Various embodiments described herein relate to electromagnetic telemetry systems and methods including apparatus, systems, and methods for detecting faults in oil field electromagnetic telemetry systems.

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During drilling and extraction operations of hydrocarbons, a variety of communication and transmission techniques have been attempted for data communications between the surface of the earth and the downhole tools. The data communications from the downhole tool to the surface may be used to provide information related to the evaluation of the formation, control of the drilling operations, etc. However, drilling, exploration, and extraction occur in remote and hostile conditions are hostile to electronic equipment and electronic communications. In some field communication schemes the signal will have significant power and if the communication channel is interrupted, then the power may cause arcing or other electromagnetic events that may be dangerous in view of the hydrocarbon extraction environment. This type of environment may be classified as a “hazardous” environment according to safety regulation authorities. See, e.g., The Dangerous Substances and Explosive Atmospheres Regulations 2002 (DSEAR) and Explosive Atmospheres Directive 99/92/EC (ATEX 137) which are enforced by the various government organizations, e.g., Petroleum Licensing Authorities, in Europe, or Underwriters Labs, National Electrical Code 500 and Canadian Services Association in North America. As a result there is a need to monitor the integrity of electronic communications between downhole and surface communication devices.

FIG. 1 is a schematic diagram of an apparatus according to various embodiments of the invention;

FIG. 2 is a schematic view according to various embodiments of the invention;

FIG. 3 is a more detailed view according to various embodiments of the invention;

FIG. 4 is a view of connections to a blowout preventer according to an embodiment of the invention;

FIG. 5 is a graph showing a fault zone according to an embodiment of the invention;

FIG. 6 is a flow chart illustrating a method according to various embodiments of the invention; and

FIG. 7 is a waveform captured according to an embodiment of the invention.

FIG. 1 illustrates a system 100 for the exploration, drilling, and extraction of hydrocarbons. An exploration/extraction rig structure 101 is in communication with electronics equipment 102 that in turn is in electrical communication with a grounding structure 104. In an embodiment, the electrical equipment 102 is remotely positioned relative to the rig 101 and connected by a communication line 106, such as a cable or wire. The communication line 106 may be a double core cable that has two separate signaling paths in a single construction. The communication line 106 may be a plurality of separate, parallel signaling paths in separate lines of cables. A further communication line 108, such as a cable or wire, connects the electronics equipment 102 to the grounding structure 104. Line 108 may also be a multiple core line or a plurality of single core lines. The grounding structure 104 may be a stake embedded in the earth 110. The electronics equipment is positioned remote from the rig 101 to protect the electronics 102 from the harsh conditions of the rig site and protect the electronics 102 from damage while the rig is forming, drilling, or in other rig operations. Moreover, the electronics 102 can be mounted in a mobile platform and brought to a well site as needed. The electronics 102 may communicate with downhole devices and may be a logging facility for storage, processing, and analysis. Such a facility may be provided with electronic equipment 102 for various types of signal processing. Similar log data may be gathered and analyzed during drilling operations (e.g., during logging while drilling, measurement while drilling, seismic while drilling operations). That is, any data acquired downhole is sent to the surface via telemetry for use by the electronics 102. The term “telemetry” is used in the hydrocarbon extraction art to define a method of transmitting information from the downhole to the surface. Telemetry can be achieved by many means, for example, “hardwire,” where the signal is passed along a conducting medium via electrical means and to which the downhole tool is in communication and/or attached.

Rig structure 101 includes rig support frame or derrick 115 located on a platform 116 at a surface of earth 110 of a well or subsurface formation 117. Frame 115 provides support for downhole structures such as a drill string 119 and/or a logging device 150. A drill string 119 may operate through surface level metal work such as a blowout preventer 120 to penetrate a rotary table 121 for drilling a borehole 122 through subsurface formations 124. The drill string 119 may include a Kelly 126, drill pipe 128, and a bottom hole assembly 130, perhaps located at the lower portion of the drill pipe 128. The bottom hole assembly 130 may include drill collars 132, a downhole tool 134, and a drill bit 136.

The drill bit 136 may operate to create a borehole 122 by penetrating the earth surface 110 and subsurface formations 124. The downhole tool 134 may comprise any of a number of different types of tools 135 including MWD (measurement while drilling) tools, LWD (logging while drilling) tools, seismic while drilling, magnetic resonance image logging (MRIL), and others. During drilling operations, the drill string 119 may be rotated by rotary table 121. In addition to, or alternatively, the bottom hole assembly 130 may also be rotated by a motor (e.g., a mud motor) that is located downhole. The drill collars 132 may be used to add weight to the drill bit 136. The drill collars 132 also may stiffen the bottom hole assembly 130 to allow the bottom hole assembly 130 to transfer the added weight to the drill bit 136, and in turn, assist the drill bit 136 in penetrating the surface 110 and subsurface formations 124.

During drilling operations, a mud pump 142 may pump drilling fluid (sometimes known as “drilling mud”) from a mud pit 144 through a hose 146 into the drill pipe 128 and down to the drill bit 136. The drilling fluid can flow out from the drill bit 136 and be returned to the surface 110 through an annular area 140 between the drill pipe 128 and the sides of the borehole 122. The drilling fluid may then be returned to the mud pit 144, where such fluid is filtered. In some embodiments, the drilling fluid can be used to cool the drill bit 136, as well as to provide lubrication for the drill bit 136 during drilling operations. Additionally, the drilling fluid may be used to remove subsurface formation 124 cuttings created by operating the drill bit 136.

In another embodiment, the rig structure 101 is positioned over a borehole 122, which has been drilled or formed, to support a tool body 150 as part of a logging operation. Here it is assumed that the drilling string has been at least temporarily removed from the borehole 122 to allow logging tool body 150, which includes an information gathering, downhole tool 134, such as a probe or sonde, to be lowered by cable, wireline or logging cable 154 into the borehole 122. Typically, the tool body 150 is lowered to the bottom of the region of interest and subsequently pulled upward at a substantially constant speed. During the upward trip, instrument tool 134 included in the tool body 150 may be used to perform measurements on the subsurface formations adjacent the borehole as the tools pass by. In an embodiment the tool body communicates with the surface electronics 102 via a communication line, such as casing pipe 160, blowout preventer 120, and line 106.

It should also be understood that the apparatus and systems of various embodiments can be used in applications other than for drilling and logging operations, and thus, various embodiments are not to be so limited. The illustration of system 100 is intended to provide a general understanding of the structure of various embodiments, and they are not intended to serve as a complete description of all the elements and features of apparatus and systems that might make use of the structures described herein.

