Abstract:
A system for separating water from crude oil includes a bulk-storage tank for storing unrefined crude oil, a first pipe for delivering water separated from crude oil in the bulk-storage tank to a containment system, a second pipe for delivering crude oil to a shipping system, a first valve for controlling flow in the first pipe, a second valve for controlling flow in the second pipe, and a control system for controlling operation of the first and second valves. The control system has a control device for controlling the first and second valves, an acoustic sensor array mounted on the first pipe for sensing a sound pressure level during flow of water through the first pipe, means for comparing the sensed sound pressure level with a predetermined sound pressure threshold level characterizing flow of oil-water mixture through the pipe, and a control device for closing the first valve and opening the second valve when the measured sound pressure level reaches the sound pressure threshold level.

Description:
RELATED APPLICATIONS 
       [0001]    This application claims the benefit of priority to U.S. Provisional Patent Application No. 61/541,713 filed Sep. 30, 2011, the disclosure of which is incorporated herein by reference in its entirety. 
     
    
     FIELD OF THE INVENTION 
       [0002]    The present invention relates generally to dewatering a bulk-storage tank and, in particular, to a method and apparatus for detecting water-to-crude oil transition in a pipe. 
       BACKGROUND 
       [0003]    Unrefined crude oil stored in a bulk-storage tank has a percentage of water entrained within the oil. Such crude oil is typically pumped into a bulk-storage tank prior to shipment. The capacity of bulk-storage tanks vary, but may be one-hundred (100) million barrels (i.e., 15.9 giga-litres). Over a period of twenty-four (24) to forty-eight (48) hours, the water and oil stored in a tank separate naturally, with the water collecting at the bottom of the tank beneath the oil. The separated water and the crude oil within the tank are very distinct except for a “black water” or “rag” interface layer. 
         [0004]    The black water interface layer is an emulsion of mixed oil and water. 
         [0005]    Prior to transferring the crude oil to a bulk carrier for shipment, the crude oil stored in a bulk-storage tank requires dewatering (i.e., removing the water from the tank). Conventionally, the oil within a bulk-storage tank is dewatered by manually opening an outlet valve at the base of the bulk-storage tank and allowing any contained liquid to run through a pipe to a containment area. The liquid running through the pipe is initially water. An operator periodically checks the liquid, using a siphon point, to see if the liquid is water or oil. The siphon point may be in the form of a domestic tap attached to the pipe. When the operator determines that the liquid has transitioned from water to oil, which occurs after a random time, the operator closes the outlet valve on the bulk-storage tank to stop the flow of liquid. A conventional definition of “transition from water to crude oil” is when a ratio of water to crude oil in the liquid reaches 20:80 (i.e., 20% water: 80% crude oil). The remaining liquid in the tank, which is primarily crude oil, may then be transferred by a separate pipe to a transport system such as a shipping delivery system. 
         [0006]    If the operator is unable to stop the flow of liquid from the tank at the point of the liquid transitioning to oil, then oil is sent to the containment area where the oil is trapped in a mixture of oil and waste-water. The oil may be recovered from the waste-water using conventional water processing methods. However, recovering the oil from the containment area is an expensive exercise. 
         [0007]    The dewatering of a bulk-storage tank as described above often takes place in open air in extreme environmental conditions such as heat, wind, sand storms, and rain. The reliability and accuracy of such a dewatering method is subject to the diligence of the operators. In particular, the decision point for closure of the outlet valve at the transition of the liquid from water to oil is a subjective judgement and open to vary from one operator to another. 
         [0008]    In order to remove the dependence on a human operator for detecting the transition of water to crude oil in a pipe, density sensors have been used to periodically determine density of the liquid within the pipe. One such density sensor is an insertion liquid density transducer (ILDT). An ILDT comprises a tuning fork which is immersed within a pipe in the liquid being measured. The tuning fork is excited into oscillation by a piezoelectric device (not shown) internally secured at the root of one tine. The frequency of the vibration of the tuning fork is detected by a second piezoelectric device secured in the root of the other tine of the tuning fork. The tuning fork is maintained at its natural resonant frequency, as modified by the surrounding liquid, by an amplifier circuit which may be located in an electronic housing. This frequency of vibration is a function of the overall mass of the tine element and the density of the liquid in contact with the tine element. As the density of the liquid changes, the overall vibrating mass changes together with the resonant frequency. By measuring the resonant frequency the density of the liquid can be determined. Another example of a density sensor may be in the form of a tube densitometer. A tube densitometer works in a similar manner to the ILDT discussed above. 
         [0009]    The density measurements determined using such density sensors may be used to determine if the transition between water and oil has occurred. In this connection, Tables 3 and 4 of Appendix C show the density of water and crude oil. However, density sensors such as those discussed above are not suitable for use with any liquid of unpredictable or erosive nature which can damage the tines causing erratic results. Further, such density sensors require complicated fitting within a pipe in order to perform the sampling. Still further such density sensors are prone to fouling when sampling particularly viscous liquids such as crude oil. 
         [0010]    Thus a need clearly exists for an improved method of detecting water to oil transition of liquid flowing in a pipe. 
       OBJECTS AND SUMMARY OF THE INVENTION 
       [0011]    It is an object of the present invention to substantially overcome, or at least ameliorate, one or more disadvantages of prior art arrangements. 
         [0012]    The present application discloses arrangements which seek to address the prior art problems by measuring one or more properties of liquid flowing within a pipe in order to detect water to oil transition. 
         [0013]    One object of the present invention is to provide a method of detecting water to oil transition of liquid flowing in a pipe, said method comprising the steps of: 
         [0014]    measuring sound pressure level produced by the liquid flowing at a predetermined point within the pipe; 
         [0015]    comparing the measured sound pressure level to a predetermined threshold value stored in a computer readable memory; and 
         [0016]    detecting if the liquid flowing in the pipe at the predetermined point has transitioned from water to crude oil based on a result of the comparison. 
         [0017]    Another object further to the above comprises the step of determining whether the liquid is flowing in a laminar or turbulent manner depending on the comparison. 
         [0018]    Another object further to the above comprises the step of determining electrical conductivity of the liquid. 
         [0019]    Another object further to the above comprises the step of measuring vibrations in the pipe caused by turbulence of fluid flow in the pipe. 
         [0020]    Another object further the above comprises the steps of opening a valve to allow outflow of water from a storage tank, and later closing said valve in order to stop the liquid flowing out of the tank if the transition from water to oil has occurred at the predetermined point. 
         [0021]    Another object is to provide an apparatus for detecting water to oil transition of liquid flowing in a pipe, said apparatus comprising: 
         [0022]    measuring means for measuring the sound pressure level produced by the liquid flowing at a predetermined point within the pipe; and 
         [0023]    a processor for comparing the measured sound pressure level to a predetermined threshold value stored in a computer readable memory, and for detecting if the liquid flowing in the pipe at the predetermined point has transitioned from water to crude oil based on a result of the comparison. 
         [0024]    Another object is to provide a computer readable storage medium, having a program recorded thereon, where the program is configured to make a computer execute a procedure to detect water to oil transition of liquid flowing in a pipe, said apparatus comprising: 
         [0025]    code for measuring sound pressure level produced by the liquid flowing at a predetermined point within the pipe; 
         [0026]    code for comparing the measured sound pressure level to a predetermined threshold value stored in a computer readable memory; and 
         [0027]    code for detecting if the liquid flowing in the pipe at the predetermined point has transitioned from water to crude oil based on a result of the comparison. 
         [0028]    Another object is to provide a method of detecting water to oil transition of liquid flowing in a pipe, said method comprising the steps of: 
         [0029]    measuring electrical conductivity of the liquid flowing at a predetermined point within the pipe; 
         [0030]    comparing the measured conductivity to a predetermined threshold value stored in a computer readable memory; and 
         [0031]    detecting if the liquid flowing in the pipe at the predetermined point has transitioned from water to crude oil based on a result of the comparison. 
         [0032]    Another object further to the above method comprises the step of determining whether the liquid is flowing in a laminar or turbulent manner depending on the comparison. 
         [0033]    Another object further to the above method comprises the step of determining sound pressure level of the liquid. 
         [0034]    Another object further to the above method comprises steps of opening a valve to allow outflow of water from a storage tank, and later closing said valve in order to stop the liquid flowing out of the tank if the transition from water to oil has occurred at the predetermined point. 
         [0035]    Another object is to provide an apparatus for detecting water to oil transition of liquid flowing in a pipe, said apparatus comprising: 
         [0036]    measuring means for measuring electrical conductivity of the liquid flowing at a predetermined point within the pipe; and 
         [0037]    a processor for comparing the measured conductivity to a predetermined threshold value stored in a computer readable memory, and for detecting if the liquid flowing in the pipe at the predetermined point has transitioned from water to crude oil based on a result of the comparison. 
         [0038]    Another object is to provide a computer readable storage medium, having a program recorded thereon, where the program is configured to make a computer execute a procedure to detect water to oil transition of liquid flowing in a pipe, said apparatus comprising: 
         [0039]    code for measuring conductivity of the liquid flowing at a predetermined point within the pipe; 
         [0040]    code for comparing the measured conductivity to a predetermined threshold value stored in a computer readable memory; and 
         [0041]    code for detecting if the liquid flowing in the pipe at the predetermined point has transitioned from water to crude oil based on a result of the comparison. 
         [0042]    Another object is to provide a method of detecting water to oil transition of liquid flowing in a pipe, said method comprising the steps of: 
         [0043]    measuring vibration at a predetermined point of the pipe; 
         [0044]    comparing the measured vibration to a predetermined threshold value stored in a computer readable memory; and 
         [0045]    detecting if the liquid flowing in the pipe at the predetermined point has transitioned from water to crude oil based on a result of the comparison. 
         [0046]    Other aspects of the invention are disclosed in the following description. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0047]    Some aspects of the prior art and one or more embodiments of the present invention will now be described with reference to the drawings and appendices, in which: 
           [0048]      FIG. 1  shows a system for dewatering crude oil stored in a bulk-storage tank; 
           [0049]      FIG. 2A  is a schematic block diagram of an electronic device of the system of  FIG. 1 ; 
           [0050]      FIG. 2B  is a schematic block diagram of a computer system used in the system of  FIG. 1 ; 
           [0051]      FIG. 3  is a flow diagram showing a method of dewatering the bulk-storage tank of  FIG. 1 ; 
           [0052]      FIG. 4  is a flow diagram showing a method of detecting water to crude oil transition in a pipe of the system of  FIG. 1 ; 
           [0053]      FIG. 5  is a flow diagram showing another method of detecting water to crude oil transition in a pipe of the system of  FIG. 1 ; 
           [0054]      FIG. 6  shows a fast Fourier transform (FFT) waterfall trace simulating the flow of water through the pipe of the system of  FIG. 1 ; 
           [0055]      FIG. 7  shows a fast Fourier transform (FFT) waterfall trace simulating the flow of crude oil through the pipe of the system of  FIG. 1 ; 
           [0056]      FIG. 8  shows an alternative system for dewatering the bulk-storage tank of  FIG. 1 ; 
           [0057]      FIG. 9  is a graph showing sound pressure level (SPL) versus time, in accordance with a dewatering example; 
           [0058]      FIG. 10  is a graph showing sound pressure level (SPL) versus time, in accordance with a dewatering example; and 
           [0059]      FIG. 11  is a graph showing conductivity versus time, in accordance with a dewatering example. 
       
