Patent Publication Number: US-2019186970-A1

Title: Fluid analysis system

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This patent application is a divisional application of U.S. patent application Ser. No. 14/947,565, filed Nov. 20, 2015, which is hereby incorporated herein by reference in its entirety. 
    
    
     BACKGROUND 
     The oil and gas industry have developed various tools capable of determining formation fluid properties. For example, borehole fluid sampling and testing tools such as Schlumberger&#39;s Modular Formation Dynamics Testing (MDT) Tool can provide important information on the type and properties of reservoir fluids in addition to providing measurements of reservoir pressure, permeability, and mobility. These tools may perform measurements of the fluid properties downhole, using sensor modules on board the tools. These tools can also withdraw fluid samples from the reservoir that can be collected in bottles and brought to the surface for analysis. The collected samples are routinely sent to fluid properties laboratories for analysis of physical properties that include, among other things, oil viscosity, gas-oil ratio, mass density or API gravity, molecular composition, H 2 S, asphaltenes, resins, and various other impurity concentrations. 
     The reservoir fluid may break phase in the reservoir itself during production. For example, one zone of the reservoir may contain oil with dissolved gas. During production, the reservoir pressure may drop to the extent that the bubble point pressure is reached, allowing gas to emerge from the oil, causing production concerns. Knowledge of this bubble point pressure may be helpful when designing production strategies. 
     Characterizing a fluid in a laboratory utilizes an arsenal of devices, procedures, trained personnel, and laboratory space. Successfully characterizing a fluid in a wellbore uses methods, apparatus, and systems configured to perform similarly with less space and personal attention and to survive in conditions that quickly destroy traditional lab equipment. Identifying the undesired phase change properties of a fluid is especially useful when managing a hydrocarbon reservoir. 
     SUMMARY 
     In accordance with example embodiments, a method includes: placing a doped glass material in a base block; inserting a hollow tube into the doped glass material; heating the doped glass material to a temperature at which the doped glass material melts; allowing the doped glass material to cool to form a solid glass isolator that mechanically supports the hollow tube with respect to the base block and electrically isolates the hollow tube from the base block. 
     Further features and aspects of example embodiments of the present invention are described in more detail below with reference to the appended Figures. 
    
    
     
       FIGURES 
         FIG. 1  shows a wireline logging system at a well site in accordance with one embodiment of the present disclosure; 
         FIG. 2  shows a wireline tool in accordance with one embodiment of the present disclosure; 
         FIG. 3A  shows a fluid analyzer module in accordance with one embodiment of the present disclosure; 
         FIG. 3B  shows a fluid analyzer module in accordance with another embodiment of the present disclosure; 
         FIG. 4A  shows a portion of a vibrating-tube densitometer; 
         FIG. 4B  shows a top view of the structure of  FIG. 4A ; 
         FIG. 4C  shows a cross-sectional view corresponding to section A-A of  FIG. 4B ; 
         FIG. 4D  shows an enlarged partial sectional view corresponding to section B of  FIG. 4C ; 
         FIG. 5A  shows a portion of a vibrating-tube densitometer; 
         FIG. 5B  shows an exploded view of the structure of  FIG. 5A ; 
         FIG. 5C  shows a cross-sectional view of the structure of  FIG. 5A ; 
         FIG. 5D  shows a partial sectional view corresponding to section C of  FIG. 5C ; 
         FIG. 5E  shows a subassembly incorporating the structure of  FIG. 5A ; 
         FIG. 5F  shows an assembly incorporating the subassembly of  FIG. 5E ; 
         FIG. 5G  shows the structure of  FIG. 5A  with an electrical control system and electrode leads in place; and 
         FIG. 5H  shows the structure of  FIG. 5A  with an electrical control system and an optical detection system. 
     
