure sensing system and which is not in
accordance with the present invention;
[0028] FIG. 2 is a graph showing applied fluid pressure at surface
versus time;
[0029] FIG. 3 is a graph showing the pressure sensed at the
downhole tool versus time;
[0030] FIG. 4a is a schematic representation of a downhole pressure
sensing system incorporating an apparatus in accordance with the
present invention;
[0031] FIG. 4b is a schematic representation of an apparatus in
accordance with the present invention;
[0032] FIG. 5 is the actual pressure sensed at the downhole tool in
the well fluid of signals applied at surface to downhole fluid in
accordance with the present invention;
[0033] FIG. 6 is a graph of the pressure versus time of the well
fluid after the pressure has been output from a high pass filter of
FIG. 4b and is representative of the pressure that is delivered to
the software in the microprocessor as shown in FIG. 4b;
[0034] FIG. 7 is a flow chart of the main decisions made by the
software; and
[0035] FIG. 8 is a graph of pressure versus time showing two peaks
as seen and counted by the software within the microprocessor of
FIG. 4b.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0036] FIG. 1 shows an oil and gas wellbore that has been previous
drilled and lined with a casing string 10 in order to stabilize the
well as is conventionally known. Thereafter, a completion string 20
consisting mainly of production tubing 20 is run into the casing
10. The production tubing string 20 is provided with a barrier 30
such as a flapper valve or a ball valve and, as is conventional,
the barrier 30 is configured in the closed position when the
completion string 20 is being run into the well. However, this can
cause debris 32 to settle out of fluid located in the production
string 20 above the closed barrier 30 to settle on top of the
closed barrier 30.
[0037] The completion string 20 is run into the wellbore to its
desired depth and as is conventionally known, when this occurs, a
signal is sent to the closed barrier 30 to instruct it to open.
This signal can be sent via a control line such as a hydraulic line
which can run from the closed barrier 30 all the way up the outside
of the completion string 20 and up to the surface or more recently
it is known to use a method where the signal can be sent through
the fluid located within the completion/production string 20 in a
series of pressure signals 40A, 40B, 40C, 40D as shown in FIG. 2.
The pressure signals 40A-40D are generated at the surface of the
production string 20 by increasing the pressure within a suitable
fluid pump momentarily which causes the pressure within the
production string 20 to increase. These pressure signals or
pressure pulses 40A-40D will therefore travel quickly down the
fluid contained within the production tubing 20 until they reach a
mechanical pressure sensor 34 located close to, such as just above,
the barrier 30. The mechanical pressure sensor 34 is capable of
sensing pressure pulses and has an indexing system within it, such
as a piston and ratchet arrangement, such that when a pressure
pulse 40A is received and acts upon the piston (not shown) the
piston moves one notch up the ratchet. The ratchet can be arranged
such that after 10 pressure pulses, the mechanical pressure sensor
34 operates to actuate the barrier 30 to open from its closed
position.
[0038] However, as shown in FIG. 1, such conventional systems can
suffer from the disadvantage that the debris 32 can impede the
ability of the mechanical pressure sensor 34 to sense the pressure
pulses 40A-40D and the attenuation of the pressure pulses is shown
in FIG. 3 which shows the pressure signals as seen by the
mechanical pressure sensor 34. Thus, the debris 32 can cause such
an attenuation of the pressure pulses 40A-40D that the amplitude
thereof is no longer sufficient to index the ratchet mechanism.
Accordingly, the barrier 30 can fail to open on command when
required. This can clearly constitute a big problem to the operator
of the oil and gas wellbore since they will then likely need to
conduct a timely and expensive intervention operation and may
indeed need to pull the production tubing string 20 out of the
wellbore.
[0039] In contrast, embodiments of the present invention instead of
operating based upon the amplitude of a pressure pulse 40A-40D,
operate on the frequency of a pulse sequence and compare the number
of acceptable pulses to a predetermined sequence, as will now be
described.