    
    
       [0060]    Where reference is made in any one or more of the accompanying drawings to steps and/or features, which have the same reference numerals, those steps and/or features have for the purposes of this description the same function(s) or operation(s), unless the contrary intention appears. 
       DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
       [0061]    It is to be noted that the discussions contained in the “Background” section and that above relating to prior art arrangements relate to discussions of documents or devices which form public knowledge through their respective publication and/or use. Such should not be interpreted as a representation by the present inventor(s) or patent applicant that such documents or devices in any way form part of the common general knowledge in the art. References will be made later herein to Appendix A, B and C where: 
         [0062]    Appendix A is a table showing kinematic viscosity of water and crude oil, 
         [0063]    Appendix B is a table showing conductivity information for water and crude oil, and 
         [0064]    Appendix C is a table showing density information for water and crude oil. 
         [0065]      FIG. 1  shows a system  100  for dewatering a bulk-storage tank  101 . The system  100  comprises two motorised valves  102  and  103 . The valve  102  controls flow of liquid through a pipe  104  connecting the base of the tank  101  to a containment system  105 . The valve  103  controls flow of liquid through another pipe  106  connecting the base of the tank  101  to a shipping (or transport) system  107 . 
         [0066]    A measuring means, in the form of an acoustic sensor array  109  is fixed at a predetermined point to the outside of the pipe  104 . In one implementation, the acoustic sensor array  109  comprises two sensors (not shown) that output a voltage (e.g., 0-10 Volts) according to average sound pressure level (SPL) detected by the sensors of the acoustic sensor array  109 . 
         [0067]    Another measuring means, in the form of a conductivity sensor  108 , is fixed at a further predetermined point to the outside of the pipe  104 . In one implementation, the conductivity sensor  108  is an inductive, non-contact type sensor that outputs a current (0-20 mA) according to the average conductivity level detected. 
         [0068]    Although the system  100  is described as comprising both the acoustic sensor array  109  and the conductivity sensor  108 , in other implementations the system  100  may comprise one of either the acoustic sensor array  109  or the conductivity sensor  108 . 
         [0069]    The system  100  is controlled by an electronic device  151  which is electrically connected to the valves  102 ,  103 . The device  151  is also connected to the conductivity sensor  108  and the acoustic sensor array  109  as seen in  FIGS. 1 and 2A . 
         [0070]    In one embodiment, the device  151  may be a programmable logic controller (PLC). Such a PLC may be electrically connected to the conductivity sensor  108  and the acoustic sensor array  109 , via corresponding controllers for processing signals from the corresponding sensor  108  and array  109 . 
         [0071]    The system  100  uses the acoustic sensor array  109  to measure liquid turbulence inside the pipe  104  in order to detect water to crude oil transition. The system  100  uses the conductivity sensor  108  to measure the conductivity of the liquid inside the pipe  104  in order to detect water to crude oil transition. Accordingly, the conductivity sensor  108  and/or the acoustic sensor array  109  provide a non-invasive method of detecting the transition of water to crude oil in the pipe  104 . 
         [0072]    As seen in  FIG. 1 , the device  151  is also connected to a computer system  200  (or computer), via a local computer network  222  (known as a Local Area Network (LAN)). The computer system is seen in detail in  FIG. 2B . The computer system  200  allows an operator to activate or de-activate dewatering remotely using one or more controls displayed on a graphical user interface (GUI) represented on a display  214  of the computer system  200 , as will be described below. In this instance, the computer system  200  communicates directly with the device  151  which controls the valves  102  and  103 . 
         [0073]    The system  100  increases the consistency of detecting the transition of water to crude oil in the pipe  104  and removes the dependence of such detection on a human operator. The system  100  reduces demand on the containment system  105  to deal with oil overspill due to late termination of dewatering. The system  100  allows dewatering to be performed remotely from the bulk-storage tank  101 , using the computer system  200 , by providing an alert when a specified ratio of water to crude oil (e.g., 20:80) has been reached in the pipe  104 . 
         [0074]    As seen in  FIG. 2A , the device  151  comprises an embedded controller  152 . Accordingly, the device  151  may be referred to as an “embedded device.” In the present example, the controller  152  comprises a processing unit (or processor)  155  which is bi-directionally coupled to an internal storage module  159 . The storage module  159  may be formed from non-volatile semiconductor read only memory (ROM) and semiconductor random access memory (RAM). The RAM may be volatile, non-volatile or a combination of volatile and non-volatile memory. 
         [0075]    The embedded device  151  may comprise an indication means  165  in form of a liquid crystal display (LCD) panel and/or light emitting diodes (LEDs) or the like. The embedded device  151  also comprises user input devices  153  which are typically formed by a keypad or like controls. 
         [0076]    As seen in  FIG. 2A , the embedded device  151  also comprises a portable memory interface  156  which is coupled to the processor  155  via a connection  119 . The portable memory interface  156  allows a complementary portable memory device  175  to be coupled to the embedded device  151 . The portable memory device  175  may act as a source or destination of data or to supplement the internal storage module  159 . Examples of such interfaces which permit coupling with portable memory devices such as Universal Serial Bus (USB) RAM, Secure Digital (SD) cards, Personal Computer Memory Card International Association (PCMIA) cards, optical disks and magnetic disks. 
         [0077]    The embedded device  151  also comprises a communications interface  158  to permit coupling of the embedded device  151  to the local computer network  222  via a connection  223 . The connection  223  may be wired or wireless, such as radio frequency or optical. An example of a wired connection includes USB. Further, an example of wireless connection includes Bluetooth™ type local interconnection, WiFi (e.g., the IEEE802 family, Infrared Data Association (IrDa)) and the like. 
         [0078]    The embedded device  151  also includes an input/output (I/O) interface  160  for communicating with the conductivity sensor  108  and the acoustic sensor array  109 , as seen in  FIG. 2A . The embedded device  151  also communicates with the valves  102  and  103  via the I/O interface  160 . 
         [0079]    The methods described below may be implemented using the embedded controller  152  wherein the processes of  FIGS. 3 to 10 , to be described, may be implemented as one or more software application programs  133  executable within the embedded controller  152 . The embedded device  151  effects an advantageous apparatus for implementing the described methods. In particular, the steps of the described methods are effected by instructions in the software  133  that are carried out within the controller  152 . The software instructions may be formed as one or more code modules, each for performing one or more particular tasks. 
         [0080]    The software  133  is generally loaded into the controller  152  from a computer readable medium, and is then typically stored in the internal storage module  159 , as illustrated in  FIG. 2A , after which the software  133  can be executed by the processor  155 . As described herein, the application program  133  is typically pre-installed and stored in the ROM by a manufacturer prior to distribution of the embedded device  151 . However, in some instances, the software  133  may be supplied to the user encoded on one or more CD-ROM (not shown) and read via the portable memory interface  156  prior to storage in the internal storage module  159  or in the portable memory  175 . In another alternative, the software  133  may be read by the processor  155  from the network  222  or loaded into the controller  152  or the portable storage medium  175  from other computer readable media. Computer readable storage media refers to any storage medium that participates in providing instructions and/or data to the controller  152  for execution and/or processing. Examples of such storage media include floppy disks, magnetic tape, CD-ROM, a hard disk drive, a ROM or integrated circuit, USB memory, a magneto-optical disk, flash memory, or a computer readable card such as a PCMCIA card and the like, whether or not such devices are internal or external of the device  151 . Examples of computer readable transmission media that may also participate in the provision of software, application programs, instructions and/or data to the device  151  include radio or infra-red transmission channels as well as a network connection to another computer or networked device, and the Internet or Intranets including e-mail transmissions and information recorded on Websites and the like. A computer readable medium having such software or computer program recorded on it is a computer program product. 
         [0081]    As seen in  FIG. 2B , the computer system  200  is formed by a computer module  201 , input devices such as a keyboard  202  and a mouse pointer device  203 , and output devices including a printer  215 , a display device  214  and loudspeakers  217 . An external Modulator-Demodulator (Modem) transceiver device  216  may be used by the computer module  201  for communicating to and from a computer network  220  via a connection  221 . The network  220  may be a wide-area network (WAN), such as the Internet or a private WAN. Where the connection  221  is a telephone line, the modem  216  may be a traditional “dial-up” modem. Alternatively, where the connection  221  is a high capacity (eg: cable) connection, the modem  216  may be a broadband modem. A wireless modem may also be used for wireless connection to the network  220 . 
