Abstract:
A method and apparatus is disclosed for measuring the flow of fluid in the conduit, giving the example of oil in a well bore ( 12 ). A heat exchanger such as a cooling station ( 66 ) is placed in the well bore ( 12 ) and caused to create a slug of cooled oil whose passage, through the well ( 12 ) can be monitored by a temperature sensor in the form of a continuous fiber optic loop ( 62 ). Knowledge of the movement of the cooled slug of oil and of the free cross-section of the conduit ( 54 ) wherein the oil is flowing permits the volume flow-rate of oil to be calculated. Cooling stations ( 66 ) are cooled by Joule-Thompson cooling employing high pressure nitrogen gas. Cooling stations ( 66 ) may be placed at plural locations within the well bore ( 12 ) to monitor individual flows ( 68 ) from multiple flow sources.

Description:
BACKGROUND OF THE INVENTION 
     The present invention relates to a method and apparatus for measuring the rate of flow of a liquid through a conduit. It particularly relates to a method and apparatus for measuring the rate of flow of hydrocarbons in production wells. Most particularly, it relates to a method and apparatus for measuring the rate and flow in production oil or water injection wells, and most especially relates to measurement of rates of flow in production oil wells where more than one source of flow opens into a common well head. 
     When extracting a flow of production fluids such as oil, from a well, it is important to be able to measure the rate of flow from the well head, and the contribution to the flow which comes from different sources opening into the common well head. In horizontal wells for hydrocarbon production, it is important for optimal recovery to know from which part of the reservoir the flow emanates. In multilateral wells, it is desirable to know how much each lateral contributes to the total production of the reservoir. If a particular lateral is producing too low a flow, it is then possible to take remedial action to increase its contribution. 
     Well bores are lined with casings whose approximate cross-sectional area is known. The free internal cross-sectional area of production tubing is also known. It is possible to derive a measure of the volume of flow at a specific location by measuring the linear flow-rate, or velocity, at that location. 
     It is known to measure flow-rates using measuring devices such as propellor driven flow meters. These are difficult to install within a well. The well has very limited cross sectional area thus limiting the size of device that may be installed. Propeller driven flow-rate meters are particularly difficult to install in horizontal wells or sub-sea wells. They are also difficult to install when a number of devices are required at different locations. The present invention seeks to provide a method and apparatus apt for the measurement of flow rate in horizontal wells, vertical wells, sub-sea wells and into the various parts of multilateral wells. The present invention also seeks to provide a method and apparatus for measuring flow rate at a plurality of points, unrestrained by the limitations imposed by the small cross-section of a well bore. 
     As well as the use of propeller driven devices such as spinner flow-meters, which turn at a rate dependent on the velocity of well fluids flowing past and are lowered down the well on an electric cable or wireline, apt for high flow-rate wells, it is also known in low flow-rate wells, which produce typically less than 1,000 barrels of oil a day, to use a radioactive tracer ejector tool. A radioactive marker (or tracer) is ejected into the oil flow. Gamma ray detectors are mounted above the ejection port on the tool. The ejector has to be replenished with tracers. The amount of time required for the marker or tracer to pass the gamma ray detectors gives a measure of the flow rate in the well. Gamma ray sources are a health hazard and require close custody and a monitoring. The present invention seeks to provide a method and apparatus for measuring flow rate in wells which has the same utility as the use of radioactive sources but lacks the health hazard associated with the radioactive tracer and which can remain permanently installed. 
     The prior art systems, in horizontal wells, both require deployment using coiled tubing. This is a very expensive proposition, and in sub-sea wells neither a wireline nor coiled tubing deployment systems can be used due to the limited access from the surface. The present invention seeks to provide a method and apparatus that can be so deployed without the expense of coiled tubing. 
     SUMMARY OF THE INVENTION 
     The present invention seeks to provide a non-invasive method and apparatus that can be pre-installed with the well, or subsequently at further work on the well, that is capable of monitoring fluid flow rate in well bores along reservoir intervals. 
     According to a first aspect, the present invention consists in an apparatus for measuring fluid flow in a conduit, said apparatus comprising: a temperature sensor for measuring and providing indication of the temperature of the fluid at at least first and second temperature measuring points spaced by a known distance along the conduit; a heat exchanger selectably operable to alter the temperature of the fluid upstream from said temperature measuring points; and a timer, responsive to said output of said temperature sensor to measure the time difference of arrival of the temperature altered fluid at said first and second temperature measuring points. 
