Wireless communication

Abstract

A method for use in controlling pressure based signal transmission within a fluid in a flowline includes transmitting a pressure based signal through a fluid within a flowline using a flow control device, recognising a condition change associated with the flowline, and then controlling the flow control device in accordance with the condition change. Another method, or an associated method for use in communication within a flowline includes determining or composing an optimised pressure based signal for detection at a remote location and then transmitting the optimised signal using a flow control device.

Claims

1. A method for autonomously controlling communication from a downhole communication system located downhole within a production well, the downhole communication system including a monitoring system, a controller and a flow control device, wherein the method comprises: (i) obtaining data relating to at least one downhole parameter using the monitoring system; (ii) using the controller to operate the flow control device to impart a pressure based signal on production fluid flowing along a flowline within the production well such that the pressure based signal is transmitted through the flowing production fluid towards a receiver, the pressure based signal being representative of the data; (iii) regularly repeating steps (i) and (ii) to transmit multiple pressure based signals through the flowing production fluid; (iv) using the monitoring system and the controller to monitor for a condition change within the production well indicative of a flowline shut-in event by (a) measuring a wellbore pressure associated with the production well during normal production, (b) monitoring the wellbore pressure to determine if an increase in the wellbore pressure relative to the wellbore pressure during the normal production exceeds a threshold, (c) measuring a length of time the increase in the wellbore pressure exceeds the threshold, and (d) recognizing the flowline shut-in event in response to the length of time the increase in wellborn pressure exceeds the threshold being greater than a set characteristic time factor; (v) in response to recognising the flowline shut-in event, using the controller to control the flow control device to cease signal transmission through the production fluid and to measure the wellbore pressure during the flowline shut-in event and store at least a maximum value of the wellbore pressure during the flowline shut-in event; (vi) using the monitoring system and the controller to monitor for a condition change within the production well indicative of a flow initiating event; and (vii) in response to recognising the flow initiating event repeating at least steps (i) and (ii) and transmitting data indicating at least the maximum value of the wellbore pressure during the flowline shut-in event via the pressure based signal.

2. The method according to claim 1, wherein the downhole parameter is associated with at least one of the production fluid, the flowline, the flow control device and adjacent regions or components.

3. The method according to claim 1, wherein the pressure based signal comprises at least one pressure variation imparted within the production fluid by the flow control device.

4. The method according to claim 3, wherein the pressure based signal comprises or defines at least one signal parameter including at least one of amplitude, a pulse width and a pulse separation.

5. The method according to claim 1, wherein the flow control device is controlled to optimise the pressure based signal.

6. The method according to claim 5, wherein optimisation is achieved in terms of creating and/or maintaining an optimum pressure based signal which permits detection of the signal by the receiver.

7. The method according to claim 5, further comprising: modifying one or more parameters of the pressure based signal to optimise said pressure based signal.

8. The method according to claim 1, comprising: controlling the flow control device by modifying operational parameters stored within the flow control device.

9. The method according to claim 8, wherein the flow control device is operated in accordance with specific algorithms or protocols, wherein such algorithms or protocols are modified in accordance with a recognised condition change within the flowline.

10. The method according to claim 8, wherein the flow control device comprises a parameter matrix, and the method further comprises: modifying parameters within the parameter matrix in accordance with the condition change.

11. The method according to claim 1, wherein monitoring is provided by use of one or more sensors.

12. The method according to claim 11, wherein at least one sensor is provided exclusively for the monitoring.

13. The method according to claim 11, wherein at least one sensor is provided for both data collection to be transmitted and the monitoring.

14. The method according to claim 1, wherein the recognising comprises: recognising at least one of a pressure condition change, a temperature condition change, a flow rate condition change and a fluid composition condition change.

15. The method according to claim 1, further comprising: determining or composing an optimised signal for detection at a remote location; and transmitting said optimised signal using the flow control device.

16. The method according to claim 15, further comprising: composing or determining an optimised pressure based signal in accordance with a simulation associated with the flowline.

17. The method according to claim 15, further comprising: composing or determining an optimised pressure based signal by transmitting one or more test signals.