         [0082]    The computer module  201  typically includes at least one processor unit  205 , and a memory unit  206  for example formed from semiconductor random access memory (RAM) and read only memory (ROM). The module  201  also includes an number of input/output (I/O) interfaces including an audio-video interface  207  that couples to the video display  214  and loudspeakers  217 , an I/O interface  213  for the keyboard  202  and mouse  203  and optionally a joystick (not illustrated), and an interface  208  for the external modem  216  and printer  215 . In some implementations, the modem  216  may be incorporated within the computer module  201 , for example within the interface  208 . The computer module  201  also has a local network interface  211  which, via a connection  225 , permits coupling of the computer system  200  to the local computer network  222 . The interface  211  may be formed by an Ethernet™ circuit card, a wireless Bluetooth™ or an IEEE 802.11 wireless arrangement. 
         [0083]    The interfaces  208  and  213  may afford both serial and parallel connectivity, the former typically being implemented according to the Universal Serial Bus (USB) standards and having corresponding USB connectors (not illustrated). Storage devices  209  are provided and typically include a hard disk drive (HDD)  210 . Other devices such as a floppy disk drive and a magnetic tape drive (not illustrated) may also be used. An optical disk drive  212  is typically provided to act as a non-volatile source of data. Portable memory devices, such optical disks (eg: CD-ROM, DVD), USB-RAM, and floppy disks for example may then be used as appropriate sources of data to the system  200 . The memory  206  and the HDD  210  may be referred to as a “computer readable memory”. 
         [0084]    The components  205  to  213  of the computer module  201  typically communicate via an interconnected bus  204  and in a manner which results in a conventional mode of operation of the computer system  200  known to those in the relevant art. Examples of computers on which the described arrangements can be practised include IBM-PC&#39;s and compatibles, Sun Sparcstations, Apple Mac™ or alike computer systems evolved therefrom. 
         [0085]    One or more steps of the methods described below may be implemented within the computer system  200 , wherein one or more steps of the processes of  FIGS. 3 to 6  may be implemented as software, such as one or more software application programs  233  executable within the computer system  200 . In particular, one or more of the steps of the described methods may be effected by instructions in the software  233  that are carried out within the computer system  200 . The instructions may be formed as one or more code modules, each for performing one or more particular tasks. The software  233  executable within the computer system  200  may implement and manage the graphical user interface (GUI) displayed on the display  214 . As described above, one or more controls displayed on the GUI allow an operator to activate or de-activate dewatering remotely. 
         [0086]    Again, the software  233  resident on the computer system  200  and implementing GUI may be stored in a computer readable medium, including the storage devices described above, for example. Such software may be loaded into the computer system  200  from the computer readable medium, and then be executed by the computer system  200 . The use of a computer program product in the computer system  200  preferably effects an advantageous apparatus for implementing one or more steps of the described methods. 
         [0087]    Through manipulation of the keyboard  202  and the mouse  203 , the operator of the system  100  and the software application  233  may manipulate the graphical user interface (GUI) to provide controlling commands and/or input to the software application  133  resident on the embedded device  151 , see  FIG. 2A . The controlling commands and/or input may allow the operator to activate and de-activate dewatering remotely using the controls displayed on the GUI represented on the display  214 ,  FIG. 2B . The GUI preferably also provides an indication of the status of the system  100  (e.g., “valve open” or “valve closed”) to indicate whether the valves  102  and  103  are open or closed,  FIG. 1 . The GUI may also display diagnostic information indicating problems with the system  100 . 
         [0088]    A method  300  of dewatering the bulk-storage tank  101  will now be described in detail below with reference to  FIG. 3 . The method  300  may be implemented as one or more code modules of the software  133  resident on the internal storage  159  of the embedded device  151  and being controlled in its execution by the processor  155 . 
         [0089]    The method  300  begins at step  301  where the processor  155  performs the step of transmitting a first signal to the motorised valve  102  to open the valve  102  allowing liquid to flow out of the tank  101  through the pipe  104 . Liquid flows from the tank  101  through the open valve  102  and the pipe  104  to the containment system  105 . The first signal may be generated by the embedded device  151  in response to a signal received from computer system  200 . As described above, the signal received from the computer system  200  may be generated based on operator manipulation of the keyboard  202  and the mouse  203  to operate one or more controls of the GUI displayed on the display device  214 . In response to such manipulation, the software  233  may generate and send the first signal to the device  151  via the network  222 . 
         [0090]    At the next step  303 , the processor  155  performs the step of detecting if the liquid flowing in the pipe  104  at a predetermined point in the pipe has transitioned from water to crude oil. As described in detail below, the processor  155  may detect whether the liquid flowing in the pipe  104  has transitioned from water to crude oil by measuring at least one property of the liquid flowing at the predetermined point within the pipe  104 . The measured property may be compared to a predetermined threshold value. Based on a result of the comparison, the processor  155  may detect if the liquid flowing in the pipe has transitioned from water to crude oil. 
         [0091]    In one example, the processor  155  may determine if the flow of liquid within the pipe  104  is “laminar” or “turbulent” at the predetermined point, at any particular point in time, based on a measurement of sound pressure level (SPL) produced by the liquid flowing within the pipe  104 . Accordingly, the property measured at step  303  is sound pressure level (SPL) produced by the liquid flowing within the pipe  104 . The determination of sound pressure level may be made using the acoustic sensor array  109  positioned at the predetermined point of the pipe  104 . A method  400  of detecting water to crude oil transition in the pipe  104  using the acoustic sensor array  109 , as may be executed at step  303 , will be described in detail below with reference to  FIG. 4 . 
         [0092]    Alternatively, the processor  155  may detect whether the flow of liquid in the pipe  104  has transitioned from water to crude oil by determining the conductivity of the liquid using the conductivity sensor  108 . Accordingly, the property measured at step  303  is conductivity of the liquid. A method  500  of detecting water to crude oil transition in the pipe  104  using the conductivity sensor  108 , as may be executed at step  303 , will be described in detail below with reference to  FIG. 5 . 
         [0093]    In still another alternative, the processor  155  may detect whether the flow of liquid in the pipe  104  has transitioned from water to crude oil by monitoring vibration within the pipe  104  using an accelerometer, as will be described below. Accordingly, in this instance, the property measured at step  303  is vibration caused by the liquid flowing in the pipe  104 . 
         [0094]    The method  300  continues at the next step  304 , where if the flow of liquid in the pipe  104  at the predetermined point has transitioned from water to crude oil (i.e., the transition has occurred), then the method  300  proceeds to step  305 . Otherwise, the method  300  returns to step  303 . At step  305 , the processor  155  performs the step of transmitting a signal to the motorised valve  102 , via the I/O interface  160 , to close the valve  102  in order to stop the liquid flowing out of the tank  101  in the pipe  104 . The closing of the valve  102  may be indicated to the operator via the GUI displayed on the display device  214 , in response to a further signal received by the processor  205  from the processor  155 . 
         [0095]    At low flow rates, liquid tends to be laminar. As the flow rate of liquid speeds up, a transition occurs and the liquid crinkles up into complicated, random turbulent flow. Turbulent flowing liquid, while proceeding in a particular direction like laminar flowing liquid, has the added complexity of random velocity fluctuations. Flow patterns of turbulent flowing liquid are chaotic. 
         [0096]    As an example of laminar flow, consider water flowing from a tap. At low flow rates, a glassy, orderly flow of water may be observed flowing from the tap. If there is no wind or other disturbance, nothing will change and the orderly flow of water will continue. Laminar flowing water is deterministic. Information about future behaviour of laminar flowing water is completely determined by specification of flow at an earlier time. For faster or larger scale water flowing from the tap (e.g., with the tap fully open), the flow pattern of water continuously changes. Although, average motion of the faster flowing water is in one direction within the flow there are irregularities everywhere within the flowing water. 
         [0097]    As the velocity of a liquid, V, increases, transition from laminar flow to turbulent flow will occur. 
         [0098]    Now consider using crude oil in place of water. Assuming a large enough pressure could be provided, even for “fast” flowing crude oil, the motion of the crude oil remains laminar. 
         [0099]    Further, consider a nozzle on a tap and constrict water flow into a fine glass capillary tube. In this instance, the flow can be made to go quite fast without the flow becoming turbulent. 
         [0100]    Laminar flow of liquid occurs for low speeds, small diameters, low densities and high viscosities. Turbulent flow of liquids occurs for the opposite conditions (i.e., high speeds, large diameters, high densities and low viscosities). 
         [0101]    Viscosity is a measurable property of a liquid. Some other examples of measurable properties of liquids are conductivity, density and temperature. Other examples of a measurable property of a liquid are sound pressure level (SPL) and vibration, both produced by the liquid flowing within a pipe. 
         [0102]    The term “kinematic viscosity” (units cSt or m 2  s −1 ) of a liquid refers to the viscosity of the liquid divided by the density of the liquid. 
         [0103]    In fluid mechanics, a value known as the Reynolds number, Re, quantifies the relative importance of inertial forces to viscous forces for a given liquid and given flow conditions. The Reynolds number for a liquid may be determined in accordance with Equation (1) below: 
         [0000]    
       