     According to a second aspect, the present invention consists in a method for measuring fluid flow in a conduit, said method comprising the steps of: measuring the temperature of the fluid at a minimum of two temperature measuring points spaced by a known distance along the conduit; altering the temperature of the fluid upstream from said temperature measuring points; and measuring the time difference of arrival of the temperature altered fluid at said first and second temperature measuring points. 
     The first aspect of the invention further provides that the heat exchanger is operable to alter the temperature of the fluid for a selectable time. 
     The first aspect of the invention further provides an apparatus including a flow arrester, selectably operable to arrest the flow of the fluid in the conduit, the flow arrester being operable to arrest the flow of the fluid while the heat exchanger alters the temperature of the fluid, and the flow arrester valve being operable to allow the fluid to flow while the heat exchanger does not alter the temperature of the fluid. 
     The first aspect of the invention further provides that the temperature sensor can be a fibre optic cable, disposed along the conduit and operative to monitor temperature at a plurality of known, spaced locations along the length of the fibre optical cable. 
     The first aspect of the invention further provides that the heat exchanger can be operative to heat the fluid or, alternatively, to cool the fluid. 
     The first aspect of the invention further provides that the heat exchanger can be a gas expansion cooler, can comprise a throttle for cooling the gas and a cooling coil for the throttled gas to extract heat from the fluid, and can comprise a pressure relief valve, operative to allow gas to pass to be expanded if the gas supply pressure exceeds a predetermined limit. 
     The first aspect of the invention further provides that the apparatus can be for use where the fluid can be a hydrocarbon or water, where the hydrocarbon can be oil and where the conduit can be a hydrocarbon or water well. 
     The first aspect of the invention further provides that the flow arrester can be a selectably operable surface valve. 
     The first aspect of the invention further provides an apparatus which can be for use where the conduit has a plurality of flow sources, the apparatus comprising: a plurality of heat exchangers, each heat exchanger being downstream from a respective flow source; the temperature sensor being operative to measure and indicate the temperature at respective first and second points downstream from each heat exchanger; and the timer being operative to measure the time difference of arrival of temperature altered fluid at each respective pair of the first and second temperature measuring points. 
     The first aspect of the invention further provides an apparatus for use where the cross-sectional area of the conduit is known, the apparatus comprising computation means to calculate the volume rate of flow past the heat exchanger or heat exchangers, where the computation means can also calculate the volume rate of flow from each flow source. 
     The second aspect of the invention further provides a method including the step of altering the temperature of the fluid for a selectable time. 
     The second aspect of the invention further provides a method including the further step of arresting the flow of the fluid while altering the temperature of the fluid, and thereafter allowing the fluid to flow while not altering the temperature of the fluid. 
     The second aspect of the invention further provides a method including the use of a fibre optic cable, disposed along the conduit and operative to monitor temperature at a plurality of known, spaced locations along the length of the fibre optical cable. 
     The second aspect of the invention further provides a method wherein the step of altering the temperature of the fluid can involve heating the fluid or can involve cooling the fluid. 
     The second aspect of the invention further provides that the step of cooling the fluid includes the step of gas expansion and can include throttling the gas and passing the throttled gas through a cooling coil for the throttled gas to extract heat from the fluid; and can also include the use of a pressure relief valve to allow gas to pass to be expanded only if the gas supply pressure exceeds a predetermined limit. 
     The second aspect of the invention further provides a method for use where the fluid can be a hydrocarbon or water, where the hydrocarbon can be oil, and where the conduit can be a hydrocarbon or water well. 
     The second aspect of the invention further provides a method where the step of arresting the flow of the fluid can include the use of a selectably operable surface valve. 
     The second aspect of the invention further provides a method, for use where the conduit has a plurality of flow sources, the method comprising the steps of: altering the temperature of the fluid at a plurality of points, each downstream from a respective flow source; measuring the temperature at respective first and second points downstream from each point whereat the temperature has been altered; and measuring the time difference of arrival of temperature altered fluid at each respective pair of the first and second temperature measuring points. 
     The second aspect of the invention further provides a method for use where the cross-sectional area of the conduit is known, including the step of computing the volume rate of flow past the point or points whereat the temperature of the fluid has been altered. 