18. The method according to claim 15, further comprising: transmitting a plurality of pressure based test signals; receiving at least one of the pressure based test signals at the receiver; determining or selecting an optimal signal from the received pressure based test signals; and transmitting a determined or selected optimal pressure based signal through the production fluid within the flowline.

19. The method according to claim 18, wherein the receiving at least one pressure based test signal includes receiving a plurality of pressure based test signals at the receiver, and the determining or selecting determines or selects an optimal pressure based signal from the received pressure based test signals.

20. The method according to claim 18, wherein the least one pressure based test signal includes two or more pressure based test signals composed with at least one different signal parameter.

21. The method according to claim 18, further comprising: communicating a positive determination of an optimal pressure based signal from the receiver to the flow control device.

22. The method according to claim 21, wherein the communicating comprises: communicating a positive determination by wireless transmission of the determined optimal pressure based signal.

23. The method according to claim 21, wherein the communicating comprises: communicating a positive determination by performance or initiation of a recognisable event within the flowline, such as a shut-in event.

24. A downhole communication apparatus for autonomous communication from a downhole location within a production well, the downhole communication apparatus comprising: a monitoring system configured to obtain data relating to at least one downhole parameter; a flow control device configured to impart a pressure based signal on production fluid flowing along a flowline within the production well such that the pressure based signal is transmitted through the flowing production fluid towards a receiver; and a controller configured to receive the data from the monitoring system and operate the flow control device based on the data from the monitoring system by, monitoring for a condition change within the production well indicative of a flowline shut-in event by (a) measuring a wellbore pressure associated with the production well during normal production, (b) monitoring the wellbore pressure to determine if an increase in the wellbore pressure relative to the wellbore pressure during the normal production exceeds a threshold, (c) measuring a length of time the increase in the wellbore pressure exceeds the threshold, and (d) recognizing the flowline shut-in event in response to the length of time the increase in wellborn pressure exceeds the threshold being greater than a set characteristic time factor, in response to recognising the flowline shut-in event, controlling the flow control device to cease signal transmission through the production fluid and to measure the wellbore pressure during the flowline shut-in event and store at least a maximum value of the wellbore pressure during the flowline shut-in event, monitor for a condition change within the production well indicative of a flow initiating event, and in response to recognising the flow initiating event, operate the flow control device to reinitiate pressure based signal transmission through the flowing production fluid towards the receiver and transmit data indicating at least the maximum value of the wellbore pressure during the flowline shut-in event via the pressure based signal.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) These and other aspects of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which:

(2) FIG. 1 is a diagrammatic illustration of a wellbore arrangement subject to wireless communication of signals in accordance with an embodiment of the present invention;

(3) FIG. 2 is a diagrammatic illustration of a modified wellbore arrangement which is also subject to wireless communication of signals in accordance with an embodiment of the present invention;

(4) FIG. 3 illustrates an exemplary embodiment a flow control device which is used for wireless communication within a wellbore;

(5) FIG. 4 illustrates example transmitted and received pressure based signals;

(6) FIG. 5 illustrates a method for optimising signal transmission;

(7) FIG. 6 is a diagrammatic illustration of a wellbore arrangement which is subject to a shut-in procedure;

(8) FIG. 7 illustrates a typical pressure build-up curve of a well during shut-in;

(9) FIG. 8 illustrates exemplary wellbore pressure trends associated with some wellbore operations;

(10) FIG. 9 illustrated changing pressure conditions within a wellbore over time; and

(11) FIG. 10 is a diagrammatic illustration of a modified wellbore arrangement which is also subject to wireless communication of signals in accordance with a further embodiment of the present invention.

DETAILED DESCRIPTION OF THE DRAWINGS

(12) Aspects and embodiments of the present invention relate to methods and apparatus for use in communicating wirelessly within a wellbore, such as wellbore 101 shown in FIG. 1 which facilitates production of hydrocarbons such as oil and/or gas from a subterranean reservoir 103 via a set of perforations 102. Somewhere on the surface of the earth the wellbore 101 is terminated in a wellhead 104 which includes appropriate valves and monitoring systems to control and operate the well in accordance with relevant procedures and legislation. Downstream of the wellhead 104 the produced hydrocarbons flow through a flowline 105 to a production facility such as a separator and tank facility (not shown).