         
           
             
               
                 
                   
                     Re 
                     = 
                     
                       
                         
                           ρ 
                            
                           
                               
                           
                            
                           Vd 
                         
                         μ 
                       
                       = 
                       
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         [0104]    where V represents speed of the liquid in meters per second (ms −1 ) flowing through an orifice (e.g., inner diameter of a pipe) of diameter d in meters (m); μ represents absolute dynamic fluid viscosity in Newton seconds per meter squared (Nsm −2 ); V represents kinetic fluid viscosity in meters squared per second (m 2  s −1 ); and ρ represents density of the liquid in kilograms per meter cubed (kg m −3 ). 
         [0105]    If the speed of the liquid, V, or diameter, d, (or both the speed and the diameter) are small and the viscosity is large, the Reynolds number Re is small. In this instance, the flow of the liquid will be laminar. Increasing the diameter, d, or the speed, V, or decreasing the viscosity, will increase the Reynolds number, Re. 
         [0106]    For any type of fluid, flowing at any speed, V, in any pipe of diameter, d, flow of the liquid in the pipe, remains laminar for a Reynolds number, Re, less than approximately two-thousand-three-hundred (2300). For a Reynolds number, Re, greater than two-thousand-three-hundred (2300), turbulence occurs in the flowing liquid. 
         [0107]    As seen in Table 1 of Appendix A, the kinematic viscosity of water at 54.4° C. is approximately 0.55 cSt or 550×10 −3  m 2  s −1 . In contrast, the kinematic viscosity of crude oil at 54.44° C. is approximately 3.5 cSt. If the pipe diameter is one (1) cm, the speed, V, at which the Reynolds number, Re, is two-thousand (2000), is 0.2 ms −1  (0.72 kmh-1) which is a relatively slow speed. Water undergoes transition to turbulence at low speeds. 
         [0108]    While the transition from laminar to turbulent flow occurs at a threshold Reynolds number, Re, of approximately two-thousand-three-hundred (2300) in a pipe (e.g., the pipe  104 ), the precise value of the threshold Reynolds number depends on whether any small disturbances are present. If the inner surface of the pipe is very smooth and there are no disturbances to the velocity, higher values of the Reynolds number, Re, can be obtained with the flow still in a laminar state. However, if the Reynolds number, Re, is less than two-thousand-three-hundred (2300), then the flow of the liquid will be laminar even if the liquid is disturbed. Further, if the pipe has a different cross-sectional geometry (e.g., square), or the flow of liquid is over a turbine blade, then the transition from laminar to turbulent flow will occur at different Reynolds number values, Re. 
         [0109]    When the flow of liquid is turbulent, the liquid contains eddying motions of all sizes. Further, a large part of the mechanical energy in the turbulent flow goes into the formation of these eddies, which eventually dissipate their energy as heat and noise. As a result, at a given Reynolds number, Re, the drag of a turbulent flow is higher than the drag of a laminar flow. Also, turbulent flow is affected by surface roughness, so that increasing roughness of a surface increases the drag. The relationship between turbulent flow and drag is important to tailoring the value of the Reynolds number, Re, for a given system (e.g., the system  100 ). 
         [0110]    The kinematic viscosity of crude oil and water is substantially different, as seen in Appendix A. As a result, the difference between the laminar flow of crude oil and the turbulent flow of water in the pipe  104  may be detected using acoustic means in the form of the acoustic sensor array  109  attached to the pipe  104 . Any sounds and vibrations in the pipe  104 , caused by turbulence of the liquid, indicate that the liquid flowing through the pipe  104  is water. In contrast, relative silence and stillness within the pipe  104 , when liquid is flowing through the pipe  104 , indicates the laminar flow of crude oil within the pipe  104 . 
         [0111]    As an example,  FIG. 6  shows a fast Fourier transform (FFT) waterfall trace  600  simulating the flow of water through the pipe  104 . The trace  600  comprises a vertical axis showing sound pressure level (SPL) in decibels (dB). The horizontal axis of the trace  600  shows frequency in Hertz (Hz). The spectrum of the trace  600  is chaotic and resembles white noise. Of note in the trace  600  is the role off of the recorded signals below 100 Hz. This role off is an artifact of the recording equipment used to generate the trace  600  and would unlikely be present in a typical implementation of the system  100 . 
         [0112]      FIG. 7  shows a fast Fourier transform (FFT) waterfall trace  700  simulating the flow of crude oil through the pipe  104 . Again, the trace  700  comprises a vertical axis showing sound pressure level (SPL) in dB. The horizontal axis shows frequency in Hz. As seen in  FIG. 7 , the amplitude of signal above 100 Hz, as highlighted by oval  701 , is small compared to the trace  600 . The overall difference in SPL between the trace  600  and the trace  700  is approximately fifty (50) dB. Accordingly, the flow of crude oil within the pipe  104  may be distinguished from the flow of water within the pipe  104  by measuring the SPL using the acoustic sensor array  109  and comparing the measured level of SPL to a first predetermined threshold value. Determination of the first predetermined threshold value will be described in detail below and may be stored in the memory  206  or on the hard disk drive  210 . The area of the trace  700  highlighted by a circle  702  in the trace  700  is a combination of environmental noise and artifact of the equipment used to generate the trace  700 . 
         [0113]    The method  400  of detecting water to crude oil transition in the pipe  104  using the acoustic sensor array  109 , as may be executed at step  303 , will now be described in detail below with reference to  FIG. 5 . As described above, the acoustic sensor array  109  is fixed at a predetermined point to the outside of the pipe  104 . The method  400  may be implemented as one or more code modules of the software  133  resident on the storage module  159  of the embedded device  151  and being controlled in its execution by the processor  155 . 
         [0114]    The method  400  will be described by way of example with reference to  FIG. 9  which shows a graph  900  representing sound pressure level (SPL) versus time for a typical dewatering scenario. The method  400  detects water to crude oil transition based on a baseline ambient SPL within the pipe  104 . The processor  155  of the embedded device  151  may be configured to pole the acoustic sensor array  109  periodically (e.g., every second) to determine an SPL reading. Prior to commencement of dewatering at step  301  (i.e., prior to time t 0  in the graph  900 ), the software  133  (under execution of the processor  155 ) determines the baseline ambient SPL by determining output of the acoustic sensor array  109  at that time. The determined ambient SPL may be stored in the RAM of the storage module  159  as a two dimensional (2D) data object. 
         [0115]    The method  400  begins at step  401 , where the processor  155  determines the sound pressure level (SPL) measured in the pipe  104  at a current time. As seen in  FIG. 9 , dewatering of the tank  101  commences at time t 0  with the opening of the motorised valve  102 , as at step  301  of the method  300 . The opening of the valve  102  represents a step stimulus to the system  100  as the SPL measured in the pipe  104  begins to rise. The rising SPL will typically plateau, as at point A of the graph  900 . The plateau represents turbulent flow of liquid within the pipe  104  and will last for a period from time t 0  to t 1  at which time transition from water to crude oil commences. The plateau occurring at point A may be referred to as the “turbulent plateau”. The period from time t 0  to t 1  will be as long as the discharge of water continues in the pipe  104 . Accordingly, in the initial execution of the method  400 , the SPL measured in the pipe  104  at step  401  will be a value between the ambient SPL and the SPL level at the turbulent plateau of the graph  900 . 