In operation the electronics 102 communicates via electromagnetic telemetry with downhole devices, such as those described in FIG. 1 but embodiments of the present invention are not limited to only those specifically described, using power electronics to deliver a signal via line 106 to the metal work extending downhole. The metal work in an example include the drill string 119. In a further example, the metal work includes the casing pipes 160 or other tubes extending below ground. The electronics may produce a carrier signal on which data is carried for example via modulation techniques. Examples of downhole telemetry are discussed in “Electric Drill Stem Telemetry” by J. Bhagwan and F. N. Trofimenkoff, IEEE Transactions on Geoscience and Remote Sensing, Vol. GE-20, No. 2, April 1982; “Propagation of electromagnetic Waves Along a Drillstring of Finite Conductivity” P. DeGauque and R. Grudzinski, SPE Drilling Engineering, June 1987; “Electromagnetic Basis of Drill-Rod Telemetry” by D. A. Hill and J. R. Wait, Electron. Letters Vol. 14, pages 532-533; and “Theory of Transmission of electromagnetic Waves Along a Drill Rod in Conducting Rock”, J. R. Wait and D. A. Hill, IEEE Transactions on Geoscience Electronics, Vol. GE-17, No. 2, April 1979. Each of these documents are hereby incorporated by reference for any purpose. The signal travels through the line 106 and metal work below ground where it is received by downhole tools 135. The downhole tools 135 may also transmit data created during hydrocarbon exploration and extraction activities though the downhole metal work to the surface electronics 102. In an example, the signal is a low frequency analog signal such that the signal can travel the length of the downhole metal work to reach a downhole tool. In an example, the signal is a sinusoidal signal having a frequency in a range of just over 0 Hz to about 250 kHz. However, such a low frequency signal would still require significant power from about 1 kilowatt and up. In an embodiment the power of the signal is about 2.0 kilowatts or higher. In an embodiment, the power is on a range up to 15. kilowatt. Moreover, the signal would be modulated using at least one of quantum phase shift key, pulse width modulation, amplitude modulation and pulse position modulation as a data encoding scheme. Other types of modulation may be used to enhance the bit rate of the communication.

In view of these types of signals and, in particular, the signal power, a dangerous condition may occur if the communication channel, for example, cable 106, or downhole metal such as drill string 119, or casing pipe 160 is damaged, disconnected or disturbed. This may generate an electrical signal such as a spark that may ignite potentially explosive gases in addition to the risk of electrical shock or electrocution to attendant personnel.

FIG. 2 shows a schematic view of an embodiment of the present invention with the electronics 102 connected to the blowout preventor 120, which is connected to the downhole metal work 201. The electronics includes a host system 205 that controls a power source 207, which are both in communication with a signal integrity monitor 210. The host system 205 may include electronic circuitry used in high-speed computers, communication and signal processing circuitry, modems, processor modules, embedded processors, data switches, and application-specific modules, including multilayer, multi-chip modules. Such apparatus and systems may further be included as sub-components within a variety of electronic systems, such as displays, televisions, personal computers, workstations, vehicles, and conducting cables for a variety of electrical devices, among others. Power source 207 provides the power for the signal that is created by the host system 205 and is conducted to the hole site whereat the signal is communicated downhole to downhole tools. In an embodiment, the power source 207 is an analog power amplifier that outputs a signal in up to about 250 kHz with a root mean power of up to 2 kilowatts or higher. In an embodiment, the amplifier outputs a signal of about 1.8 kilowatts. In an embodiment, the power source is similar to an AC audio amplifier for audio listening equipment. In a further embodiment, the power source is a DC amplifier.

The cable signal integrity monitor 210 is connected through physical lines 106 to the host system 205, power source 207, and blowout preventor 120. The lines 106 provide wired communication between these devices. Lines 106 may be housed in a single insulation, for example, coaxially. The lines 106 are adapted to provide a signal path for AC communication signals in the well site environment. The lines 106 are insulated and hardened to prevent damage thereto in this environment. However, the lines may still become damaged in this environment, for example, by workers using tools or other heavy equipment. The monitor 210 senses signals in the lines 106. Based on the sensed signals, the monitor 210 either maintains the steady state, which allows electrical communication in the system, or will disconnect the power source from the communication system in an attempt to minimize stray electrical power in the event of a fault. It is also desirable to minimize false fault detection. Turning off the power will minimize the likelihood that the electrical power, which is needed for metal work communication with downhole equipment, will cause a hazardous situation such as electrical shock or ignition of gases. The cable integrity monitor 210 includes electrical signal detectors. In an embodiment, the monitor includes a resistance sensor to sense a change in resistance in the communication path. In an embodiment, the monitor 210 includes a voltage sensor to sense a change in voltage in the signals in the communication path. In an embodiment, the monitor 210 includes a current sensor to sense a change in current in the communication path. One example of a current sensor includes a current sense amplifier connected to the communication lines 106. The current sense amplifier may include a comparator to compare the sensed signal to a reference signal that represents the signal produced by the host system 205. In an embodiment, the current sense amplifier includes two internal comparators to produce a pulse-width output signal proportional to the current being sensed. In an embodiment, the current sensor includes a hall effect sensor that operated on a non-contact basis by measuring the change in the magnetic field produced by signals in the lines 106.

FIG. 3 shows an embodiment of the monitor 210 with connections to the power source 207, host system 205, and blowout preventor 120. In the illustrated embodiment, the communication connections 106 are shown as multiple wires, i.e., two wire connections. However, it will be recognized that a single wire may be used. Monitor 210 includes a safety manager circuit and safe mode driver 301 that is in direct connection with the host system 205. Driver 301 may be implemented as a circuit. In an embodiment, the driver 301 is a software module operating in a processor/memory device. The driver 301 receives a modulated signal from the host system 205 and transmits the signal to the power amplifier 207 over connection 306. Driver 301 further sends an on/off signal over connection 307 to the amplifier 207 to control the state of the amplifier 207. Power amplifier 207 is in an on or off state depending on the signal from the driver 301. The amplifier 307 outputs and amplified signal on connection 106 to inputs of a sensor circuit 310. The sensor circuit determines the integrity of the signal path and further toggles the amplifier to off as well as feedbacks to the host system 205.