(13) Oil or gas fields typically comprise numerous wells, of which most/all produce into the same processing facility. As wells may be of uneven pressure, for example due to penetrating different sections of the reservoir 103 or different reservoir units, regulation is required on surface to ensure that the production from each well arrives at the production facility at equal pressure. In order to provide for this, most flowlines 105 are equipped with a choke valve 107 in order to regulate pressure. Further, most flowlines 105 and/or wellheads 104 are equipped with a pressure sensor 106 to monitor the wellhead pressure.

(14) It is desirable to provide some form of communication within the wellbore, for example between downhole and surface locations. Such communications have been known to be provided by dedicated wires and cables which extend along the entire communication path. However, such wired communication may be subject to failure within the wellbore environment. Forms of wireless communication are therefore of interest in the art.

(15) In the present embodiment a flow control device or system 108 is located at a downhole location and functions to control the flow within the wellbore, for example production flow, to apply pressure based signals 112 through the well fluid to provide wireless communication between the surface and downhole location. As will be described in more detail below, embodiments of the present invention permit control over the pressure based signal transmission by recognising a condition change associated with the wellbore and then controlling the device 108 in accordance with the condition change.

(16) The device 108 can be used to monitor and/or control the well. For downhole data monitoring purposes, the device 108 uses one or more sensors. A sensor suite 111 is provided, which for illustrative purposes may include a pressure sensor, defined by the letter “P”. Other sensors, such as temperature sensors, flow rate sensors, composition sensors and the like may alternatively or additionally be provided. A control module 110 is used to record and process data obtained by the sensor suite 111. The device 108 comprises a choke/flow regulator valve or assembly 109 which is used to intelligently impose pressure variations 112 on the flowing production fluid in order to transmit the recorded data to surface. On surface, the pressure signals 112 are received by a sensor such as a pressure sensor 106 and an analysis system (not shown) is used to extract the downhole information.

(17) FIG. 2 illustrates a wellbore which is largely similar to that shown in FIG. 1, and as such like components share like reference numerals. However, the arrangement shown in FIG. 2 differs in that a flow control device or system 201, which is configured similarly to downhole device 108, is provided at the surface location (effectively replacing or modifying the choke 107 in FIG. 1) and which is used for receiving signals 112 transmitted from the downhole device 108 as well as transmitting pressure signals 205 to said downhole device 108, and or other remote locations.

(18) Reference is now made to FIG. 3 in which there is shown one embodiment of a flow control device or system 108 which may be used to monitor downhole conditions, such as pressure and temperature data, and transmit such data wirelessly to surface by means of imposing pressure pulses onto the flowing fluid in the well 101. The device 108 functions in a similar manner to that described in WO 2006/041308, the disclosure of which is incorporated herein by reference.

(19) The device 108, which includes the choke/flow regulator valve or assembly 109, includes a housing 210 which is secured to the well/production tubing 101 by means of a packer arrangement 212. The packer arrangement 212 restricts the fluid flow 216, which can be both produced as well as injected fluids, along the tubing 101 causing flow through flow ports 218 formed in the wall of the housing 210 and into a flow path 214 which is in fluid communication with surface. A regulator assembly or element 220 is mounted within the housing 210 and is actuated to move by a drive arrangement 222 to vary the flow area through the ports 218 and into the flow path 214 to generate pressure based wireless signals 112 which are then transmitted via the fluid to surface.

(20) The drive arrangement 222, which is also mounted within the housing, comprises an electric motor 230 which operates a pump 232 to displace a fluid to/from a piston chamber 234 in order to apply work on a drive piston 236 secured to the regulator assembly 220 via shaft 238.

(21) A battery module 240 and an control/electronics module 242 are used to energise and control the operation of the device 108.