         [0116]    The current value of SPL in the pipe  104  may be read by the processor  155  at step  401  from the RAM of the internal storage module  159 . Alternatively, the processor  155  may be configured to pole the acoustic sensor array  109  at the current time (i.e., real time capture) to determine the SPL reading. In another alternative, the processor  155  may be configured to record (i.e., capture and store) the signal (representing SPL) from the acoustic sensor array  109  for a predetermined period (e.g., sixty seconds). The processor  155  may also process the signal from the acoustic sensor  109  using cross correlation and FFT analysis and compare the determined values of SPL against previously learned (and stored) values. 
         [0117]    In one implementation, the processor  155  may be configured to implement a learning algorithm so that the system  100  may self adapt over a period of time to each new installation of the system  100 , as the frequency response of no two mechanical systems is exactly identical. For example, the system  100  may be configured to vary weightings associated with the acoustic sensor  109  and the conductivity sensor  108 . 
         [0118]    Returning to the example of  FIG. 9 , at time t 1 , the transition from water to oil commences, resulting in a knee (as at point B) on the graph  900 . As the transition continues following time t 1 , the rag interface layer separating the water and oil in the tank will be discharged typically resulting in a variable but reducing level of turbulence (i.e., reducing SPL) until time t 2 . At time t 2 , the majority of liquid flowing in the pipe  104  will be crude oil and the turbulence measured in the pipe  104  (i.e., represented by measured SPL) will plateau at a lower level. This lower level plateau represents laminar flow of liquid in the pipe  104  and may be referred to as the “termination plateau”. The ratio of water to crude oil in the liquid at the termination plateau will typically be around 20:80. Accordingly, point C on the graph  900  represents the point at which the valve  102  is closed, as at step  305  of the method  300 , in order to stop the liquid flowing out of the tank  101  into the pipe  104 . Point C may be referred to as the “termination point”. 
         [0119]    The difference between the baseline ambient SPL and SPL level at the turbulent plateau will typically be around 40 dB. However, this difference may vary significantly depending on the implementation of the system  100  and the liquid flowing in the pipe  104 . 
         [0120]    The difference between the SPL level at the turbulent plateau and the SPL level at the termination plateau will typically be between 30 dB and 40 dB. Accordingly, the SPL level at the termination plateau will be close to the baseline ambient SPL. In this instance, the first predetermined threshold used for detecting if the liquid flowing in the pipe  104  has transitioned from water to crude oil may be set to 10 dB above the ambient baseline level. Again, the difference between the SPL level at the turbulent plateau and the SPL level at the termination plateau may vary significantly depending on the implementation of the system  100  and the liquid flowing in the pipe  104 . The first predetermined threshold may be determined by the processor  155  prior to commencement of the method  300  and stored in the internal storage module  159 . 
         [0121]    Returning to the method  400 , at the next step  403 , if the processor  205  determines that the SPL at the current time is less than or equal to the first predetermined threshold value, indicating laminar flow within the pipe  104 , then the method  400  proceeds to step  405 . Otherwise, the method  400  returns to step  401 . Steps  401  and  403  may occur many times between time t 0  and time t 2  on the graph  900 . 
         [0122]    At step  405 , the processor  155  determines that the transition from water to crude oil has occurred. The processor  155  may set a flag, for example, configured within the internal storage module  159  in order to indicate that the transition has occurred. Accordingly, at step  303 , the processor  155  may detect whether the flow of liquid in the pipe  104  has transitioned from water to crude oil by determining the state of the flag. 
         [0123]    The SPL value determined at step  401  may represent an average (or Mean) SPL value dynamically determined by the processor  155  for a moving window of readings (e.g., 10 successive readings). The reason for using an average SPL value is to discount random noise and smooth the determined SPL data. The processor  155  may also be configured to determine a running standard deviation of the average SPL values. 
         [0124]      FIG. 10  is a graph  1000  showing SPL values against time in accordance with one example. The graph  1000  is similar to the graph  900 . As seen in  FIG. 10 , trace  1001  plots raw SPL values, trace  1002  plots average (or mean) SPL values, and trace  1003  plots the standard deviation of the windowed average SPL values. Point B (occurring at time t 1 ) on the graph  1000  substantially corresponds to point B (i.e., the knee) on the graph  900 . Point B on the graph  1000  may initially be determined by the processor  155  from a variation in standard deviation data (as represented by trace  1003 ) greater than three times the running average standard deviation (as represented by trace  1002 ). This three times factor may be refined as part of the learning algorithm. 
         [0125]    Point C (i.e., the point at which the termination plateau begins at time t 2 ) on the graph  1000  corresponds to point C on the graph  900 . In one implementation of the system  100 , point C may be determined and refined by the processor  155 , as at step  405 , based on decline in standard deviation (as represented by trace  1003 ) to 50% of the maximum value of standard deviation variation subsequent to point B. As seen in  FIG. 10 , point C corresponds to the point on trace  1003  where the variation in standard deviation has dropped to 50% of its maximum value subsequent to point B. Once point C is determined by the processor  155  in this manner, the processor  155  performs the step  305  of transmitting a signal to the motorised valve  102 , via the I/O interface  160 , to close the valve  102  in order to stop the liquid flowing out of the tank  101  in the pipe  104 . Accordingly, the determination at step  405  of whether the transition from water to crude oil has occurred may be made by determining when the variation in standard deviation has dropped to 50% of its maximum value subsequent to point B. In this instance, step  403  of the method  400  may be described as a determination by the processor  155  of whether an “SPL Function” is at the threshold. The term SPL Function here refers to each of a measured SPL value as described above; an average (or Mean) SPL value dynamically determined for a moving window of readings (e.g., 10 successive readings); and a running standard deviation of the average SPL values. 
         [0126]    As described above, the processor  155  may also be configured to implement a learning algorithm so that the system  100  may self adapt over a period of time to each new installation of the system  100 . For the acoustic sensor array  109 , in one implementation, the following system variables may be recorded into a history file stored within the internal storage module  159  to allow reinforced learning to take place, relative to time t 0 :
       (i) “t 1 ” —the time at which the standard deviation of the SPL increases by a factor of 3;   (ii) “t 2 ” —the time at which the standard deviation of the SPL decreases by 50%;   (iii) Ambient SPL;   (iv) Mean SPL between time “t 0 ” and time “t 1 ”; and   (v) Mean SPL after “t 2 ”.       
 