     The second aspect of the invention further provides a method including the step of calculating the volume rate of flow from each flow source. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     The invention is further explained, by way of an example, by the following description, taken in conjunction with the appended drawings, in which: 
     FIG. 1 is a cross-sectional view of multilateral oil well in which the present invention can be applied. 
     FIG. 2 is a cross-sectional schematic diagram of a multilateral, horizontal oil well to which the present invention can be applied. 
     FIG. 3 is a schematic cross-sectional view of an oil well showing a first essential component to the present invention. 
     FIG. 4 is a schematic cross-sectional view of an oil well showing a second component, cooling stations, being part of the embodiment for the present invention. 
     FIG. 5 is a view of a cooling station. 
     FIG. 6 shows a first method of supplying and exhausting high pressure nitrogen gas for the cooling stations. 
     FIG. 7A illustrates a method of providing high pressure nitrogen to cooling stations from a common line and venting to a common exhaust line. 
     FIG. 7B shows an alternate venting arrangement to that shown in FIG.  7 A. 
     FIG. 8A is a sketch of a cooling station, as actually implemented in a practical example. 
     FIG. 8B is the sketch of FIG. 8A, but showing an alternative embodiment where the pressure release valve is housed within a stinger. 
     FIG. 9 shows the effect of prolonged cooling in a well bore when the oil is not flowing. 
     FIGS. 10A and 10B are graphs illustrating how temperature spikes, generated as shown in FIG.  9  and when the fluid is flowing, move along the well bore. 
     FIG. 11 shows the basis for calculation of the volume rate of flow through the well bore and illustrates the various zones and temperatures and their cooling characteristics. 
     FIG. 12 is an actual graph of the temperature and depth response of a three cooling station well. 
     FIG. 13 is a schematic view of the elements required to operate the present invention. 
     FIG. 14 is a flow chart of the activities of the controller shown in FIG.  13 . 
     FIG. 15 is a graph of the temperature versus distance, with the cooling station operating, in a steadily flowing oil well. 
     FIG. 16 is a graph showing the initial stage where a cooling operation is commenced in the well bore with the oil flowing. 
     FIG. 17 is a graph showing the effect of cessation of a cooling operation in a well bore with the oil steadily flowing. 
     FIG. 18 is a graph showing the movement of a temperature spike, otherwise shown in FIG. 9, as the well bore changes from a non-flowing to a flowing situation. 
     FIG. 19 is a graph of actual data recorded as the cooling element is switched off and flow carries the cooled fluid downstream. 
    
    
     DETAILED DESCRIPTION 
     Attention is drawn to FIG. 1 showing a schematic cross-sectional view of a multilateral production well to which the present invention is applicable. 
     From a surface  10  a well bore  12  passes first through non oil bearing surface rock  14  and formations, then through a first lateral oil bearing formation  16 , thereon through non oil bearing intermediate formations  18 , on into a second lateral oil bearing formation  20 , where the well bore  12  may terminate, or may further penetrate through a further intermediate non oil bearing formation  22  to engage further oil bearing formations there below. 
     A first arrow  24  is indicative of the flow of oil from those oil bearing formations below the further non oil bearing formation  22 . A second arrow  26  shows the flow of oil from the oil bearing layers below FIG. 1, together with the flow of oil from the second lateral oil bearing formation  20 . A third arrow  28  shows the flow of oil indicated by the second arrow  26  together with the contribution from the first lateral oil bearing formation  16 . It is an object of the present invention to make it possible to measure the contribution made by each or any of the oil bearing formations  16   20  to the overall flow  28  rising in the well bore  12 . 
     Attention is drawn to FIG. 2, showing a horizontal well bore for which the present invention is apt for use. 
     The well bore  12  passes through the surface rock formations  14  and is gently angled to form a first horizontal lateral bore  30  extending at an angle, which can reach horizontal, into a first horizontally displaced oil bearing formation  32 . The well bore  12  is again gently curved to drill and form a second horizontal lateral bore  34  whose angle can be curved as far as the horizontal. The second horizontal lateral bore  34  passes into a second horizontally displaced oil bearing formation  36 . 
     A fourth arrow  38  indicates the flow of oil from the first horizontally displaced oil bearing formation  32 . A fifth arrow  40  shows the contribution to the oil flow made by the second horizontally displaced oil bearing formation  36 . A sixth arrow  42  shows the sum of the flows indicated by the fourth arrow  38  and the fifth arrow  40  passing up through the well bore  12 . FIG. 2 illustrates that a well bore can be curved as far as the horizontal and that a well bore  12  with lateral bores  30   34  can also be multilateral. The manner of disposition of the present invention, is as described in PCT PATENT application WO 98/50681. 