The sensor circuit 310 in the illustrated embodiment is a Wheatstone bridge. The bridge has a first input 311 connected to one of the lines 106 and a second input 312 connected to a second of the lines 106. The bridge includes a circuit to determine a reference signal, which includes a first leg 316 in series with a second leg 317. The bridge further includes a second circuit to determine a sense signal, which includes a third leg 318 and a fourth leg 319. Each of legs 316-319 has a predetermined impedance. In an embodiment, each of the legs 316-319 have a known resistance. First leg 316 is between the first input 311 and a reference output 320. Second leg 317 is between the reference output 320 and the second input 312. Third leg 318 is between the first input and the sensed output 321. Fourth leg 319 is between the sensed output 321 and the second input 312. In one embodiment, the third leg includes an electrical line extending from the first input to a relay switch 330. The relay 330 is a circuit breaker in an embodiment. The third leg 318 further includes an electrical line 331 extending from the relay. This electrical line 331 covers essentially the entirety of the distance from the electronics to the well site. In an embodiment, this distance is tens of meters. In an embodiment, this distance is up to about 100 meters. In an embodiment, the length is up to about 125 meters. In yet other embodiments, the length can be equal to or greater than 1,000 meters. That is the length of lines 106, 331 are up to or greater than 1 kilometer. The line 331 is connected to the blowout preventor 120. In an embodiment, line 331 is clamped to an arm of the blowout preventor 120. Adjacent the blowout preventor 120 and distal to the monitor 210, leg 318 includes a known resistance, which is connected to a line 332 that returns to the relay 330 and connects to the sensed output 321. In an embodiment, the lines 331, 332 are housed in a single insulator, dual core cable. In a further embodiment, the lines 331, 332 are in a braided cable. In an embodiment, the lines 331, 332 are separate lines. The reference signal at 320 and the sensed signal 321 are each fed to a comparator 340. Comparator 340 is a ratiometric window comparator. The comparator 340 compares the reference signal to the sensed signal. If there is a certain deviation of the sensed signal from the reference signal, then comparator 340 outputs a signal to the driver 301. Driver 301 then opens the normally closed relay 330 to disconnect the power amplifier 207 from the third leg 318, and hence, the well site. The driver 310 further turns off amplifier 207. Driver 310 signals host system 205 that the communication with the equipment at the well site is down. Additional data related to the shut down can be stored by the host system 205.

It is recognized that the cable 106 is connected to a metal work such as a blowout preventor in the illustrated embodiment. However the invention is not so limited and may be connected to metal work at the surface known to those in the field of wells. The surface level metal work 120 may include one of a pump jack, a nodding donkey or a horsehead pump. In an embodiment, the cable 106 is connected to a conductive stake at the bore hole. In an embodiment, the cable 106 is connected to a pipeline service station. In an embodiment, the cable 106 extends from an offshore platform down to metal work at the borehole.

FIG. 4 shows an embodiment of the connection from the signal monitor 210 to the well site. The signal monitor 310 is electrically connected to the lines 331, 332. Line 331 delivers the modulated power signal that contains the data to be transmitted downhole through the downhole metal work. Line 331 is connected to one side of the blowout preventor 120 by a clamp 402. Line 332 is connected to another side of blowout preventor 120 by a clamp 403. It will be understood that each of lines 331 and 332 could be connected to a single one of clamps 402, 403 in an embodiment. Signals arrive through powered line 331 and enter the blowout preventor 120, which in turn transmits that electrical signal to the downhole metal work 201. Return line 332 feeds the powered signal back through an impedance (e.g., a set sense resistance), to the monitor 210. The set sense resistance is housed such that it is proximal to the well site and protected from the elements and accidental damage.

FIG. 5 shows a graphical representation of an acceptable waveform to provide cable or connection fault detection. The reference signal 401 is shown as a sinusoidal signal in which data is embedded. As the reference signal 401 travels a sinusoidal pattern, an upper threshold limit 402 and a lower threshold limit 403 is determined as a percentage of the reference signal. In an embodiment, the reference signal is a reference voltage. The sensed signal at output 321 is compared to the reference signal, which is at output 320. If the sensed signal exceeds the upper threshold 402 or falls below the lower threshold 403, then a fault is detected. The driver 301 trips the relay and turns off the power amplifier 207.

FIG. 6 is a flow chart illustrating a method 600 of an embodiment of the present invention. A data signal is produced, 601, which includes a carrier signal that is modulated to include data. The data signal typically does not have sufficient power to transmit through downhole metal work to subsurface tools. The data signal is then amplified, 603, remote of the well site. The amplified signal is delivered to the downhole metal structures, 605, such as drill strings or casing. A portion of the amplified signal is fed back to the location remote of the well site, 607. The amplified data signal is sampled, 609. The feed back signal is sampled, 611. In an embodiment, the sample signals are analog and, hence, the sampling is performed at an analog circuit, such as a bridge circuit. In an embodiment, the sampled signals are digitally sampled. In a further embodiment, the sampling is performed at an analog circuit, such as bridge. The sampled signals are compared, 613. This comparison is done in the digital domain when digitally sampled or using an analog comparator circuit if in an analog domain. If the sampled signals are within a range or threshold 615, then the method continues, i.e., returns to step 601. However, many of these steps can occur simultaneously. If the comparison shows that the feedback signal deviates from the reference amplified signal outside the threshold, then the power amplifier is disconnected from communication with the well site, 617. The amplifier is also turned off based on the comparison, 619.

FIG. 7 shows a data graph that illustrates the operation of the presently described structures, apparatus and methods. Waveform 701 shows an output waveform, which is a portion of sine wave that is applied at the well site. In an embodiment, the signal is a 30 volt peek to peek, 11.5 Hz signal. Waveform 702 represents the signal over the third leg of the bridge, sensing circuit. Waveform 703 represents the output from the comparator. Waveform 704 represents a fault latch signal in the driver. A brief description of the operation follows. At time t0 a short circuit trip occurs, see waveform 702. A short circuit fault may occur when the power line 331 and the sense line 332 are electrically connected together other than through the metal work 120. This can occur when a cable that includes the power and sense lines 331, 332 is squashed together or otherwise damaged. The value at leg 318 goes to a low impedance value. In an example, the leg 318 goes to a low impedance at time t1 as shown in FIG. 7. The bridge circuit 310 goes imbalanced, which causes the comparator to generate a fault signal. Returning to FIG. 7, at time t1, the fault is detected in the signal monitor 210, see waveform 703. The fault is latched in the monitor 210, see waveform 704. The driver 301 trips, i.e., opens the normally closed, relay 330. The electrical power at the well site is no longer powered by the electronics based on the open relay. The power at the well site begins to decay at time t1. The time period between t0 and t1 is less than one millisecond. In an embodiment, the time period between the short and the sensing of the short is about 800 microseconds. The power at the well site decays rapidly to about 20% of its power at t1 by time t2. The power in signal 701 begins to decay before the power amplifier is turned off. At time t3, the fault detector signal 703 returns to a no-fault state. However, the fault state is latched in waveform 704, which will not allow the communication through relay 330 to reset without resetting the fault latch. The fault latch is reset after personnel inspect the communication system including all lines, wires, cables, and connections. As shown in this embodiment, the fault signal is a digital signal.

The present system 100 may further detect an open circuit fault, which will generate similar waveforms. An open circuit fault is where the Rsense portion of leg 318 is no longer connected to the bridge 310. In an embodiment, the leg 318 is not electrically connected to the remainder of the bridge. The bridge 310 will become imbalanced and signal the comparator. The comparator will signal the driver 301 that a fault has occurred. More specifically, waveform 703 will show a fault. Waveform 704 will latch the fault. Waveform 701 will decay shortly after the fault is detected.