         [0132]    As seen in  FIG. 10 , the methods described above introduce a minimal amount of lag into the system  100 . However, the learning algorithm may account for this lag by applying weightings to the determined SPL values to ensure that point B occurs as close as possible to the actual beginning of the transition from water to crude oil. In this connection, in probability theory and statistics, standard deviation is a measure of the variability or dispersion of a population, a data set, or a probability distribution. A low standard deviation indicates that the data points tend to be very close to the same value (the mean), while high standard deviation indicates that the data are “spread out” over a large range of values. 
         [0133]    The standard deviation of a discrete random variable is the root-mean-square (RMS) deviation of its values from the mean. If the random variable X takes on N values x 1  . . . x N  (which are real numbers) with equal probability, then the standard deviation a of the variable X may be determined by finding the mean,  x , of the values x 1  . . . x N , determining the deviation (x i  . . .  x ) from the mean for each value x i . determining the squares of these deviations, determining variance σ 2  representing the mean of the squared deviations, and determining the square root of the variance. Accordingly, the standard deviation σ of the variable X may be determined in accordance with Equation 2 as follows: 
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         [0134]    The learning algorithm may be based on comparison of the SPL data values in the history file stored within the internal storage module  159 . The learning algorithm may be parameterised using the mean SPL values from previous dewatering processes, with SPL values beyond the mean by more than two standard deviations being ignored. 
         [0135]    During actual execution of the method  300 , the operator may be notified by way of the GUI displayed on the display device  214 , that the dewatering currently underway is atypical, where the actual determined SPL values are above the mean by more than two standard deviations. 
         [0136]    The learning algorithm may also compare data determined using the acoustic sensor array  109  to equivalent data determined using the conductivity sensor  108 , in order to correct the determination of points B and C on the graph  1000 . Electrical conductivity is measured in Siemens per metre (Sm-1). As seen in Appendix B, water has a conductivity ranging from pure water at 5.5×10 −6  μm −1  to sea water with a conductivity of 5 μm −1 . Depending on contamination levels, crude oil exhibits conductivity tending towards that of pure water. In particular, depending on source of the crude oil, the conductivity ranges from between 35×10 −6  μm −1  to 110×10 −6  μm −1 . Accordingly, crude oil may be distinguished from contaminated water passing through a non-contact conductivity sensor such as the conductivity sensor  108 . 
         [0137]    The method  500  of detecting water to crude oil transition in the pipe  104 , using the conductivity sensor  108 , as may be executed at step  303 , will now be described in detail with reference to  FIG. 5 . As described above, the conductivity sensor  108  is positioned at a predetermined point within the pipe  104 . The method  500  may be implemented as one or more code modules of the software  133  resident in the storage module  159  of the embedded device  151  and being controlled in its execution by the processor  155 . 
         [0138]    The method  500  will be described by way of example with reference to  FIG. 11  which shows a graph  1100  representing conductivity Siemens per metre (Sm-1) versus time for a typical dewatering scenario. The method  500  detects water to crude oil transition based on a baseline ambient conductivity value within the pipe  104 . The processor  155  of the embedded device  151  may be configured to pole the conductivity sensor  108  periodically (e.g., every second) to determine a conductivity reading. Prior to commencement of dewatering at step  301  (i.e., prior to time t 0  in the graph  1100 ), the software  133  (under execution of the processor  155 ) determines a baseline ambient conductivity value by determining a current output of the conductivity sensor  108 . The determination of the baseline ambient conductivity value allows for any plaque on the sensor  108  from any previous dewatering processes. The determined ambient conductivity value may be stored in the RAM of the storage module  159  as a two dimensional (2D) data object. 
         [0139]    The method  500  begins at step  501 , where the processor  155  determines conductivity of the liquid in the pipe  104  at a current time. As seen in  FIG. 11 , dewatering of the tank  101  commences at time t 0  with the opening of the motorised valve  102 , as at step  301  of the method  300 . The opening of the valve  102  represents a step stimulus to the system  100  as the conductivity value measured in the pipe  104  begins to rise. The rising conductivity will typically plateau, as at point A of the graph  1100 . The plateau represents turbulent flow of liquid within the pipe  104  and will last for a period from time t 0  to t 1  at which time transition from water to crude oil commences. Again, the plateau occurring at point A of the graph  1100  may be referred to as the “turbulent plateau”. The period from time t 0  to t 1  will be as long as the discharge of water continues in the pipe  104 . 
         [0140]    Similar to the method  400 , in the initial execution of the method  500 , the conductivity values measured in the pipe  104  at step  501  will be a value between the baseline ambient conductivity value and the conductivity value at the turbulent plateau on the graph  1100 . The conductivity reading may be stored in RAM of the internal storage module  159 . In this instance, at step  501 , the current value of conductivity may be read by the processor  155  from the RAM of the internal storage module  159 . Alternatively, the processor  155  may be configured to pole the conductivity sensor  108  at the current time to determine the conductivity reading. In another alternative, the processor  155  may be configured to record the signal (representing conductivity value) from the conductivity sensor  108  for a predetermined period (e.g., sixty seconds). 
         [0141]    Returning to the example of  FIG. 11 , at time t 1 , the transition from water to oil commences, resulting in a knee (at point B) on the graph  1100 . As the transition continues following time t 1 , the rag interface layer separating the water and oil in the tank  101  will be discharged typically resulting in a variable but reducing level of conductivity (i.e., reducing Sm-1) until time t 2 . At time t 2 , the majority of liquid flowing in the pipe  104  will be crude oil and the conductivity measured in the pipe  104  will plateau at a lower level. This lower level plateau represents laminar flow of liquid in the pipe  104  and, again, may be referred to as the “termination plateau” similar to the graph  900 . Accordingly, point C on the graph  1100  represents the point at which the valve  102  is closed, as at step  305  of the method  300 , in order to stop the liquid flowing out of the tank  101  in the pipe  104 . 
         [0142]    The difference between the baseline ambient conductivity value and the conductivity value at the turbulent plateau will typically range from 1 Sm −1  to 5 Sm −1 . However, this difference may vary significantly depending on the implementation of the system  100  and the liquid flowing in the pipe  104 . 
         [0143]    The conductivity of crude oil relative to water may be approximated to zero. As such, the system  100  may be configured so that the termination point (i.e., point C on the graph  1100 ) is reached when mean conductivity of the liquid in the pipe  104  drops to 20% of the difference between the baseline ambient conductivity value and the conductivity value at the turbulent plateau of the graph  1100  (i.e., 0.2 Sm −1  to 1 Sm −1 ). Accordingly, the difference between the conductivity value at the turbulent plateau and the conductivity value at the termination plateau will typically range between 0.8 Sm −1  to 4 Sm −1 . The conductivity value at the termination plateau will be close to the baseline ambient conductivity value. In this instance, a second predetermined threshold used for detecting if the liquid flowing in the pipe  104  has transitioned from water to crude oil may be set to 20% above the ambient baseline conductivity value. Again, the difference between the conductivity value at the turbulent plateau and the conductivity value at the termination plateau may vary significantly depending on the implementation of the system  100  and the liquid flowing in the pipe  104 . In one implementation of the system  100 , the second predetermined threshold may be set to 0.01 Sm −1 . 
         [0144]    Returning to the method  500 , at the next step  503 , if the processor  155  determines that the conductivity of the liquid at the current time is less than or equal to the second predetermined threshold value, indicating that the liquid flowing within the pipe  104  is oil, then the method  500  proceeds to step  505 . Otherwise, the method  500  returns to step  501 . 
         [0145]    Steps  501  and  503  may occur many times between time t 0  and time t 2  on the graph  1100 . The second predetermined threshold value may be stored in the internal storage module  159  of the device  151 . 
         [0146]    At step  505 , the processor  205  determines that the transition from water to crude oil has occurred. Again, the processor  205  may set a further flag described above, for example, configured within the memory  206  in order to indicate that the transition has occurred. Accordingly, at step  303 , the processor  205  may detect whether the flow of liquid in the pipe  104  has transitioned from water to crude oil by determining the state of the further flag. 
         [0147]    In one implementation, the system  100  may be configured so that the conductivity of the liquid must be less than or equal to the second predetermined threshold value for a predetermined period (e.g., sixty seconds), before the method  500  proceeds to step  505  and the processor  155  determines that the water has transitioned to crude oil. 
         [0148]    As described above, the processor  155  may also be configured to implement a learning algorithm so that the system  100  may self adapt over a period of time to each new installation of the system  100 . For the conductivity sensor  108 , the following system variables may be recorded into a history file stored within the internal storage  159  to allow reinforced learning to take place, relative to time t 0 :
       “t 1 ” —the time at which a running mean of sixty (60) conductivity readings drops by 20% from the conductivity value at the turbulence plateau;   (ii) “t 2 ” —the time at which the conductivity value has fallen to 20% of the conductivity value at the turbulence plateau (i.e., the second predetermined threshold). In one implementation, variable “t 2 ” may represent the time at which the conductivity has fallen to or less than the second predetermined threshold value for a predetermined period (e.g., sixty seconds);   (iii) Ambient conductivity;   (iv) Mean conductivity between time “t 0 ” and time “t 1 ”; and   (v) Mean conductivity at “t 2 ”.       
 