     The present invention can be applied to measure one, all or some of the flows  38   40   42  in such a situation. 
     Attention is drawn to FIG. 3 showing some of the component parts of an oil well and illustrating a first important element of the present invention. 
     A well head  44  is set into the well bore  12  and provides support, control and registration for further operations in a manner well known in the art. The well bore  12  descends, through the surrounding surface rock  14 , to the oil bearing formation  46 . Intermediate casing  48  is provided on the walls of the well bore  12  and held in place against the surrounding surface rock  14  by concrete  50  which is driven in a slurry to be forced up the gaps between the intermediate casing  48  and the surrounding surface rock  14  and sets to keep the intermediate casing  48  in place. 
     A production liner  52 , a perforated steel tube which allows ingress of oil, extends into the oil bearing formation  46 . Production tubing  54  allows pumping of oil from the production line  54  towards the well head  44 . 
     A surface control valve  55  can be opened to permit the flow of oil in the well bore  12  or closed to prevent the flow of oil in the well bore  12 . 
     A fibre optic coupling station at the surface  10  provides a start and end point for a loop of high pressure tubing  58  which passes through the well to the bottom of the oil bearing formation  46  and returns to the fibre optic coupling station  56 . As will later be illustrated, a continuous fibre optic line is driven through the loop of high pressure tubing  58  by water pressure to descend the bore  12  and to return to the surface. The continuous loop fibre optic in the high pressure tubing  58  is used to monitor temperature in the bore  12 . Such use is explained, for example, in GB 2122337 and EP 0213872. 
     Attention is drawn to FIG. 4 showing a schematic view of a cross section of an oil well illustrating further elements in the present invention. 
     The high pressure tubing  58  has a supporting “stinger”, a small diameter tube which can be inserted into the production tubing  54 , supporting the high pressure tubing  58  in its loop. The stinger  60  tubes are assembled at the surface  10  and lowered one by one, as an assembly, into the well bore  12  until the end of the loop of high pressure tubing  58  reaches the greatest depth, in the well bore  12 , from which measurements are to be made. The fibre optic cable  62  is passed down the high pressure tubing  58  by passage of fluid, around the U-bend  64  at the bottom of the loop of high pressure tubing  58 , and back to the fibre optic coupling station  56  at the surface  10 . 
     Also supported on the stinger  60  are a plurality of cooling stations  66 , positioned on the stinger  60  to intercept each flow  68  to be measured after its entry into the well bore  12  and before the entry of any other flow  68 . 
     Attention is drawn to FIG. 5 showing details of the elements of a cooling station  66 . The stinger  60  lies within the production tubing  54 . A nitrogen supply line  70 , bearing nitrogen, from the surface, under extremely high pressure, is attached to a pressure release valve  72 , the nitrogen supply line  70  is pressurised below 6,500 lb per sq inch (45 MPa) when the valve  72  is shut. As soon as the pressure in the nitrogen supply line  70  exceeds 6,500 lb per sq inch (45 MPa), the valve  72  opens and allows fresh passage of high pressure nitrogen therethrough. From the valve  72 , the high pressure nitrogen passes through a small diameter tubing throttle  74  wrapped around the stinger  60 , in which the pressurised nitrogen undergoes Joule-Thompson cooling. Thereafter, the cooled nitrogen passes to a cooling coil  76  which cools the surrounding, passing oil. The spent nitrogen is then returned towards the surface in an exhaust line  78 . 
     Attention is drawn to FIG. 6 which shows one way in which the cooling stations  66 , down the stinger  60 , can be provided with high pressure nitrogen. In FIG. 6, each cooling station  66  is provided with its own nitrogen supply line  70  and its own exhaust line  78 . The respective pairs of an exhaust line  78  and a supply line  70  are threaded, on the surface of the stinger  60 , to the individual cooling stations  66 . 