(22) To transmit one single pressure pulse (negative pulse in this embodiment) the motor 230 is used to operate the pump 232 to pump fluid into a piston chamber 234 to cause the drive piston 236 and regulator assembly 220 (via shaft 238) to shift to the right in FIG. 3. This has the effect of reducing the flow area through the flow ports 218 thus choking the flow and generating a pressure drawdown downstream of the device 108. After having applied the required pressure amplitude (pressure drawdown) for a sufficient period of time to permit detection at surface, the motor 230 is reversed to offload fluids from the piston chamber 234. A spring 246 causes the regulator assembly 220 to retract and the production returns to “normal”, i.e. a fully open position.

(23) FIG. 4, which is a plot of pressure vs time, illustrates a characteristic signal transmission sequence which may be achieved by appropriate use of the flow control device 108, in accordance with the present invention. Selectively restricting the flow ports 218 may establish a signal pattern 301 which comprises a set of generated pressure fluctuations, or pulses 301a-301e which are composed to represent appropriate data to be transmitted. The pulses 301a-301e are provided by variations from a baseline pressure P.sub.wbf, which is the pressure within the wellbore when flowing without restriction imposed by the device 108. Each pulse 301a-301e comprises particular signal parameters including a duration or pulse width d and an amplitude A. The time lapse between sequential pulses 301a-301e may be defined as a pulse separation, or frequency. This pulse separation may be of importance in embedding appropriate data. For example, the pulse separation may be selected to be representative of a digitised data format. It is vital that the signal pattern 301 is detectable at surface, and the present invention achieves this by selection of appropriate signal parameters, including pulse width d and/or amplitude A, which will be discussed in more detail below.

(24) When appropriate signal parameters are selected a received signal pattern 302 will be detected at surface, with an appropriate time lag 303. The received signal will comprise individual pulses 302a-302e which can be appropriately processed to extract the embedded data.

(25) As noted above, the present invention provides a signal which will be capable of being detected at surface, or any other intended point of reception. In accordance with one embodiment of the present invention correct parameters for amplitude and duration may be achieved by means of a software simulation up-front any installation in the well.

(26) Further, the device or system 108 (FIG. 1) may be programmed with a parameter matrix, and change amplitude A and duration d according to read downhole parameters, read by systems sensors such as pressure sensors, flow sensors and phase composition and/or density sensors.

(27) FIG. 5, which is also a plot of pressure vs time, illustrates another method according to an embodiment of the present invention for providing an optimised signal. The method comprises sending a trial signal 310 which may include a number of trial pulses 312, 314, 316, 318 which each comprise different signal parameters, specifically pulse width d and amplitude A. Although single pulses are provided, a plurality of pulses may be transmitted with one set of signal parameters, then a plurality of pulses with a different set of signal parameters, and so on. Further, each illustrated individual pulse may represent an entire test signal, such that in the embodiment shown in FIG. 5 four test signals 312-381 are presented. A receiver at a target location, such as surface level, is operated to detect a received signal 320 which corresponds to the transmitted test signal. Upon analysing the received signals 320, the optimal amplitude A and/or duration d may be determined. This can then be communicated to the downhole device 108 (FIG. 1) by means of surface to downhole wireless communication, or by means of alternative actions such as shutting in the well for a predetermined amount of time.

(28) In addition to this, the present invention permits other intelligence to be accounted for. For example, excessive choking of the well is generally to be avoided as this may otherwise entail unwanted disturbances to the production flow. Further, as the well gets older, the pressure conditions and fluid regime may change, due to a decline in reservoir pressure. Embodiments of the present invention permit optimal signalling (for example in order to achieve the correct amplitude A and/or pulse width d) by applying intelligence to the transmission system. Specifically, embodiments of the present invention permit condition changes within the wellbore 101 (FIG. 1) to be recognised and the flow control device 108 controlled accordingly to adapt the signals to the changing conditions. This is described in more detail below.

(29) FIG. 6 illustrates the same well 101 as presented in FIG. 1, with one exception: in FIG. 6 the well 101 is not producing. That is, the well 101 is shut-in such that there is no flow. By closing valves such as a downhole safety valve 401 and wellhead valve(s) 402 the production from the well 101 can be stopped. This may be required in cases of emergency, but shutting wells in is also very common for other reasons such as:

(30) testing—performing so-called pressure build-up (PBU) tests is common in order to acquire data that can be interpreted to yield important information about the well 101 and/or the reservoir 103;

(31) maintenance—wells are commonly shut-in to permit in-well maintenance or other maintenance, for instance on the production facility;

(32) production stop due to the introduction of or excess of unwanted fluids such as water.