The present description refers to on shore structures examples. It will be recognized that the embodiments of the present invention are adaptable to monitor the integrity of offshore cables.

It should be noted that the methods described herein do not have to be executed in the order described, or in any particular order. Moreover, various activities described with respect to the methods identified herein can be executed in iterative, serial, or parallel fashion. Information, including parameters, commands, operands, and other data, can be sent and received in the form of one or more carrier waves.

The accompanying drawings that form a part hereof, show by way of illustration, and not of limitation, specific embodiments in which the subject matter may be practiced. The embodiments illustrated are described in sufficient detail to enable those skilled in the art to practice the teachings disclosed herein. Other embodiments may be utilized and derived therefrom, such that structural and logical substitutions and changes may be made without departing from the scope of this disclosure. This Detailed Description, therefore, is not to be taken in a limiting sense, and the scope of various embodiments is defined only by the appended claims, along with the full range of equivalents to which such claims are entitled.

Such embodiments of the inventive subject matter may be referred to herein, individually and/or collectively, by the term “invention” merely for convenience and without intending to voluntarily limit the scope of this application to any single invention or inventive concept if more than one is in fact disclosed. Thus, although specific embodiments have been illustrated and described herein, it should be appreciated that any arrangement calculated to achieve the same purpose may be substituted for the specific embodiments shown. This disclosure is intended to cover any and all adaptations or variations of various embodiments. Combinations of the above embodiments, and other embodiments not specifically described herein, will be apparent to those of skill in the art upon reviewing the above description.

The Abstract of the Disclosure is provided to comply with 37 C.F.R. §1.72(b), requiring an abstract that will allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims. In addition, in the foregoing Detailed Description, it can be seen that various features are grouped together in a single embodiment for the purpose of streamlining the disclosure. This method of disclosure is not to be interpreted as reflecting an intention that the claimed embodiments require more features than are expressly recited in each claim. Rather, as the following claims reflect, inventive subject matter lies in less than all features of a single disclosed embodiment. Thus the following claims are hereby incorporated into the Detailed Description, with each claim standing on its own as a separate embodiment.

1. Field of the Invention

The present invention generally relates to devices and methods for measuring fluid density and other fluid flow properties in a flow stream, where fluid is taken to mean any liquid, gas, or mixture thereof, including those which contain solids. More particularly, the present invention relates to a high accuracy density and viscosity measurement device suitable for use in a high-temperature, high-pressure, high-shock environment such as may be encountered in a wellbore.

2. Description of the Related Art

There are many instances in industrial processes and controls for handling flowing fluids where the density of the moving fluid has to be determined accurately. One particular application is in the identification of reservoir fluids flowing in a well. Water often co-exists with crude oil in some common geologic formations. As such, both substances are often pumped up together by a working oil well and the water is ultimately separated from the crude oil at a downstream location. It is desirable to determine the amount of oil that occurs in an oil-water stream flowing from a formation. To accurately determine the amount of crude oil extracted from a formation, a “net oil computer” may be used to ascertain the amount of crude oil. The “net oil computer” determines the total volume flow rate of the flow stream and calculates the flow stream's oil percentage (based on density measurements) to determine the net amount of oil that emanates from the formation. Given the large quantities of crude oil that are usually involved, any small inaccuracies in measuring density can disadvantageously accumulate over a relatively short interval of time to become a large error in a totalized volumetric measure.

Another particular application of density measurement is to determine the mass flow rate of a fluid medium. Mass flow rate can be calculated as a product of a fluid density (determined by a density meter) and a volume flow rate of the fluid (measured by a volumetric flowmeter). There are mass flowmeters available at the present time such as the Coriolis force or convective inertia force mass flowmeters and thermal probe mass flowmeters. These types of mass flowmeters, while they function excellently in the mass flow measurement of low viscosity fluids, work poorly in measuring flows of highly viscous fluids. The fluid's viscosity introduces error in the data acquisition for the mass flow rate. One of the more promising approaches to measurement of the mass flow rate is to combine an accurate density meter and a reliable positive displacement volumetric flowmeter. This combination is particularly effective in measuring mass flow rates of highly viscous fluids or mixtures of fluids and gasses.

Coriolis mass flow meters can be used to measure the density of an unknown process fluid. In general, as taught, for example, in U.S. Pat. No. 4,491,025, a Coriolis meter can contain two parallel conduits, each typically being a U-shaped flow tube. Each flow tube is driven such that it oscillates about an axis. As the process fluid flows through each oscillating flow tube, movement of the fluid produces reactionary Coriolis forces that are perpendicularly oriented to the plane of the fluid's angular velocity in the tube. These reactionary Coriolis forces cause each tube to twist about a torsional axis that, for U-shaped flow tubes, is normal to its bending axis. The net effect is a slight deformation and deflection of the conduit proportional to the mass flow rate of the fluid. This deformation is normally measured as a small difference between the deflection at the inlet ends of the conduits compared to the deflection at the outlet ends. Both tubes are oppositely driven such that each tube behaves as a separate tine of a tuning fork and thereby advantageously cancels any undesirable vibrations that might otherwise mask the Coriolis forces. The resonant frequency at which each flow tube oscillates depends upon its total mass, i.e. the mass of the empty tube itself plus the mass of the fluid flowing therethrough. Inasmuch as the total mass will vary as the density of the fluid flowing through the tube varies, the resonant frequency will likewise vary with any changes in density.

As specifically taught in U.S. Pat. No. 4,491,009, the density of an unknown fluid flowing through an oscillating flow tube is proportional to the square of the period at which the tube resonates. While the circuit taught in this patent may provide accurate density measurements, it unfortunately possesses several drawbacks. First, for certain application, density measurements to an accuracy of one part in 10,000 are necessary. An accuracy of this magnitude is generally not available through an analog circuit unless highly precise analog components are used. Such components are quite expensive. Second, the analog circuit disclosed in this patent cannot be independently calibrated to compensate for changing characteristics of the electronic components—such as offset, drift, aging and the like. Specifically, this circuit is calibrated on a “lumped” basis, i.e. by first passing a known fluid, such as water, through the meter and then adjusting the circuit to provide the proper density reading at its output. This process compensates for any errors that occur at the time of calibration that are attributable either to physical errors in measuring density using a Coriolis mass flow meter or to errors generated by the changing characteristics of the electrical components themselves. Unfortunately, after the circuit has been calibrated in this fashion, component characteristics will subsequently change over time and thereby inject errors into the density readings produced by the circuit. This, in turn, will eventually necessitate an entire re-calibration.