     FIG. 7A shows another manner in which the cooling station  66  may be connected to the exhaust line  78  and the nitrogen supply line  70 . Instead of having individual supply lines  70  and exhaust lines  78 , the cooling stations  66  are connected to a common supply line  70 A and a common exhaust line  78 A. Whereas the arrangement shown in FIG. 6 permitted individual cooling stations  66  to operate, the arrangement shown in FIG. 7 causes all of the cooling stations  66  to operate simultaneously. As will be appreciated, all of the Figures showing an oil well are very much minimised in the longitudinal (vertical) direction. Individual cooling stations  66  may be many hundreds or thousands of feet apart. As will become clear from the following explanation of use, the present invention is completely functional even when all cooling stations  66  are simultaneously activated. 
     FIG. 7B shows another manner in which the cooling stations  66  may be connected to the exhaust line  78  and the nitrogen supply line  70 . A common supply line  70 A is provided. Instead of having a common return line  78 A, each cooling station  66  has its own truncated return line  78 C capped, for preference, by a non-return valve  79  which prevents ingress of oil into the truncated return line  78 C. This arrangement has the advantage that each of the cooling stations  66 , being vented by the same length of truncated return line  78 , is more balanced in its performance with the other cooling stations  66  in the well bore  12 . 
     As an alternative, not shown in FIG. 6, FIG. 7A or FIG. 7B, the exhaust line  78 A may be omitted and the nitrogen, having passed through the cooling coil  76 , can be vented directly into the surrounding oil in the production tubing  54 . The arrangements of FIG.  6  and FIG. 7 are preferred however since this does not contaminate the oil, even with inert gas and does not introduce gas into the immediate vicinity of the cooling station  66 . 
     FIG. 8A is a sketch of a real life implementation of a cooling station  66  that has actually been tested. All of the numbers refer to the same elements as in the other Figures. The cooling coil  36  and the throttle  74  are simply lengths of tubing wound on the stinger  60 . The cooling coil is ⅜″ (9.5 mm) diameter tubing and the throttle is ⅛″ (3.1 mm) diameter tubing. The pressure release valve  72  is simply in series therewith. It is to be noted that the stinger  60  comprises four fins  80  which space it from and hold it central within the wall of the production tubing  54 . The fibre optic line passes through the high pressure tubing  58 , which is here shown terminating on this particular stinger  60  with its U-bend  64  on the cylindrical surface of the stinger  60 . The various lines  70   78   58  are simply clamped to the cylindrical surface of the stinger  60  by any means which will hold them in place. To give an idea of the scale, the diameter of the cylindrical body of the stinger  60  is only 4.8 cm (1.9 in). The cross section presented within the production tubing  54  is small enough not to represent a significant impedance to the flow of oil. 
     FIG. 8B shows another, preferred embodiment, similar to FIG. 8A but with one of the fins  80  and the high pressured tubing  58  omitted for clarity. In this embodiment, the pressure release valve  72  is housed within the stinger  60 . This embodiment presents a lower cross-sectional area for the entire stinger  60  assembly, and protects the pressure release valve  72 . In FIG. 8A, the pressure release valve  72  is shown protected by the fins  80 . Increased protection for the pressure release valve  72  is found in FIG. 8B, the pipes to and from the pressure release valve  72  passing through the wall of the cylindrical section of the stinger  60 . 
     Attention is drawn to FIG. 9, a graph showing the effect, over time, of the cooling station  66  in a well bore when high pressure nitrogen is vented through the pressure release valve  72 , the throttle  74 , and the cooling coil  76 . The horizontal extent of the graph is shown, for size comparison, against the real size of a cooling station  66 . A first curve  82  shows the temperature profile around the cooling station  66  at the start of the cooling process. The reservoir temperature (the ambient temperature at that depth) is around  51  Degrees Celsius. A second curve  84  is the temperature profile around the cooling station  66  nine minutes after the first curve  82 . A full 2 Degrees Celsius temperature drop has been achieved. A third curve  86  shows the temperature profile around the cooling station  66  seventeen minutes after the first curve  82  and eight minutes after the second curve  84 . As can be seen, after just seventeen minutes of cooling, a temperature drop of 4 Degrees Celsius has been achieved. 
     The measurements, shown in FIG. 9, were taken in a well bore with the main flow from the well bore shut off. The present intention is intended mainly for use with measurements under constant flow, but also with a stop-start process. 