         [0154]    For the conductivity sensor  108 , the learning algorithm may be based on comparison of the conductivity values in a history file stored within the internal storage module  159 . The learning algorithm may be parameterised using the mean values from previous dewatering processes, with conductivity values beyond the mean by more than two standard deviations being ignored. Again, during actual execution of the method  300 , the operator may be notified by way of the GUI displayed on the display device  214 , that the dewatering currently underway is atypical, where the actual determined conductivity values above the mean by more than two standard deviations are ignored. 
         [0155]    The learning algorithm may also compare conductivity data values determined using the conductivity sensor  108  to equivalent data determined using the acoustic sensor array  109 , in order to correct the determination of points B and C on the graph  1100 . 
         [0156]    Once the water has been removed from the bulk-storage tank  101 , the valve  105  may be opened to send the crude oil to the transport system  107 . 
         [0157]    The methods  300 ,  400  and  500  described above may alternatively be implemented in dedicated hardware such as one or more integrated circuits performing the functions or sub functions of  FIGS. 3 to 5 . Such dedicated hardware may include graphic processors, digital signal processors, or one or more microprocessors and associated memories. 
         [0158]    In one embodiment, both of the methods  400  and  500  may be performed at step  303 . In this instance, the transition from water to crude oil may be determined to have occurred only when both of the sensors  108  and  109  provide a result indicating that the transition has occurred (i.e., when the measured SPL is less than the first predetermined threshold value and the measured conductivity is less than the second predetermined threshold value). 
         [0159]    Further, weightings may be applied to each of the sensors  108  and  109 . For example, the acoustic sensor array  109  may be given a higher weighting than the conductivity sensor  108 . In this instance, if the acoustic sensor array  109  indicates that the transition has occurred and the sensor  108  indicates that the transition has not occurred, then the processor  205  may still determine that the transition has occurred on the basis that the sensor array  109  has a higher weighting. 
         [0160]    The processor  205  may be configured to adjust the weightings associated with each of the sensors  108  and  109 , based on results produced by the system  100 . For example, upon the sensors  108  and  109  being installed and trials being conducted on the system  100 , one of the sensors  108  and  109  may be given a higher weighting if that sensor is found to produce more accurate and reliable results in indicating that the transition has occurred. After a predetermined period of time (e.g., one or more days or weeks) the weightings associated with the sensors  108  and  109  may be adjusted based on results at that time. 
         [0161]    The acoustic sensor array  109  is preferably configured to permanently bolt to the pipe  104  at a predetermined point of the pipe  104 . Alternatively, the acoustic sensor array  109  may be bolted to a fitting connected to the pipe  104 . Any suitable acoustic sensor may be used for the acoustic sensor array  109  in the system  100 . In one embodiment, the acoustic sensor  109  is a Sitrans™ AS100 manufactured by Siemens AG. The Sitrans™ AS100 requires a controller to process signals from the acoustic sensor array  109 . In this instance, the controller is a Sitrans™ AS100+CU02 manufactured by Siemens AG. Such a controller is electrically configured between the acoustic sensor array  109  and the electronic device  151 . 
         [0162]    The conductivity sensor  108  is preferably configured to overcome fouling and be resistant to moderate temperatures, chemical exposure and physical wear. For example, the conductivity sensor  108  preferably has a large bore to allow solids to pass through the sensor  108  without plugging, to allow the sensor to be used for applications containing high levels of suspended solids. The conductivity sensor  108  is preferably configured to measure accurately over a large range of Scm −1 . The conductivity sensor  108  may be formed of an exceptionally strong and hard material (e.g., chemically resistant polyetheretherketone (PEEK)). Any suitable conductivity sensor may be used for the sensor  108  in the system  100 . In one embodiment, the conductivity sensor  108  is a Rosemount™ Analytical Model  226  large bore “toroidal” conductivity sensor. The Rosemount™ Analytical Model  226  requires a controller to process signals from the conductivity sensor  108 . In this instance, the controller is a Rosemount™ Analytical Model 54eC. Such a controller is electrically connected between the conductivity sensor  108  and the electronic device  151 . 
         [0163]    The Model  226  conductivity sensor is very resistant to fouling effects. The Model  226  uses an inductive method of measuring conductivity. In addition, the Model  226  has a large 47 mm bore to allow solids to pass through the sensor without plugging. The Model  226  is preferably configured to work at temperatures to 120° C. and measure accurately over the range of 50 μScm −1  to 1,000 mScm −1 . 
         [0164]    In another embodiment, the conductivity sensor  108  is a Foxboro™ Model 875EC, Intelligent Electrochemical Analyser for Electrodes Conductivity Measurement sensor. In still another embodiment, the conductivity sensor  108  is a Foxboro™ Model 871EC-LB, Electrodes Conductivity Sensor—Large Bore, PEEK, High Sensitivity. 
         [0165]    In one embodiment, the valves  102  and  103 , the acoustic sensor array  109  and the conductivity sensor  108  may be connected directly to the local computer network  222 , as seen in  FIG. 8 . In the embodiment of  FIG. 8 , the methods described above may be implemented using the processor  205 . In this instance, the processes of  FIGS. 3 to 7  may be implemented as one or more software application programs resident within the hard disk drive  210  and being controlled in their execution by the processor  205 . In particular, the steps of the described methods may be effected by instructions in the software that are carried out within the computer module  201 . 
         [0166]    The ratio of crude oil to water in the liquid at different times should preferably be displayed on the GUI. As described above, the ratio of crude oil to water may be determined by the processor  155  based on SPL and/or conductivity measurements. The system  100  may be calibrated so that predetermined SPL and/or conductivity measurements indicate certain water to crude oil ratios of the liquid. 
         [0167]    The system  100  may also be configured so that the predetermined SPL and conductivity thresholds may be adjusted by an operator using the computer module  201 . 
         [0168]    The system  100  should preferably be fail-safe such that in the event of a failure the valves  102  and  105  should move to a closed position. 
         [0169]    In one implementation, a measuring means, in the form of an accelerometer may be fixed to the pipe  104  in a similar manner to the acoustic sensor  109  and the conductivity sensor  108 . The accelerometer may be used in place of the acoustic sensor array  109  and/or the conductivity sensor  108  or together with the array  109  and the sensor  108 . Such an accelerometer may be adapted to the lower end of the frequency spectrum in order to measure vibration at a predetermined point of the pipe  104 . In this connection, when water is flowing in the pipe  104 , the measured vibration will be relatively higher than when crude oil is flowing in the pipe  104 . A change in the level of vibration at the predetermined point of the pipe  104  may therefore be used to detect the water to crude oil transition of the liquid in a similar manner to the methods  400  and  500 . Similar to the methods  400  and  500  described above, the measured vibration may be compared to a predetermined threshold level of vibration. 
       INDUSTRIAL APPLICABILITY 
       [0170]    It is apparent from the above that the arrangements described are applicable to the computer and data processing industries. 
         [0171]    The foregoing describes only some embodiments of the present invention, and modifications and/or changes can be made thereto without departing from the scope and spirit of the invention, the embodiments being illustrative and not restrictive. 
         [0172]    For example, the methods  300 ,  400  and  500 , and the system  100  have been described above with reference to crude oil. The described methods may have applications with other liquids and substances including petroleum products. Such petroleum products include unfinished oils, liquefied petroleum gases, pentanes plus, aviation gasoline, motor gasoline, naphtha-type jet fuel, kerosene-type jet fuel, kerosene, distillate fuel oil, residual fuel oil, petrochemical feedstocks, special naphthas, lubricants, waxes, petroleum coke, asphalt, road oil and still gas. However, for the acoustic sensor array  109  to accurately differentiate between water and other water-insoluble liquid, the kinetic viscosity of this other liquid needs to be greater than water. 
         [0173]    In the context of this specification, the word “comprising” means “including principally but not necessarily solely” or “having” or “including”, and not “consisting only of”. Variations of the word “comprising”, such as “comprise” and “comprises” have correspondingly varied meanings. 
       APPENDIX A 
     Kinematic Viscosity of Water and Oil 
       [0174]      
         [0000]    
       