All densitometers are generally calibrated using a calibration fluid having a known density. This density is specified at a certain temperature. Unfortunately, the density of most fluids varies with temperature; some fluids exhibit a significant variation, while other fluids exhibit relatively little variation. Consequently, many currently available densitometers require that the temperature of the calibration fluid must be carefully controlled before the fluid is injected into the densitometer for calibration. This necessitates that the container holding the fluid must be placed in a temperature bath for a sufficiently long period of time so that the fluid will stabilize to a desired temperature. In addition, provisions must be made to ensure that the temperature of the fluid will not change as the fluid is pumped through the meter. Accurately controlling the temperature of a fluid and then accurately maintaining its temperature, while the fluid is being pumped through the meter, is both a costly and tedious process.

It may be appreciated from the foregoing that a need exists in the art for a high-accuracy densitometer which is capable of operation under the high temperature, pressure, shock and vibration conditions encountered in a wellbore; which uses relatively inexpensive components; which substantially eliminates any error caused by changing characteristics of any of the electronic components; and which effectively eliminates the errors associated with the effects of temperature and pressure on the system.

Accordingly, there is disclosed herein a measurement device for determining fluid properties from vibration frequencies of a sample cavity and a reference cavity. In one embodiment, the measurement device includes a sample flow tube, a reference flow tube, vibration sources and detectors mounted on the tubes, and a measurement module. The sample flow tube receives a flow of sample fluid for characterization. The reference flow tube is filled with a reference fluid having well-characterized properties. The reference flow tube may be pressure balanced to the same pressure as the sample. The measurement module employs the vibration sources to generate vibrations in both tubes. The measurement module combines the signals from the vibration detectors on the tubes to determine properties of the sample fluid, such as density, viscosity, compressibility, water fraction, and bubble size. The measurement module may further detect certain flow patterns such as slug flow, for example.

To determine the sample fluid density, the measurement module measures the difference between resonance frequencies of the sample flow tube and the reference flow tube. The density can then be calculated according to a formula. Other fluid properties may be determined from the sample tube's resonance peak amplitude, peak width and/or peak shape. Variation of the density measurements may be used to detect and characterize multiple phase fluid flow. The use of a reference tube in the disclosed measurement device is expected to greatly enhance the accuracy and reliability of the measurement device over a range of temperatures, pressures, and shock accelerations such as those that may be found in a borehole.

A better understanding of the present invention can be obtained when the following detailed description of the preferred embodiment is considered in conjunction with the following drawings, in which:

FIG. 1A shows a densitometer according to a preferred embodiment of the present invention;

FIG. 1B shows a piezoelectric vibratory source;

FIG. 2 shows an alternative embodiment of a densitometer according to the present invention;

### Examples Of Usb Devices

FIG. 3 shows a graph of an exemplary resonance peak;

FIG. 4 shows an exemplary measurement module;

FIG. 5 shows a method for adaptive tracking of a resonance frequency;

FIG. 6 shows a method for measuring resonance peak frequency, amplitude, and width; and

FIG. 7 shows a graph of a measured density as a function of time.

While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and will herein be described in detail. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.

Referring now to FIG. 1A, one embodiment of a device for measuring density and viscosity of a flowing fluid generally includes a rigid housing 102, two bulkheads 104, fasteners 106, flow tubes 108, vibration sources 110, vibration detectors 112, and a measurement module (not shown). The rigid housing 102 surrounds and protects a volume through which the flow tubes 108 pass and reduces the response to vibrations not associated with particular modes of the flow tubes. The bulkheads 104 seal the volume and secure the flow tubes 108 within that volume. Fasteners 106 are provided to secure the bulkheads 104 to the rigid housing 102. The volume preferably contains air, a vacuum or a relatively inert gas such as nitrogen or argon. If gasses are used, then they are preferably at atmospheric pressure when the device is at room temperature.

Rigid housing 102, bulkheads 104, and flow tubes 108 are preferably made from materials that can withstand pressures of more than 20,000 psi (pounds per square inch) at temperatures of 250° C. or more. Two examples of suitable materials are Titanium and Hastaloy-HA276C. The flow tubes 108 may be welded to the bulkheads 104, or (as discussed further below) mechanically isolated from the bulkheads 104.

The flow tubes 108 are preferably straight, as this reduces any tendencies for plugging and erosion by materials passing through the flow tubes 108. However, it is recognized that bent tubes of various shapes, including “U”-shaped tubes, may provide greater measurement sensitivities.

Contemplated dimensions for the embodiment of FIG. 1A are shown in Table 1:

 TABLE 1 Flow Tube Bulkhead Housing Length 6″ 2″ 10″ Outer Diam 0.304″ 1.5″ 2″ Inner Diam 0.219″ — ˜1.5″

However, it is noted that other dimensions may be used without departing from the scope of the invention.

The vibration sources 110 are piezoelectric transducers such as those shown in FIG. 1B. They include a clamp 118 for securing the vibration source to the flow tube 108, an inertial or “backing” mass 114, and a piezoelectric layer 116 sandwiched between the clamp 118 and the inertial mass 114. When a voltage is applied to the piezoelectric layer 116, the layer expands, driving the tube 108 and mass 114 away from each other. When the voltage is subsequently removed or reversed, the layer contracts, pulling the tube and the mass together. Application of an oscillating voltage to the piezoelectric layer imparts a vibratory motion to the flow tube.

As discussed farther below, the flow tube 108 has a resonance frequency that depends on the density of the fluid it contains. When the vibration source 110 drives the flow tube 108 at a resonance frequency, the vibration of the tube reaches maximum amplitude (displacement), and the energy required to drive the vibration reaches a local minimum.

The vibration detectors 112 shown in FIG. 1A are piezoelectric devices with a structure similar to the vibration sources 110. A piezoelectric transducer is sandwiched between a clamp and an inertial mass. When the piezoelectric transducer is compressed (e.g. by movement of the clamp toward the inertial mass), it generates a voltage. When the layer is subsequently restored or expanded (e.g. by movement of the clamp away from the inertial mass), the voltage decreases. Vibration of the vibration detector 112 causes the detector to generate an electrical signal that oscillates at the vibration frequency. The amplitude of the electrical signal increases with the amplitude of the vibration.

Referring now to FIG. 4, one embodiment of the measurement module generally includes a digital signal processor 402, two voltage-to-frequency converters 404, two current drivers 406, two filter/amplifiers 408, two amplitude detectors 410, and a read-only memory (ROM) 412. The digital signal processor 402 may be configured and controlled by a system controller 414 that operates in response to actions of the user on the user interface 416. The system controller 414 preferably also retrieves measurements from the digital signal processor 402 and provides them to the user interface 416 for display to the user.