     FIG. 10A shows a series of graphs illustrating what happens when the oil in the well bore  12  is started to flow. Each horizontal axis  80 , in the depth direction, carries a graph of the temperature spike  90  as the oil is first cooled during a no flow period and then the cooled oil moves away from the cooling station  66 . Each of the graphs on the horizontal axis  80  is effectively the graph of FIG. 9, but taken some time afterwards and with the exception that the oil is flowing in the well bore  12 . As the oil flows, the height of the temperature spike  90  steadily decreases. The oil, having been cooled when the oil was not flowing in the well bore  12 , now moves away from the cooling station  66  and carries with it the cold oil which was cooled down during a period of cooling. The gradient line  92  indicates the rate of flow of the oil in the well bore  12 . In other words, the temperature spike  90  moves along the well bore and is detected by the fibre optic cable  62  in a series of spaced measurements. The fibre optic cable  62  is capable of knowing at what distance along its length a particular temperature exists. As the temperature spike  90  carried by the slug of cooled oil moves away from the cooling station  66 , so it begins to be warmed through the walls of the production tubing  54  and the temperature spike steadily decreases in size. 
     FIG. 10B is a suitable set of graphs to those of FIG. 10A, showing the response when the cooling station  66  is switched on whilst the well is flowing. In this case the amount of cooling is less because heat is carried up the well by the flowing fluid—typically 0.5-1.0 Degrees Centigrade. However, when the cooling element  66  is switched off, the cooled slug of fluid moves up the well in the same manner as with FIG.  10 A. In this case, a number of temperature measurements at different depths are required in order to statistically resolve the small temperature changes produced in the well flowing measurement. 
     FIG. 11 is a schematic diagram of oil flowing in the production tubing  54  illustrating the manner in which the rate of flow of oil is measured and the manner in which the temperature differential of the spike  90  decays. 
     In the first region  94  the oil, not having yet encountered the cooling station  66 , moves with a velocity V. The internal diameter of the production tubing  54  is D. In the first region  94  the oil has a temperature, reflecting the temperature of the ambience surrounding rock, of T 1 . The cooling station  66  is located at the termination of the first region  94 . The cooling station  66  cools the oil to a lower temperature T 2  in a second region  96 . In subsequent regions  97  the oil begins to warm as it continues up the well bore  12  heat being transferred from the production tubing  54  to the oil by conduction. The oil warms through successive temperatures T 3  to T 6 , where T 6  approximates to the local reservoir temperature which may or may not be the same as T 1 . The associated graph  100 , with the vertical axis in the same scale as the distance along the production tubing  54 , shows how the initial temperature drop decays, exponentially with distance along the production tubing  54 , and subsequently with time. The calculation box  102  shows this formula by which the volume of oil per second, moving along the production tubing, is calculated. 
     Attention is drawn to FIG. 12 showing a typical temperature measurement down an oil well, the temperature in degrees Celsius being shown against depth in the well. 
     The pressure release valves  72  are designed to open when the pressure in the nitrogen supply line  70  exceeds 6,500 psi (45 MPa). The example shown, in FIG. 12, illustrates a well where three cooling stations  66  have been placed. With the well not flowing, a lower curve  110  is obtained which includes the temperature anomalies caused by injecting high pressure gas through the 3 cooling coils. A first temperature drop  104  shows the location of the uppermost of the cooling stations  66 . A second temperature drop  106  shows the location of a middle cooling station  66 . A third temperature drop  108  shows the location of the lowest of the three cooling stations  66 . When the well has been flowing for sixteen hours, an upper curve  112  is obtained which, beyond a heating spike  114 , caused by the presence of a down-well pump, matches the lower curve  110  in the value of its ambient down-well temperature. 
     Attention is drawn to FIG. 13 showing a possible control set-up which could be used with the present invention. At the surface  10  of the well bore  12  the fibre optic coupling station  56  feeds the two fibre optic cables  62  into an analyser  116  which feeds depth and temperature information to a controller  118 . The controller  118  in turn provides operational commands to a valve controller  120  which selectably operates the surface valve  55  which is situated in the top of the well bore  12 , above all sources of supply of oil to the well bore  12 . The controller  118  also provides commands and instructions to a nitrogen supply module  124  which is selectably operable to provide nitrogen, from a high pressure nitrogen reservoir  126  to the nitrogen supply line  70  feeding a cooling station  66  in the well bore  12 . 
     Attention is now drawn to FIG. 14, showing a flow chart of the activities of the controller  118  when conducting flow rate measurements based on the actual manual process used in current installations. 