[0040] FIGS. 4a and 4b show an embodiment of an apparatus in
accordance with the present invention generally designated at 50
and which is generally intended to replace a conventional
mechanical pressure sensor 34.
[0041] The apparatus 50 comprises a downhole pressure transducer 52
which is capable of sensing the pressure of well fluid located
within the production tubing string 20 in the locality of (such as
just above) the downhole tool to be operated which in this example
is barrier 30 and outputting a voltage having an amplitude
indicative thereof.
[0042] As an example, FIG. 5 shows a typical electrical signal
output from the pressure transducer where a pressure pulse sequence
70A, 70B, 70C, 70D is clearly shown as being carried on the general
well fluid pressure which, as shown in FIG. 5 is oscillating much
more slowly and represented by sine wave 72. Again, as before, this
pressure pulse sequence 70A-70D is applied to the well fluid
contained within the production tubing 20 at the surface of the
wellbore by using any suitable means or mechanism to increase
pressure in the well fluid such as a pump or the like located at
the surface.
[0043] However, unlike the prior art system shown in FIG. 1, the
presence of debris above the downhole tool and it's attenuation
effect in reducing the amplitude of the pressure signals will not
greatly affect the operation of the embodiment described now.
[0044] The apparatus 50 further comprises an amplifier to amplify
the output of the pressure transducer 52 where the output of the
amplifier is input into a high pass filter which is arranged to
strip the pressure pulse sequence out of the signal as received by
the pressure transducer 52 and the output of the high pass filter
56 is shown in FIG. 6 as comprising a "clean" set of pressure
pulses 70A-70D. The output of the high pass filter 56 is input into
an analogue/digital converter 58, the output of which is input into
a programmable logic unit comprising a microprocessor containing
software 60.
[0045] A logic flow chart for the software 60 is shown in FIG. 7
and is generally designated by the reference numeral 80.
[0046] In FIG. 7: [0047] "n" represents a value used by a counter;
[0048] "p" is pressure sensed by the pressure transducer 52; [0049]
"dp/dt" is the change in pressure over the change in time and is
used to detect peaks, such as pressure pulses 70A-70D; [0050] "n
max" is programmed into the software prior to the apparatus 50
being run into the borehole and could be, for instance, 5 or
10.
[0051] Furthermore, the tolerance value related to timer "a" could
be, for example, 1 minute or 5 minutes or 10 minutes such that
there is a maximum of e.g. 1, 5 or 10 minutes that can be allowed
between pulses 70A-70B. In other words, if the second pulse 70B
does not arrive within that tolerance value then the counter is
reset back to 0 and this helps prevent false actuation of the
barrier 30.
[0052] Furthermore, the step 88 is included to ensure that the
software only regards peak pressure pulses and not inverted drops
or troughs in the pressure of the fluid.
[0053] Also, step 90 is included to ensure that the value of a
pressure peak as shown in FIG. 6 has to be greater than 100 psi in
order to obviate unintentional spikes in the pressure of the
fluid.
[0054] It should be noted that step 102 could be changed to
ask:
[0055] "Is `a` greater than a minimum tolerance value"
such as the tolerance 106 shown in FIG. 8 so that the software
definitely only counts one peak as such.
[0056] Accordingly, when the software logic has cycled a sufficient
number of times such that "n" is greater than "n max" as required
in step 96, a signal is sent by the software to a suitable barrier
actuation tool (not shown) to open the barrier as shown in step
106. The barrier actuation tool could be provided with power from
the surface or could be provided with a suitable downhole power
pack.
[0057] Embodiments of the present invention have the advantage that
much more accurate opening of the barrier 30 will be provided and
much more precise control over opening of the barrier 30 will be
enabled.
[0058] Modifications and improvements may be made to the
embodiments hereinbefore described without departing from the scope
of the invention. For example, the signal sent by the software at
step 106 could be used for other purposes such as injecting a
chemical into e.g. a chemically actuated tool such as a packer or
could be used to operate a motor to actuate another form of
mechanically actuated tool or in the form of an electrical signal
used to actuate an electrically operated tool.
* * * * *