         
               
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 1 
               
               
                   
               
               
                 Liquid 
                 Variant 
                 Temperature 
                 Kinematic Viscosity (cSt) 
               
               
                   
               
             
             
               
                   
               
             
          
           
               
                 Crude oil 
                 48° API 
                 15.55 C. (60 F.) 
                 3.8 
               
               
                 Crude oil 
                 48° API 
                 54.44 C. (130 F.) 
                 1.6 
               
               
                 Crude oil 
                 40° API 
                 15.55 C. 
                 9.7 
               
               
                 Crude oil 
                 40° API 
                 54.44 C. 
                 3.5 
               
               
                 Crude oil 
                 35.6° API 
                 15.55 C. 
                 17.8 
               
               
                 Crude oil 
                 35.6° API 
                 54.44 C. 
                 4.9 
               
               
                 Crude oil 
                 32.6° API 
                 15.55 C. 
                 23.2 
               
               
                 Crude oil 
                 32.6° API 
                 54.44 C. 
                 7.1 
               
               
                 Water 
                 Pure 
                  20.2 C. 
                 1.0000 
               
               
                 Water 
                 Fresh 
                 15.55 C. 
                 1.13 
               
               
                 Water 
                 Fresh 
                 54.44 C. 
                 0.55 
               
               
                   
               
             
          
         
       
     
       APPENDIX B 
     Conductivity Information 
       [0175]      
         [0000]    
       
         
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 2 
               
               
                   
               
               
                 Liquid 
                 Variant 
                 Conductivity (S) 
               
               
                   
               
             
             
               
                   
               
             
          
           
               
                 Water 
                 Pure 
                 5.5 × 10 −6   
                 Sm −1   
               
               
                 Water 
                 Drinking 
                 0.005 to 0.05 
                 Sm −1   
               
               
                 Water 
                 Sea 
                 5 
                 Sm −1   
               
               
                 Crude Oil 
                 Maya 
                 60 to 110 × 10 −6   
                 Sm −1   
               
               
                 Crude Oil 
                 Istmo 
                 35 to 80 × 10 −6   
                 Sm −1   
               
               
                 Diesel 
                 United States of America 
                 50 to 840 × 10 −12   
                 Sm −1   
               
               
                 Gasoline 
                 United States of America 
                 25 × 10 −12   
                 Sm −1   
               
               
                   
               
             
          
         
       
     
       APPENDIX C 
     Density Information 
       [0176]      
         [0000]                                                                TABLE 3                   Densities of Water and Oil                            Density           Liquid   Variant   Temperature   (kg/m{circumflex over ( )}3)                            Crude oil   48° API   15.55 C. (60 F.)   790           Crude oil   40° API   15.55 C.   825           Crude oil   35.6° API   15.55 C.   847           Crude oil   32.6° API   15.55 C.   862           Crude oil   California   15.55 C.   915           Crude oil   Mexican   15.55 C.   973           Crude oil   Texas   15.55 C.   873           Water   Pure   15.55 C.   999           Water   Sea     25 C.   1022                        
For extrapolation to other temperatures, refer to the following from the Revised Petroleum Measurement Tables (IP 200, ASTM D1250, API 2540 and ISO R91 Addendum 1)
 
         [0000]    
       
         
           
             
               ρ 
               t 
             
             = 
             
               
                 ρ 
                 15 
               
                
               
                 exp 
                  
                 
                   [ 
                   
                     
                       - 
                       
                         a 
                         15 
                       
                     
                      
                     
                       
                         Δ 
                         t 
                       
                        
                       
                         ( 
                         
                           1 
                           + 
                           
                             0.8 
                              
                             
                                 
                             
                              
                             
                               a 
                               15 
                             
                              
                             
                               Δ 
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                         ) 
                       
                     
                   
                   ] 
                 
               
             
           
         
       
       
         
           
             where 
              
             
               : 
             
           
         
       
       
         
           
             
               ρ 
               t 
             
             = 
             
               
                 the 
                  
                 
                     
                 
                  
                 product 
                  
                 
                     
                 
                  
                 density 
                  
                 
                     
                 
                  
                 at 
                  
                 
                     
                 
                  
                 t 
                  
                 
                     
                 
                  
                 ° 
                  
                 
                     
                 
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                   . 
                   
                     
 
                   
                    
                   
                     ρ 
                     15 
                   
                 
               
               = 
               
                 
                   the 
                    
                   
                       
                   
                    
                   product 
                    
                   
                       
                   
                    
                   density 
                    
                   
                       
                   
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                    
                   
                       
                   
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                    
                   
                       
                   
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                   5 
                    
                   
                       
                   
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                     . 
                     
                       
 
                     
                      
                     
                       Δ 
                       t 
                     
                   
                 
                 = 
                 
                   
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                      
                     
                         
                     
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                     ° 
                      
                     
                         
                     
                      
                     
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                       . 
                       
                         - 
                       
                     
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                      
                     ° 
                      
                     
                         
                     
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                       . 
                       
                         
 
                       
                        
                       
                         a 
                         15 
                       
                     
                   
                   = 
                   
                     
                       tangent 
                        
                       
                           
                       
                        
                       thermal 
                        
                       
                           
                       
                        
                       expansion 
                        
                       
                           
                       
                        
                       coefficient 
                        
                       
                           
                       
                        
                       per 
                        
                       
                           
                       
                        
                       
                         °C 
                         . 
                         
                             
                         
                          
                         at 
                       
                        
                       
                           
                       
                        
                       15 
                        
                       ° 
                        
                       
                           
                       
                        
                       
                         C 
                         . 
                       
                     
                     = 
                     
                       
                         
                           K 
                           0 
                         
                         + 
                         
                           
                             K 
                             1 
                           
                            
                           
                             ρ 
                             15 
                           
                         
                       
                       
                         ρ 
                         15 
                         2 
                       
                     
                   
                 
               
             
           
         
       
     
         [0000]    
       
         
               
             
               
               
               
               
               
             
           
               
                 TABLE 4 
               
             
             
               
                   
               
               
                 Density Extrapolation Variables 
               
               
                 K0 and K1 are defined in accordance with Table 4 as follows: 
               
             
          
           
               
                   
                   
                 Density Range 
                   
                   
               
               
                   
                 Product 
                 (kg/m{circumflex over ( )}3) 
                 K 0   
                 K 1   
               
               
                   
                   
               
               
                   
                 Crude Oil 
                 771-981 
                 613.97226 
                 0.00000 
               
               
                   
                 Gasolines 
                 654-779 
                 346.42278 
                 0.43884 
               
               
                   
                 Kerosenes 
                 779-839 
                 594.54180 
                 0.00000 
               
               
                   
                 Fuel Oils 
                  839-1075 
                 186.96960 
                 0.48618