Borehole fluid flow monitoring apparatus

Abstract: A well logging sonde carries first and second electro-acoustic transducers (23,33) and control means (52,54) operable to control the transducers so that during a first measurement step the first transducer (23) transmits a pulse and the second transducer (33) receives a pulse that has passed through the fluid and so that during a second measurement step the second transducer (33) transmits a pulse and the first transducer (23) receives a pulse that has passed through the fluid. Signal means (60,64,69) provides travel time signals representative of the travel times of a pulse between the transducers in the two measurement steps, and deriving means (80) at the surface is connected to the signal means through a cable (56), and derives a signal representative of the velocity of the fluids in accordance with the travel time signals. The sonde may also carry caliper means (43) to measure the borehole diameter, and the deriving means can then also derive the volume flow rate of the fluid.

Description: The present invention relates to well logging systems for monitoring the flow of a fluid in a borehole traversing an earth formation. One of the primary applications of production logging is to determine the oil and water flow rates at various depths in a well. These rates are calculated from the measurements of water hold-up and total flow. The accuracy of the results is greatly influenced by both the total flow and water hold-up measurements. In production logging, flow measurements are made almost entirely by spinners or impellers. The total flow rate of the fluid is related to the speed of the spinner which is measured by electrically counting the revolutions per second (RPS) of the impeller. Even though spinners have been widely used for many years and have been greatly improved, they still have many disadvantages and restrictions. Some of the disadvantages of a spinner flowmeter relate to mechanical effects and others relate to the properties of the fluid and the flow which is being measured. For example, the impeller of the spinner operates on a bearing which wears and requires frequent inspection and replacement to keep frictional effects from influencing the measurements. Another disadvantage, which increases logging time on the well, is that calibration must be done downhole by making several extra logging runs at various logging speeds. In reference to the fluid properties, the spinner speed is not only affected by changes in the velocity of the fluid but also by changes in the viscosity and temperature of the fluid. One of the major restrictions on spinner flowmeters is that the minimum measurable flow is not low enough to measure all the flow rates of interest in many wells. Logging companies have taken two approaches to overcome this limitation. One approach uses spinners with longer blades or impellers to expose more surface area to the flow. These spinners, called fullbore spinners or flowmeters, do operate at lower flow rates but still suffer from the problems discussed previously. In fact, they may suffer even more since a greater surface area is exposed to the fluid and the flow. An additional mechanical problem is involved because the longer blades of this spinner must be designed and operated to collapse into the standard 4,3 cm (1 11/16 inch) tool diameter. This constraint is required so the tool can be lowered and raised through the production tubing in the well. The second approach that has been taken to overcome the minimum flow limitation of the spinner is to divert all the flow in the casing or borehole through the center of the tool where the spinner is located. Since the diameter of the flow is greatly reduced, its velocity will increase to a level where the spinner is operational. The flow is diverted through the center of the tool by using either an inflatable packer (packer flowmeter) or an expandable basket (basket flowmeter). Both of these diverting flowmeters also suffer from additional mechanical problems. They must not only expand to produce a seal between the tool and the casing or borehole, but they also must collapse into the 4,3 cm (1 11/16 inch) tool diameter for passage through the production tubing. Since there is no way to ensure a good seal, leakage around the tool is always possible and could cause significant errors in the measured flow. Calibration of the diverting flowmeters is also questionable. Since a seal is required between the tool and the borehole, only stationary measurements can be made. Thus the logging engineer can not perform the normal downhole calibration by running at different logging speeds. One must calibrate these tools in a flow loop at a test facility, and assume that the calibration remains constant during logging. Initially, such a calibration is probably sufficient, but as the bearing of the spinner wears and as different fluids mixtures and properties are encountered, the calibration may become inaccurate. One