     From a start  128  a first test  130  awaits a well start-up command. It is presumed that the well is switched off. If a well start-up command is received, a first operation  132  selects a start-up cooling period to be used in the well when the oil is not flowing. In the preferred embodiment of the present invention, the start-up cooling period is selected to be in the region of twenty minutes. It is to be appreciated that the cooling period can be greater or lesser than this dependently upon the sensitivity of the temperature measuring apparatus, and dependently upon the degree of cooling which is required. 
     Thereafter, a second operation  134  causes the nitrogen supply module  124  to supply nitrogen to the cooling station  66  or cooling stations  66  in the well bore  12 . The pressure of the nitrogen supplied is above the pressure for opening the pressure release valve  72  so that the cooling stations  66  begin to cool the surrounding oil in the well bore  12 . A third operation  136  maintains the supply of nitrogen to pass through the cooling station  66  for the selected cooling period. At the end of the third operation  136 , a fourth operation  138  switches off the nitrogen supply to the cooling stations  66  terminating the cooling epoch. A starting operation  139  opens the surface valve  55  so that the well starts flowing. The controller  118  then tracks the temperature spikes  90  in a fifth operation  140 . By using measurement intervals of one metre and taking temperature samples every twenty-five seconds, the controller  118 , receiving data from the analyser  116 , and acting as a timer to time the difference of arrival of the temperature spikes  90  at different points, knows the linear rate of flow of oil departing from each cooling station  66 . A sixth operation  142  then calculates the volume rate of flow past each cooling station  66  and a seventh operation  144  calculates the volume flow contribution from each source feeding the well bore  12 . 
     A second test  146  determines whether or not the temperature measurement run is a simple static test or whether production is to continue. If the second test  146  detects that production is not to continue, an eighth operation  148  causes the valve controller  122  to close the surface valve  55  and goes to an exit  150 . The results obtained are exemplary of those shown in FIG.  10 A. 
     If the second test  146  detects that the measurement operation is to be done over a production run, a ninth operation  152  selects the cooling period to be used while the production is running. The cooling period to be used when oil production is running can be the same as the start-up cooling period or can be shorter or longer depending upon the measurements requirements. For example, a shorter running period will give a smaller temperature drop. A longer running period will give a greater temperature drop. The initial start-up cooling period, while the oil was not running in the well bore  12 , gives a cold slug of oil whose progress along the well bore  12  can be measured to give a first idea of the flow rate of the oil in the well bore  12 . The ninth operation  152  can select the cooling period to be used while the well bore  12  is producing oil, dependently upon the initially measured rate of flow of oil. The faster the oil flows, the longer must be the cooling period for the minimum measurable temperature drop to be established. 
     The ninth operation  152  then passes on to a tenth operation  154  during which all operation of the cooling stations  66  is suspended for the measurement interval. The measurement interval is the period of time between flow rate tracking measurements. In a fast-running well, this can be just a few minutes. In a slow-running well, the measurement interval can be much longer. The tenth operation  154  can select the measurement interval dependently upon the observed temperature fall and the initially measured flow rate in the well bore  12 . 
     The tenth operation  154  then passes control back to the second operation  134  which switches on the nitrogen supply to start the cooling process over again by producing another set of temperature spikes  90  which can be tracked in the manner shown in FIG.  10 . 
     The controller  118  thus continues making flow rate calculations, based on the movement of cold slugs of oil, at repeated measurement intervals until the second test  146  detects that the production run is over. The results obtained are exemplary of FIG.  10 B. 
     Attention is drawn to FIG. 15 which illustrates the process of tracking the temperature spikes undertaken in the fifth operation  140 . 
     FIG. 15 is a graph of the steady state conditions, with the cooling stations  66  operative, reached in the well bore  12 . 
     The cooling station  66  creates a temperature drop in the oil flowing past. The fourth curve  156  shows the situation where the oil is flowing at a first velocity. The oil cools down steadily with time, and the distance moved by the oil is proportional to time. A fifth curve  158  shows what happens when the oil is moving more quickly. The fifth curve  158  has the oil moving twice as quickly as for the fourth curve  156 . The initial temperature drop is only half as high in the fifth curve  158  as it is in the fourth curve  156 . However, because the oil is flowing twice as quickly, the distance factor is also multiplied by two, so that, beyond a critical distance, the fifth curve  158  exceeds the value of the fourth curve  156 . The cooling with distance curves shown in FIG. 15 are the basis for the following Figures. 