(33) The device or system 108 is designed to transmit signals through the producing fluid, hence signalling is not possible when the well 101 is shut in. As will be described in more detail in the following sections, embodiments of the present invention permit a recognition of changing conditions within the well, which may be indicative of a specific event, such as shut-in, with changes to the operational modus of the device 108 being made accordingly. For the shut-in well scenario, such change does in one embodiment imply a stop in the signalling activity to avoid wasting system power, as signalling is not possible due to the halt in fluid movement.

(34) FIG. 7 illustrates a typical pressure build-up (PBU) curve 410, i.e. the downhole pressure trend when going from a production modus to a shut-in modus of the well. Time is used as the reference along the x-axis and P.sub.wb, a short-name for wellbore pressure, is plotted along the y-axis. When the well is flowing, P.sub.wb equals the value P.sub.wbf, i.e. the flowing wellbore pressure. At time t.sub.0, the well is shut in. Gradually, the pressure P.sub.wb rises to a maximum wellbore pressure P.sub.wbsi at time t.sub.1. In many cases, it is of great interest to know the value of the maximum wellbore pressure P.sub.wbsi.

(35) In order to store and subsequently report the value P.sub.wbsi, the downhole device or system 108 recognises the fact that the well is being shut in. One method to achieve this is to transmit a wireless message from the surface beforehand or at the time of shutting in the well, informing the downhole device(s) that this is the case. However in some cases that may not be possible due to a lack of signalling systems on surface or other reasons.

(36) FIG. 8 shows aspects related to one embodiment of the present invention, further to a scenario where the downhole device or system 108 is configured to perform a self-assessment and correct behaviour subsequent to recognised wellbore changes. FIG. 8 illustrates pressure changes which may be typical within a wellbore. The given trend starts in a time period 412 where the well of this example is producing. In conjunction with the installation of an autonomous downhole tool, such as the device 108 described herein, the well is shut-in for the job of installing the system. The first pressure build-up profile 414 shows a typical pressure path when the well is shut-in for a short period of time (related to rigging up and installing the downhole equipment). The first pressure build-up profile 414 is normally followed by a short period of producing the well 416 to verify that all downhole components are working satisfactorily. Upon verification, the well is shut-in a second time in order to rig down relevant intervention equipment such as pressure control equipment associated with a wireline operation. This stage is associated with pressure trend 418. Thereafter, the well is put on normal production 420, which may last for a prolonged period of time.

(37) After some time of production, the well is shut-in in order to perform a shut-in test. When shutting in, a profile such a pressure trend 422 is experienced. This typically has a longer duration than the shut-in periods that are associated with the installation work 414, 418, and as a consequence, the pressure increase is higher as pressure effects from more remote reservoir segments will be experienced in the wellbore, for example.

(38) The present invention operates, or permits operation of the downhole device or system 108 in accordance with a number of desires, including:

(39) the system should not spend energy on attempting to send data during a shut-in period;

(40) the system should preferably record representative shut-in data, such as the pressure value at the time of shutting in the well;

(41) the system should transmit the recorded data to surface when production is started again;

(42) the system should preferably not transmit shut-in data recorded during short periods of shutting in the well such as the periods described by the two first pressure trends 414, 418—these periods may be too short to provide for useful representations of shut-in data.

(43) In one embodiment of the invention, the tool is programmed to recognise a true shut-in period 422 by monitoring pressure differences versus time. A true shut-in period 422 is defined by a certain pressure increase ΔP.sub.car1 taking place. As this may also be the case in other, smaller shut-in periods 414, 418 where data acquisition may not be of interest, a true shut-in period 422 may also be defined by a characteristic time factor t.sub.car1, i.e., if a pressure increase further to ΔP.sub.car1 is experienced, and sustained for a time period longer than a time equal to t.sub.car1, then a real shut-in period 422 is recognised as taking place. Upon recognising this, the tool starts to sample pressure data at regular time intervals, and in a preferred embodiment, the device 108 transmits the last recorded build-up pressure when the production is started again, after a certain time of stabilisation.