final limitation of the fullbore flowmeter and the diverting flowmeters is that they were designed for low flow rates and can not be operated in some of the higher flows. In many wells, one will be interested in measuring both the low flow rates in the lower zones and the higher rates that develop in the upper portion of the well. Thus in addition to a low flow rate device, a regular spinner must also be run. Since one is normally interested in obtaining other borehole data, the production tool string is usually already configured to its maximum length. Therefore, to run both a regular spinner and a low flow rate meter, an extra trip into the hole will probably be required which will increase the logging cost and the time on the well. US-A-4,452,077 describes a well logging system for monitoring the flow of a fluid in a borehole traversing an earth formation, comprising; first and second electroacoustic transducer means carried by a logging sonde; control means operable to control the transducer means to transmit and receive acoustic pulses along upstream and downstream paths through the fluid; signal means connected to the transducer means to provide travel time signals representative of the travel times of a pulse along said upstream and downstream paths between said first and second transducer means; and deriving means connected to the signal means to derive a signal representative of the velocity of the fluid in accordance with said travel time signals. The present invention is characterised in that: said first and second transducer means are each adapted both to transmit and to receive acoustic pulses; said control means is operable to control the transducer means so that during a first measurement step the first transducer transmits a pulse and the second transducer receives a pulse that has passed through the fluid and so that during a second measurement step the second transducer transmits a pulse and the first transducer receives a pulse that has passed through the fluid; caliper means is provided for measuring the diameter of the borehole and providing a signal representative of the measured diameter; and wherein said deriving means derives a signal representative of the volume flow rate of the fluid at the present position of the sonde in the borehole in accordance with said travel time signals and said diameter signal at that position. US-A-4,905,203 describes, per se, caliper means for measuring the diameter of the borehole and providing a signal representative of the measured diameter, and deriving means which derives a signal representative of the volume flow rate of the fluid in accordance with travel time signals and said diameter signal, the travel time signals originating from a Doppler frequency electroacoustic transducer arrangement. Embodiments of the present invention will now be described, by way of example, with reference to the accompanying drawings, in which: Figure 1 is a graphical representation of a well logging sonde for use in a logging system according to the invention, and shown in a borehole; Figure 2 is a simplified block diagram of the well logging system; and Figure 3 is a graphical representation of a second embodiment of well logging sonde, for use in a logging system according to the invention, and shown in a borehole. With reference to Figures 1 and 2 there is shown a borehole 5 traversing an earth formation 10 having fluid flowing upward containing particles or droplets of a different fluid 14. A conventional well logging sonde 18 contains a conventional type transducer, which is an ultrasonic crystal 23. Electronics 29 provide electrical pulses to transmitter crystal 23, as hereinafter explained, to provide acoustical pulses into the fluid flow. The acoustical pulses pass through the fluid containing particles 14 and impinge upon another transducer, which is a crystal 33, mounted on an arm 36. Arm 36 is initially closed and forms part of sonde 18 as sonde 18 is lowered into and removed from borehole 5. Actuator means 40 is controlled by signals as hereinafter explained to either extend the actuator arm 36 for measurement purposes or to bring it into an initial position for movement of sonde 18 through the borehole. As explained hereinafter during a measurement, the roles of crystals 23, 33 are reversed. Crystal 23 or 33 provides electrical pulses back to electronics 29 in accordance with the received acoustical pulses. Electronics 29 processes the signal from crystal 23 or 33 and provides a travel-time signal in accordance therewith. A conventional caliper log means 43 has pads 45 and 46 urged against the wall of borehole 5, by arms 47 and 48, respectively, so as to centralize sonde 18 in borehole 5. Caliper means 43 also provides a signal representative of the diameter of borehole 5 in accordance with the positioning of pads 45 and 46. Electronics 29 includes a pulse source 52 connected to switching means 54 and to cable means 56 and receiving a signal from cable means 56 to