     Attention is drawn to FIG. 16 which shows the situation, while the oil is flowing, which occurs when the cooling station  66  is switched on. In a first example, where the oil is flowing at the slower velocity, a “slug” of cooled oil has the temperature gradient with distance shown by curve  156 A. There is a sharp transition  160  to the fourth curve  156  at the point where the flowing oil has reached since the cooling started. 
     The slug of cooled oil, whose temperature profile is shown by the curve  158 A, is exemplary of the oil having double the velocity to that illustrated by curve  156 A. In this instance, the cooled slug of oil has progressed twice the distance as the slug of oil illustrated by curve  156 A. 
     Attention is drawn to FIG.  17 . Here, the cooling has been switched off and the oil continues to flow. The slug of oil, at the slower velocity, is exemplified by curve  156 B. The temperature of each part, as it moves along the well bore  12 , follows the exponential temperature difference curve  156  shown in FIG.  15 . Had the oil been flowing at double the rate illustrated by  156 B, curve  158 B would have been the result. It, too, represents a slug of oil which cools, as it moves along the well bore  12  according to the exponential temperature difference curve  158  shown in FIG.  15 . 
     FIG. 17 shows that trailing edge  162  of a slug of cooled oil, when the cooling operation is applied while the oil is flowing, is very much more prominent in its temperature drop signature than the trailing edge  162 . 
     In the fifth operation  140 , when the flow of oil has been established and the well bore  12  is in constant production, for the reasons illustrated in FIGS. 15,  16  and  17 , more easily tracks the trailing edge  162  of the cooled slug of oil in each instance. Nonetheless, the leading edge  164  and the main body of the cooled slug of oil can also be tracked. 
     After the start-up cooling period, which is sufficient to allow the static oil to reach close to its maximum temperature drop, the surface valve  55  is opened, a down-well pump  122  is switched on and the oil begins to move. As time passes, the originally static primary cooling spike  166  becomes a moving temperature spike  168 . It is to be observed that its amplitude decreases in accordance with the exponential cooling decay curve  156  of FIG.  15 . The further the moving spike  168  moves along the well bore  12  the smaller it gets. In this instance, of the initial start-up flow measurement, the rate of flow of oil can be tracked by the fifth operation  140  monitoring either or both of the leading edges  164  and the trailing edges  162 , since both, in this instance, are equally well defined. 
     Attention is drawn to FIG.  18 . FIG. 18 illustrates the situation which happens at the start-up cooling period selected by the first operation  132  of FIG.  14 . The oil is not flowing. The cooling station  66  is switched on. A primary cooling spike  166  is built up, as illustrated by FIG. 9, in the vicinity of the cooling station  66 . 
     Attention is drawn to FIG.  19 . FIG. 19 is an actual graph of real data recorded in a water test flow loop where the water has been cooled by the cooling coil and the cooling is then stopped. The flow of fluid up the well carries the warm/cold interface up the well and the slope of track of the interface in both depth and time, as exemplified by a slope line  170 , can be converted into a fluid velocity. The plot demonstrates the warming of the fluid upstream of the cooling coil both when the cooling is taking place and once it is switched off. 
     It is to be appreciated that the present invention is also operative to measure reverse flow in the oil well. Some flow sources may be reversed if the pressure of other flow sources is excessive within the well. 
     While the invention has been described with reference to an oil production well  12 , the invention can be applied to any fluid, such as water or gas, flowing in any conduit, such as a water main, open channel or a gas pipeline. The invention has been described with reference to a Joule-Thompson effect cooling station  66 . It is to be appreciated that the invention can have any kind of heat exchanger to alter the temperature of the fluid, such as electrical refrigerators or heaters either heating the fluid directly by a heat exchanger, as with the gas cooling described herein, or by ejecting a suitably preheated slug of fluid into the well bore. The fluid can be heated or can be cooled to create a moveable slug of fluid whose progress can be tracked. The heat exchanger can be electrically or chemically driven. The present invention has been shown as utilising a surface valve  122  as a flow arrester by being switched off. The invention can also use any type of flow arrester which can achieve this purpose. The invention has been described using a fibre optic temperature sensor  62 . It is to be appreciated that any temperature sensor which can measure the temperature at two or more points downstream from each heat exchanger is also within the invention, and can include thermocouples, infra red imaging devices and simple thermometers. 
     The invention is further explained by the following claims.