The digital signal processor 402 preferably executes a set of software instructions stored in ROM 412. Typically, configuration parameters are provided by the software programmer so that some aspects of the digital signal processor's operation can be customized by the user via interface 416 and system controller 414. Preferably, the set of software instructions causes the digital signal processor 402 to perform density measurements according to one or more of the methods detailed further below. The digital signal processor preferably includes digital to analog (D/A) and analog to digital (A/D) conversion circuitry for providing and receiving analog signals to off-chip components. Generally, most on-chip operations by the digital signal processor are performed on digital signals.

In performing one of the methods described further below, the digital signal processor 402 provides a voltage signal to the voltage-to-frequency converter 404. The voltage-to-frequency converter 404 produces a frequency signal having a frequency proportional to the input voltage; The current driver 406 receives this frequency signal and amplifies it to drive the vibration source 110. The vibration source 110 causes the flow tube to vibrate, and the vibrations are detected by vibration detector 112. A filter/amplifier 408 receives the detection signal from vibration detector 112 and provides some filtering and amplification of the detection signal before passing the detection signal to the amplitude detector 410. The filter/amplifier 408 serves to isolate the vibration detector 112 from the amplitude detector 410 to prevent the amplitude detector 410 from electrically loading the vibration detector 112 and thereby adversely affecting the detection sensitivity. The amplitude detector 410 produces a voltage signal indicative of the amplitude of the detection signal. The digital signal processor 402 measures this voltage signal, and is thereby able to determine a vibration amplitude for the chosen vibration frequency.

The measurement module employs the vibration sources 110 and vibration detectors 112 to locate and characterize the resonance frequencies of the flow tubes 108. Several different methods are contemplated. In a first method, the measurement module causes the vibration sources 110 to perform a frequency “sweep” across the range of interest, and records the amplitude readings from the vibration detectors 112 as a function of the frequency. As shown in FIG. 3, a plot of the vibration amplitude versus frequency will show a peak at the resonance frequency f0. The resonance frequency can be converted to a density measurement, and the shape of the peak may yield additional information such as viscosity and multiple phase information.

In a second method, the measurement module adaptively tracks the resonance frequency using a feedback control technique. One implementation of this method is shown in FIG. 5. An initial step size for changing the frequency is chosen in block 502. This step size can be positive or negative, to respectively increase or decrease the frequency. In block 504, the vibration source is activated and an initial amplitude measurement is made. In block 506, the vibration frequency is adjusted by an amount determined by the step size. In block 508, a measurement of the amplitude at the new frequency is made, and from this, an estimate of the derivative can be made. The derivative may be estimated to be the change in amplitude divided by the change in frequency, but the estimate preferably includes some filtering to reduce the effect of measurement noise. From this estimated derivative, a distance and direction to the resonance peak can be estimated. For example, if the derivative is large and positive, then referring to FIG. 3 it becomes clear that the current frequency is less than the resonance frequency, but the resonance frequency is nearby. For small derivatives, if the sign of the derivative is changing regularly, then the current frequency is very near the resonance frequency. For small negative derivatives without any changes of sign between iterations, the current frequency is much higher than the resonance frequency. Returning to FIG. 5, this information is used to adjust the step size in block 510, and the digital signal processor 402 returns to block 506. This method may work best for providing a fast measurement response to changing fluid densities.

In a third method, the measurement module employs an iterative technique to search for the maximum amplitude as the frequency is discretely varied. Any of the well-known search algorithms for minima or maxima may be used. One illustrative example is now described, but it is recognized that the invention is not limited to the described details. In essence, the exemplary search method uses a back-and-forth search method in which the measurement module sweeps the vibration source frequency from one half-amplitude point across the peak to the other half-amplitude point and back again. One implementation of this method is shown in FIG. 6. In block 602, vibration is induced at an initial (minimum) frequency. In block 604, the vibration amplitude at the current vibration frequency is measured and set as a threshold. In block 606, the frequency is increased by a predetermined amount, and in block 608, the amplitude at the new frequency is measured. Block 610 compares the measured amplitude to the threshold, and if the amplitude is larger, then the threshold is set equal to the measured amplitude in block 612. Blocks 606-612 are repeated until the measured amplitude falls below the threshold. At this point, the threshold indicates the maximum measured amplitude, which occurred at the resonance peak. The amplitude and frequency are recorded in block 614. The frequency increases and amplitude measurements continue in blocks 616 and 618, and block 620 compares the amplitude measurements to half the recorded resonance frequency. Blocks 616-620 are repeated until the amplitude measurement falls below half the resonance peak amplitude, at which point, the half-amplitude frequency is recorded in block 622. Blocks 624-642 duplicate the operations of corresponding blocks 602-622, except that the frequency sweep across the resonance peak occurs in the opposite direction. For each peak crossing, the measurement module records the resonance amplitude and frequency, and then records the subsequent half-amplitude frequency. From this information the peak width and asymmetry can be determined, and the fluid density, viscosity, and multiple phase information can be calculated.

The measurement module is an electronic circuit that may have temperature, pressure, and age-dependent variations. The densitometer structure as a whole may also exhibit these variations. Since it is expected that the densitometer will be exposed to temperature and pressure extremes over the device lifetime, it is unrealistic to believe that the device can sustain a given set of calibration settings. To circumvent the need for frequent re-calibrations, one of the flow tubes 108 is set up as a “vibration standard” that has a well-determined resonance frequency, and the resonance frequency of the other flow tube (hereafter termed the sample flow tube) is measured relative to the standard, or reference, flow tube. The sample flow tube accepts a flow of the sample fluid whose density is to be measured in one end and discharges the flow from the other end.

As the properties of water are extremely well known, it is preferred to have the reference flow tube filled with water. Alternatively, the reference flow tube may be filled with a vacuum, a gas, or some other substance with well known density properties (e.g. a reference solid). For the present purposes, the reference tube is considered to contain a vacuum if at room temperature the internal pressure is less than 0.05 atmospheres. Any fluid in the reference flow tube is preferably subjected to the pressure and temperature of the sample fluid's environment. Thermometers and pressure meters are preferably provided to determine what these temperature and pressure values are.

The measurement module preferably employs one vibration source 110 and one vibration detector 112 to adaptively track the resonance frequency of the reference flow tube 108. The measurement module then measures the frequency of the vibration signal from the sample tube relative to the resonance frequency signal from the reference tube. In one embodiment, the measurement module adds the two signals to obtain a signal that exhibits a beat frequency. The frequency of the beats is equal to the (unsigned) difference between the resonance frequency and the frequency of the vibration signal. The sign of the difference can be determined in a number of ways. One method is to utilize a fluid in the reference tube that is outside the anticipated density range (either lighter or heavier) of the sample. A second, different, reference tube could be used to determine a second beat frequency. Another method is to de-tune the frequency of the sample tube from its resonant frequency and observe the change in the measured frequency difference. For example, if an increase in the driving frequency results in an increase of the frequency difference, the resonant frequency of the sample is greater than that of the reference. Alternatively, the drive frequency of the reference tube could be de-tuned with similar results. From the signed difference, the density of the unknown fluid can be determined. A method for determining the density of the unknown fluid is presented further below.