provide a pulse to switching means 54. Switching means 54 is also connected to crystals 23, 33 and to cable means 56. Switching means 54 is controlled by a control signal from cable means 56 during one part of a measurement to provide the pulse from pulse source 52 to crystal 23 and during another part of the measure to provide the pulse from pulse source 52 to crystal 33. Pulse source 52 also provides a pulse to a set input of a flip-flop 60. Flip-flop 60 has its clear input connected to switching means 54 which provides an electrical pulse corresponding to the first arrival signal from crystal 33 to flip-flop 60 during the one part of the measurement and a similarly-derived signal from crystal 23 during the other part of the measurement. An output of flip-flop 60 is provided to an AND gate 64 which also receives timing pulses from a clock 69. AND gate 64 provides its output to cable means 56. The output of AND gate 64 will correspond to the transit time for the acoustical pulse to be transmitted from crystal 23 or 33 through the water to crystal 33 or 23. This is accomplished by pulse source 52 providing a pulse to the input of flip-flop 60, triggering flip-flop 60 to a set state thereby causing flip-flop 60 to provide an enabling signal to AND gate 64. The enabling signal causes AND gate 64 to pass the timing pulses from clock 69 to cable means 56. Clock 69 is tied to microprocessor 80 by providing pulses to cable means 56 so as to provide synchronized timing of the system. When crystal 23 or 33 receives an acoustical pulse, it provides an electrical pulse, by way of switching means 54, to the clear input of flip-flop 60 triggering flip-flop 60 to its clear state thereby terminating the enabling signal. The termination of the enabling signal causes AND gate 64 to block the timing pulses from clock 69. Therefore the timing pulses passed by AND gate 64 represent the time of travel of the acoustical pulse from one crystal 23 or 33 to the other crystal 33 or 23. Cable means 56 provides the passed timing pulses uphole to microprocessor means 80. Cable means 56 also provides the signal from caliper log means 43 uphole to microprocessor means 80. Microprocessor means 80 provides signals to cable means 56 for triggering pulse source 52, and for controlling actuator means 40 and switching means 54. It should be noted that the time between triggering of pulse source 52 should be sufficient to allow any ringing of crystal 33 or 23 by acoustical pulses to have died down so that the next transit time measurement is not inadvertently terminated early by a ringing from the previous part of the measurement. Thus, microprocessor means 80 will receive pulses corresponding to two travel times for each measurement. The equations for the two travel times are given below: t₁ = d / ( c + v cosϑ) (1) t₂ = d / ( c - v cosϑ) (2) where t₁ = travel time from the crystal 23 to crystal 33 t₂ = travel time from crystal 33 to crystal 23 c+ v cosϑ = velocity traveling with the flow c - v cosϑ = velocity traveling against the flow c = velocity of sound in the fluid v = velocity of the fluid ϑ = angle between the transmitted pulse and the sonde 18 axis d = path distance between crystals 23 and 33. Subtracting Eq (1) from Eq (2) yields: t₂ - t₁ = 2 d v cosϑ / (c² - v²cos²ϑ) (3) Since c²>> v²cos²ϑ, Eq (3) can be reduced to: t₂ - t₁ = 2 d v cosϑ / c² or v = c²( t₂ - t₁ ) / ( 2 d cosϑ) (4) Another equation relating fluid velocity to the travel times can be obtained which is independent of c, the velocity of sound in the fluid. Taking the reciprocal of Eq (1) and (2) gives 1/t₁ = (c + v cosϑ) / d (5) 1/t₂ = (c - v cosϑ) / d (6) Subtracting Eq (6) from (5) yields 1/t₁ - 1/t₂ = 2 v cosϑ / d (7) Solving Eq (7) for v v = ( d / 2 cosϑ ) (1/t₁ - 1/t₂) (8) Calibration of the system may be accomplished prior to logging in a flow loop or during logging by running at several different cable speeds. The calibrated fluid velocity will be exact if the tool is run stationary. During a logging run where the tool is moving upwards, the actual fluid velocity will be the indicated velocity minus the velocity of the cable. The flow rate can be determined from the velocity measurement by the following equation: FR = 1.4 (D²-s²) v where FR = flow rate in barrels per day (one barrel = 159 liters), D = diameter of the casing or borehole in inches (one inch = 2,54 cm), s = diameter of the tool in inches (one inch = 2,54 cm), v = fluid velocity in ft/min (one foot = 30,5 cm), and 1.4 = unit conversion constant. The diameter of the borehole or the casing is obtained from a caliper log means 43. The diameter of the sonde 18 is standard 4,3 cm (1 11/16 inches). In another embodiment shown in Figure 3, arm 36 is eliminated as is actuator means 40. Crystals 23 and 33 are positioned so that the acoustical pulses reflect off the walls of borehole 5 and sonde 18 until they impinge on one of the crystals 23 or 33. The operation of this embodiment is essentially the same as the first embodiment.

