Remote actuation of downhole tools using fluid pressure from surface
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.
Latest Patents:
- Instrument for endoscopic applications
- DRAM circuitry and method of forming DRAM circuitry
- Method for forming a semiconductor structure having second isolation structures located between adjacent active areas
- Semiconductor memory structure and the method for forming the same
- Electrical appliance arrangement having an electrical appliance which can be fastened to a support element, in particular a wall
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 INVENTIONConventionally, 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
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 INVENTIONAccording 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.
Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which:
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
However, as shown in
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.
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,
However, unlike the prior art system shown in
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
A logic flow chart for the software 60 is shown in
In
-
- “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
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
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.
Type: Application
Filed: Aug 8, 2008
Publication Date: Feb 19, 2009
Applicant:
Inventor: Daniel Purkis (Aberdeenshire)
Application Number: 12/221,999
International Classification: E21B 34/10 (20060101); E21B 43/12 (20060101);