Turning now to FIG. 2, a second embodiment is shown. In FIG. 2, the flow tubes are mechanically isolated from the mounting structure by elastomeric seals 202. This makes the ends free to vibrate because the seals are soft and the deflections are small, but perhaps more significantly, this configuration may eliminate most of the extraneous vibration noise from the flow tubes. The vibration sources shown for this embodiment are inductive coils 204. Electrical currents passing through the inductive coils generate a magnetic field that attracts or repels a permanent magnet. By alternating the current direction at a desired vibration frequency, the magnet can be forced to vibrate the flow tubes at that frequency.

The position of the magnet can be measured from the back EMF (electromotive force) that the coil generates, so the inductive coils can also be used as the vibration sensors. Alternatively, a separate inductive coil may serve as a vibration sensor, as may any one of a multitude of other position sensors including piezoelectric devices, Hall-effect sensors, interferometers, strain gauges, capacitance meters, accelerometers, etc.

It is noted that in both embodiments, the vibration sources and vibration detectors are preferably mounted near an antinode (point of maximum displacement from the equilibrium position) of the mode of vibration they are intended to excite and monitor. It is contemplated that more than one mode of vibration may be employed (e.g. the vibration source may switch between multiple frequencies to obtain information from higher resonance harmonic frequencies). The vibration sources and detectors are preferably positioned so as to be near antinodes for each of the vibration modes of interest.

The locations of nodes (points of zero vibrational amplitude) and antinodes are determined by the wavelength of the vibration mode. The frequency f and wavelength λ are related to the speed of sound v in the material by the equation v=fλ.

The following notation is used for the resonance frequency derivation:

A vibration system constant (22.4 fixed ends, 22.4 free ends, 3.52 cantilevered on one end)

A calibration constant (lbf/(in3-sec2)

B calibration constant (lbf/(in3)

fn natural frequency (Hz)

p period of natural frequency (sec)

ρ fluid density (lbf/in3)

ρt tube material density (lbf/in3)

μ system mass per unit length (lbf-sec2/in2)

μf fluid mass per unit length (lbf-sec2/in2)

μt tube mass per unit length (lbf-sec2/in2)

do tube outside diameter (in)

di tube inside diameter (in)

l tube length (in)

E tube modulus of elasticity (psi)

I area moment of inertia of the tube cross section (in4)

g gravitational constant (386.4 in/sec2)

The natural frequency of the tube can be calculated as follows (see page 1-14 of the Shock and Vibration Handbook, McGraw Hill, N.Y., 1976.): $fn=A2πE·Iμ·l4(Hz)(1)$

A is determined by the geometry of the system, and is 22.4 for the first mode of vibration in a tube with fixed ends or free ends. The area moment of inertia of a tube (I) is given by: $I=πdo464(1-di4do4)(in4)(2)$

The mass per unit length μ consists of the tube's weight and the fluid's weight divided by the length of the tube and the gravitational constant (g=386.4 in/ sec2): $μt=ρtπg(do2-di2)4(lbf-sec2/in2)(3)μf=ρπgdi24(lbf-sec2/in2)(4)μ=μt+μf=ρtdo2πg4(1-di2do2(1-ρρt))(lbf-sec2/in2)(5)$

Substituting Equations 2 and 5 into Equation 1 yields an estimate of the natural frequency: $fn=A2πE·πdo464(1-di4do4)ρtdo2πg4(1-di2do2(1-ρρt))·l4=Ado8πl2Egρt(1-di4do4)1-di2do2(1-ρρt)(Hz)(6)$

Solving Equation 6 for density yields: $ρ=Eg(Ado2fn8πdil2)2(1-di4do4)-ρt(do2di2-1)(7)$

Equation 7 can be expressed in terms of constant coefficients A & B:

 TABLE 2 Hastaloy-HA276C Titanium Cantilever Fixed Fixed Cantilever Fixed Fixed Variables: A 3.52 22.4 22.4 3.52 22.4 22.4 E 29.8 106 29.8 106 29.8 106 15.0 106 15.0 106 15.0 106 g 386.4 386.4 386.4 386.4 386.4 386.4 di 0.09 0.219 0.219 0.09 0.219 0.219 do 0.125 0.304 0.304 0.125 0.304 0.304 σ stress 63056.48 63154.651 63154.651 63056.478 63154.651 63154.651 1 4 16 6 4 16 6 ρt 0.321 0.321 0.321 0.175 0.175 0.175 ρ−sg = 1 0.0361 0.0361 Results: ρ−sg fn fn fn fn fn fn 2 229.13 221.62 1575.98 204.19 197.47 1404.26 1.8 231.40 223.82 1591.60 207.40 200.59 1426.40 1.6 233.73 226.08 1607.69 210.77 203.85 1449.62 1.4 236.14 228.41 1624.28 214.31 207.28 1474.02 1.2 238.62 230.82 1641.39 218.04 210.89 1499.68 1 241.18 233.30 1659.06 221.97 214.70 1526.74 0.8 243.83 235.87 1677.30 226.11 218.72 1555.31 0.6 246.57 238.52 1696.17 230.50 222.97 1585.56 0.4 249.40 241.27 1715.68 235.15 227.48 1617.63 0.2 252.33 244.11 1735.89 240.10 232.28 1651.74 0.00122 255.35 247.03 1756.69 245.34 237.36 1687.87 Δf 26.22 25.41 180.71 41.15 39.88 283.61 Δf/fc 10.87% 10.89% 10.89% 18.54% 18.58% 18.58% ρ = A/fn2 − B (8)

Where the coefficients A & B are determined by the tube's material properties and geometry: $A=E(gAdo28πdil2)2(1-di4do4)(9)B=ρt(do2di2-1)(10)$

In practice, the constants A & B may be estimated by fitting a calibration curve.

Table 2 is an example calculation of the natural frequencies for various configurations and materials. The frequencies are calculated as a function of fluid specific gravity (ρ-sg) in a range from near 0 (air) to 2 (heavy mud). The sensitivity of the device can be defined as the change in frequency from air to a heavy mud divided by a center frequency determined with water (specific gravity=1) in the tube. The cantilever device has a sensitivity of 10.87% and the 16 ″ fixed-end straight tube has a sensitivity slightly larger with 10.89%. A 6 ″ fixed-end straight tube exhibits an increased frequency with water (sg=1) to 1659 Hz. It is noted that while the frequency increased, the sensitivity remained unchanged (10.89%). The sensitivity ratios can be increased to 19% by using Titanium, due to its improved stiffness to weight ratio. The housing, when made of steel, exhibits a much higher natural frequency than the tubes (5960 Hz). Hence, it does not couple with the tube modes.