Claims: A well logging system for monitoring the flow of a fluid in a borehole traversing an earth formation, comprising; first and second electroacoustic transducer means (23,33) carried by a logging sonde (18); control means (52,54) operable to control the transducer means to transmit and receive acoustic pulses along upstream and downstream paths through the fluid; signal means (60,64,69) connected to the transducer means to provide travel time signals representative of the travel times of a pulse along said upstream and downstream paths between said first and second transducer means; and deriving means (80) connected to the signal means to derive a signal representative of the velocity of the fluid in accordance with said travel time signals; characterised in that: said first and second transducer means (23,33) are each adapted both to transmit and to receive acoustic pulses; said control means (52,54) is operable to control the transducer means so that during a first measurement step the first transducer (23) transmits a pulse and the second transducer (33) receives a pulse that has passed through the fluid and so that during a second measurement step the second transducer (33) transmits a pulse and the first transducer (23) receives a pulse that has passed through the fluid; caliper means (43) is provided for measuring the diameter of the borehole and providing a signal representative of the measured diameter; and wherein said deriving means (80) derives a signal representative of the volume flow rate of the fluid at the present position of the sonde in the borehole in accordance with said travel time signals and said diameter signal at that position. A system according to Claim 1 characterised in that said control means (52,54) includes: a pulse source (52) for providing pulses for transmission by a said transducer (23,33) in response to a first control signal; and switch means (54) responsive to a second control signal to pass the pulses for transmission by the first transducer and to pass electrical pulse signals representative of received pulses at the second transducer to the signal means (60,64,69) during said first measurement step, and to pass the pulses for transmission by the second transducer and to pass electrical pulse signals representative of received pulses at the first transducer to the signal means (60,64,69) during said second measurement step. A system according to claim 2 characterized in that said signal means (60,64,69) comprises: a clock (69) to provide timing pulses; enabling means (60) connected to said pulse source (52) and to said switch means (54) to provide an enabling signal for each said measurement step in accordance with pulses from said pulse source and said switch means; and gate means (64) for passing said timing pulses to the deriving means (80) in accordance with said enabling signals, whereby to provide the travel time signals. A system according to any one of claims 1 to 3 characterized in that said deriving means (80) derives the velocity of the fluid in accordance with the travel time signals and the following equation: v = ( d / 2 cos ϑ ) (1/t₁ - 1/t₂) where t₁ is the travel time of an acoustic pulse from the first transducer to the second transducer, t₂ is the travel time of an acoustic pulse from the second transducer to the first transducer, d is the path distance between the first and second transducers and ϑ is the angle between the transmitted pulse and the sonde axis. A system according to any one of claims 1 to 4 characterized in that said deriving means (80) derives the flow rate of the fluid in accordance with the travel time signals, the diameter signal and the following equation: FR = 1.4 (D² - s²) v where FR is the flow rate in barrels per day (one barrel = 159 liters), D is the diameter of the casing or borehole in inches (one inch = 2.54 cms.), s is the diameter of the sonde in inches, v is the fluid velocity in feet per minute (one foot = 30.5 cms.), and 1.4 is the unit conversion constant. A system according to any one of claims 1 to 5 characterized by means (36) for extending one of said transducers (33) outside said sonde (18) so that there is a direct acoustic pulse path between said transducers. A system according to any one of claims 1 to 5 characterized in that said transducers (23,33) are disposed so that there is an indirect acoustic pulse path therebetween. A system according to any one of claims 1 to 7 characterized in that said logging sonde (18) is connected by a cable (56) to electronic means at the surface, said sonde (18) housing said transducer means (23,33), said control means (52,54), said caliper means (43) and said signal means (60,64,69), and said electronic means including said deriving means (80) and control signal generating means to generate control signals and to pass them down said cable (56) to said control means (52,54) in the sonde.

Inventors: SIMS JACKIE CHARLES, SUPERNAW IRWIN RAY, SIMS, JACKIE CHARLES, SUPERNAW, IRWIN RAY
Applicants: TEXACO DEVELOPMENT CORP, TEXACO DEVELOPMENT CORPORATION
Application year: 1990
Main classification: E21B47
IPC codes: E21B47, G01F1