US20090044937A1

US20090044937A1 - Remote actuation of downhole tools using fluid pressure from surface

Info

Publication number: US20090044937A1
Application number: US12/221,999
Authority: US
Inventors: Daniel Purkis
Original assignee: Petrowell Ltd
Current assignee: Petrowell Ltd
Priority date: 2007-08-16
Filing date: 2008-08-08
Publication date: 2009-02-19
Also published as: GB0715970D0; CA2635306A1; AU2008202761A1; BRPI0803502A2; EP2025861A3; EP2025861A2

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.

Description

FIELD OF THE INVENTION

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

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.
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.
Accordingly, the debris prevents such a conventional mechanical pressure mechanism from indexing/cycling and causes the downhole tool to fail to open on command.
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

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:
providing a downhole fluid sensor capable of sensing changes in downhole fluid and installing said sensor downhole;
providing a signal processing means and installing said processing means 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 processing means.
Preferably, the downhole fluid sensor is a downhole fluid pressure sensor.
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:
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.
Preferably, the programmable logic unit is capable of instructing actuation or operation of a tool based upon previously programmed logic.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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

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

FIG. 1 is a schematic representation of a conventional downhole mechanical pressure sensing system and which is not in accordance with the present invention;

FIG. 2 is a graph showing applied fluid pressure at surface versus time;

FIG. 3 is a graph showing the pressure sensed at the downhole tool versus time;

FIG. 4 a is a schematic representation of a downhole pressure sensing system incorporating an apparatus in accordance with the present invention;

FIG. 4 b is a schematic representation of an apparatus in accordance with the present invention;

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;

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. 4 b;

FIG. 7 is a flow chart of the main decisions made by the software; and

FIG. 8 is a graph of pressure versus time showing two peaks as seen and counted by the software within the microprocessor of FIG. 4 b.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

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.
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.
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.
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.
FIGS. 4 a and 4 b 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.
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.
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.
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.
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.
A logic flow chart for the software 60 is shown in FIG. 7 and is generally designated by the reference numeral 80.
In FIG. 7:

- “n” represents a value used by a counter;
- “p” is pressure sensed by the pressure transducer 52;
- “dp/dt” is the change in pressure over the change in time and is used to detect peaks, such as pressure pulses 70A-70D;
- “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.

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.
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.
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.
It should be noted that step 102 could be changed to ask:
“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.
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.
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.
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.

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.