(44) Typically, a representative pressure data such as the pressure in place at t=t.sub.bu is recorded and subsequently reported to the surface, after the production is initiated again. Normally, the further into the pressure build-up period 422, the more representative the data will be. Therefore, the device 108 will record shut-in data continuously, and transmit the last recorded representative value after the production has started again.

(45) In the same manner, the device can be programmed to identify the time of starting the production again after a time of shutting the well in. As shown in FIG. 8, this can be performed by recognising a pressure drop ΔP.sub.car2 and this being sustained or exceeded for a period of t=t.sub.car2.

(46) At the initiation of the production after shut-in period 422, some pressure disturbance may be experienced. To avoid recording and transmitting pressure data from that period (such data may be faulty and not represent the shut-in period), reverse time lags may be added to the procedure. As an example, the device 108 may be programmed to transmit the last data recorded up to a minimum of 2 hours prior to a recognised production start-up.

(47) In one embodiment, the device 108 is capable of making a mathematical representation of the pressure trend 422, and transmit a digital representation of the mathematical representation to the surface. This may compensate for band-width and energy usage problems related to transmitting a large amount of datapoints representing the same curve. The mathematical representation could be created by transmitting the constants of an mathematical equation, i.e., numerical analysis of the data, or by comparing the recorded curve form with template curves in a library, transmitting the characteristic number for the best match curve, together with required absolute values.

(48) FIG. 9 illustrates another aspect related to the advantages of the present invention in being capable of recognising condition changes within a wellbore and adapting accordingly. A typical pressure trend 430 is illustrated which represents a well falling off plateau production. Plateau is defined as a production rate when the well provides equal to or more fluids than the production facility can accept. When wells have drained the reservoir segment for a longer period of time, it is quite common that the downhole pressure drops. This pressure drop may be associated with changes in the fluid flow rate, and to the fluid composition, possibly due to free gas being released from the oil, or the commencement of water production from aquifers or water injection wells. The present invention permits recognition of such changing conditions and controls the device 108 to correct its behaviour further accordingly. For example, if the device 108 reads a wellbore pressure equal to or lower than P.sub.car3, it may change settings related to pulse duration d and amplitude A of the transmitted pressure pulse signals (see, for example, FIG. 4) as well as settings related to the recognition of a pressure build-up and associated production start event. A similar new change may take place when the wellbore pressure goes below P.sub.car4.

(49) FIG. 10 illustrates another embodiment of the present invention. Specifically, FIG. 10 illustrates a wellbore 101 almost identical to that shown in FIG. 6, and as such like features are represented by like reference numerals, and only the differences will be highlighted. The downhole device 108 is equipped with (an) additional sensor(s) 440. This could be sensors for monitoring flow velocity, water cut, fluid density and other relevant downhole parameters. Following the same argumentation as for the previous figures; depending in recorded changes in the sensor(s) 440, the downhole device 108 may change its operating characteristics, this being characteristics such as;

(50) amplitude and pulse width or duration of wireless signal pulses;

(51) signal transmission frequency;

(52) detection levels for recognising shut-in and production start events;

(53) transmission of more/additional types of information, for example information on water-cut may identify when water is confirmed present;

(54) changes in parameters for energy generation modules of the device 108.

(55) in one or more embodiments of the invention, the additional sensor(s) 440 may fulfil more than one role in the system 108, such as;

(56) propeller system used as status sensor for determining a shut-in period and/or flow sensor for sensing flow velocity and/or energy generator;

(57) vibration based system (vortex shedding device or lift reversal device) used as status sensor for determining a shut-in period and/or flow sensor for sensing flow velocity and/or energy generator.

(58) It should be understood that the embodiments described herein are merely exemplary and that various modifications may be made thereto without departing from the scope of protection. For example, the methods and devices described above may be utilised within any flowline, and are not restricted for wellbore use.