The overriding natural frequency of the tubes is dominated by the tube material and its properties. It is noted that the tube's length has the most significant influence on the natural frequency. The resolution (sensitivity) of the gauge may be increased in terms of frequency change versus density by reducing the weight or density of the tube.

Using Equation 8, ρs (the density of the sample fluid in the sample tube) can be expressed in terms of ρr (the density of the reference fluid in the reference tube) and Δf (the measured difference in frequencies): $ρs=A(AρR+B+Δf)2-B(11)$

It is expected that the accuracy of this calculation may be limited by the calibration accuracy for A and B and the frequency resolution.

FIG. 7 shows an example of density measurements made according to the disclosed method as a function of time. Initially, the sample flow tube fills with oil, and the density measurement quickly converges to a specific gravity of 0.80. As a miscible gas is injected into the flow stream, the sample tube receives a multiple-phase flow stream, and the density measurement exhibits a significant measurement variation. As the flow stream becomes mostly gas, the oil forms a gradually thinning coating on the wall of the tube, and the density measurement converges smoothly to 0.33. It is noted that in the multiple-phase flow region, the density measurement exhibits a variance that may be used to detect the presence of multiple phases.

Air or gas present in the flowing fluid affect the densitometer measurements. Gas that is well-mixed or entrained in the liquid may simply require slightly more drive power to keep the tube vibrating. Gas that breaks out, forming voids in the liquid, will reduce the amplitude of the vibrations due to damping of the vibrating tube. Small void fractions will cause variations in signals due to local variation in the system density, and power dissipation in the fluid. The result is a variable signal whose envelope corresponds to the densities of the individual phases. In energy-limited systems, larger void fractions can cause the tube to stop vibrating altogether when the energy absorbed by the fluid exceeds that available. Nonetheless, slug flow conditions can be detected by the flowmeter electronics in many cases, because they manifest themselves as periodic changes in measurement characteristics such as drive power, measured density, or amplitude. Because of the ability to detect bubbles, the disclosed densitometer can be used to determine the bubble-point pressure. As the pressure on the sample fluid is varied, bubbles will form at the bubble point pressure and will be detected by the disclosed device.

If a sample is flowing through the tube continuously during a downhole sampling event, the fluids will change from borehole mud, to mud filtrate and cake fragments, to majority filtrate, and then to reservoir fluids (gas, oil or water). When distinct multiple phases flow through the tube, the sensor output will oscillate within a range bounded by the individual phase densities. If the system is finely homogenized, the reported density will approach the bulk density of the fluid. To enhance the detection of bulk fluid densities, the disclosed measurement devices may be configured to use higher flow rates through the tube to achieve a more statistically significant sample density. Thus, the flow rate of the sample through the device can be regulated to enhance detection of multiple phases (by decreasing the flow rate) or to enhance bulk density determinations (by increasing the flow rate). If the flow conditions are manipulated to allow phase settling and agglomeration (intermittent flow or slipstream flow with low flow rates), then the vibrating tube system can be configured to accurately detect multiple phases at various pressures and temperatures. The fluid sample may be held stagnant in the sample chamber or may be flowed through the sample chamber.

In addition, the resonance frequency (or frequency difference) may be combined with the measured amplitude of the vibration signal to calculate the sample fluid viscosity. The density and a second fluid property (e.g. the viscosity) may also be calculated from the resonance frequency and one or both of the half-amplitude frequencies. Finally, vibration frequency of the sample tube can be varied to determine the peak shape of the sample tube's frequency response, and the peak shape used to determine sample fluid properties.

The disclosed instrument can be configured to detect fluid types (e.g. fluids may be characterized by density), multiple phases, phase changes and additional fluid properties such as viscosity and compressibility. The tube can be configured to be highly sensitive to changes in sample density and phases. For example, the flow tubes may be formed into any of a variety of bent configurations that provide greater displacements and frequency sensitivities. Other excitation sources may be used. Rather than using a variable frequency vibration source, the tubes may be knocked or jarred to cause a vibration. The frequencies and envelope of the decaying vibration will yield similar fluid information and may provide additional information relative to the currently preferred variable frequency vibration source.

The disclosed devices can quickly and accurately provide measurements of downhole density and pressure gradients. The gradient information is expected to be valuable in determining reservoir conditions at locations away from the immediate vicinity of the borehole. In particular, the gradient information may provide identification of fluids contained in the reservoir and the location(s) of fluid contacts. Table 3 shows exemplary gradients that result from reservoir fluids in a formation.

Determination fluid contacts(Gas/Oil and Oil/Water) is of primary importance in reservoir engineering. A continuous vertical column may contain zones of gas, oil and water, Current methods require repeated sampling of reservoir pressures as a function of true vertical depth in order to calculate the pressure gradient (usually psi/ft) in each zone. A fluid contact is indicated by the intersection of gradients from two adjacent zones (as a function of depth). Traditionally, two or more samples within a zone are required to define the pressure gradient.

The pressure gradient (Δp/Δh) is related to the density of the fluid in a particular zone. This follows from the expression for the pressure exerted by a hydrostatic column of height h.

P=ρ*g*h (12)

 TABLE 3 Density Gradient Fluid Gm/cc psi/ft Low Pressure Gas Cap 0.10 0.04 Gas Condensate 0.20 0.09 Light Oil 0.50 0.22 Med. Oil 0.70 0.30 Heavy Oil 0.90 0.39 Pure Water 1.00 0.43 Formation Water ≧1.00 ≧0.43 Mud Filtrate (from 8.7 ppg) 1.04 0.45 Completion Brine 1.08 0.47 Mud (12.5 ppg) 1.50 0.65

where P denotes pressure, ρ denotes density, g denotes gravitational acceleration, and h denotes elevation.

In a particular zone, with overburden pressure which differs from that of a continuous fluid column, the density of the fluid may be determined by measuring the pressure at two or more depths in the zone, and calculating the pressure gradient: $ρ=ΔP/Δhg(13)$

However, the downhole densitometer directly determines the density of the fluid. This allows contact estimation with only one sample point per zone. If multiple samples are acquired within a zone, the data quality is improved. The gradient determination can then be cross-checked for errors which may occur. A high degree of confidence is achieved when both the densitometer and the classically determined gradient agree.

Once the gradient for each fluid zone has been determined, the gradient intersections of adjacent zones are determined. The contact depth is calculated as the gradient intersection at true vertical depth.

Numerous variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. For example, the flow tubes may be replaced with sample chambers of any rigid variety. It is intended that the following claims be interpreted to embrace all such variations and modifications.

It is noted that when the disclosed device uses a reference fluid in the reference tube, the reference fluid is preferably subjected to substantially the same pressure and temperature as the sample fluid. When the reference tube has an excitation source mounted on the tube to generate vibration of the reference tube, the vibration of the reference tube may also induce vibration of the sample tube.