    
    
     DESCRIPTION 
     At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation-specific decisions may be made to achieve the developer&#39;s specific goals, such as compliance with system related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. In addition, the composition used/disclosed herein can also comprise some components other than those cited. In the summary and detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary and detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any concentration within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to a few specific points, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors possessed knowledge of the entire range and all points within the range. 
       FIG. 1  shows one example of a wireline logging system  100  at a well site. Such a wireline logging system  100  can be used to implement a rapid formation fluid analysis. In this example, a wireline tool  102  is lowered into a wellbore  104  that traverses a formation  106  using a cable  108  and a winch  110 . The wireline tool  102  is lowered down into the wellbore  104  and makes a number of measurements of the adjacent formation  106  at a plurality of sampling locations along the wellbore  104 . The data from these measurements is communicated through the cable  108  to surface equipment  112 , which may include a processing system for storing and processing the data obtained by the wireline tool  102 . The surface equipment  112  includes a truck that supports the wireline tool  102 . In other embodiments, the surface equipment may be located in other locations, such as within a cabin on an off-shore platform. 
       FIG. 2  shows a more detailed view of the wireline tool  102 . The wireline tool  102  includes a selectively extendable fluid admitting assembly (e.g., probe)  202 . This assembly  202  extends into the formation  106  and withdraws formation fluid from the formation  216  (e.g., samples the formation). The fluid flows through the assembly  202  and into a main flow line  204  within a housing  206  of the tool  102 . A pump module  207  is used to withdraw the formation fluid from the formation  106  and pass the fluid through the flow line  204 . The wireline tool  102  may include a selectively extendable tool anchoring member  208  that is arranged to press the probe  202  assembly against the formation  106 . 
     The wireline tool  102  also includes a fluid analysis module  210  for analyzing at least a portion of the fluid in the flow line  204 . This fluid analysis module  210  is further described below. After the fluid analysis module  210 , the formation fluid may be pumped out of the flow line  204  and into the wellbore  104  through a port  212 . Some of the formation fluid may also be passed to a fluid collection module  214  that includes chambers for collecting fluid samples and retaining samples of the formation fluid for subsequent transport and testing at the surface (e.g., at a testing facility or laboratory). 
       FIG. 3A  shows a more detailed view of a fluid analysis module  210 . As shown in  FIG. 3A , the fluid analysis module  210  includes a secondary flow line  302  (e.g., a channel) that is coupled through a valve  304  to the main flow line  204 . The valve  304  selectively passes a sample of formation fluid into the secondary flow line  302 . The secondary flow line  302  also includes a membrane  306  to separate water from the formation fluid sample (e.g., a hydrophobic membrane). Such a membrane is described in U.S. Pat. No. 7,575,681 issued on Aug. 18, 2009 and U.S. Pat. No. 8,262,909 issued on Sep. 11, 2012, each of which is hereby incorporated by reference in its entirety. 
     In some embodiments, a pump or a piston is used to extract the formation fluid sample from the main flow line  204  and pass the formation fluid through the membrane  306 . In various embodiments, the membrane  306  separates water from the formation fluid sample as the sample is being extracted from the main flow line  304 . Also, although the membrane  306  is disposed after the valve  304 , it should be appreciated that in some embodiments the membrane  306  is disposed before the valve  304 . Moreover, although a single membrane  306  is provided in  FIG. 3A , it should be understood that some embodiments include multiple membranes. 
     Once the formation fluid sample passes the membrane  306 , the sample flows into a fluid analyzer  308  that analyzes the sample to determine at least one property of the fluid sample. The fluid analyzer  308  is in electronic communication with the surface equipment  112  through, for example, a telemetry module and the cable  108 . Accordingly, the data produced by the fluid analyzer  308  can be communicated to the surface for further processing by processing system. 
     The fluid analyzer  308  can include a number of different devices and systems that analyze the formation fluid sample. For example, in one embodiment, the fluid analyzer  308  includes a spectrometer that uses light to determine a composition of the formation fluid sample. The spectrometer can determine an individual fraction of methane (C 1 ), an individual fraction of ethane (C 2 ), a lumped fraction of alkanes with carbon numbers of three, four, and five (C 3 -C 5 ), and a lumped fraction of alkanes with a carbon number equal to or greater than six (C 6+ ). An example of such a spectrometer is described in U.S. Pat. No. 4,994,671 issued on Feb. 19, 1991 and U.S. Patent Application Publication No. 2010/0265492 published on Oct. 21, 2012, each of which is incorporated herein by reference in its entirety. In some embodiments, the fluid analyzer  308  includes a gas chromatograph that determines a composition of the formation fluid. In some embodiments, the gas chromatograph determines an individual fraction for each alkane within a range of carbon numbers from one to 25 (C 1 -C 25 ). Examples of such gas chromatographs are described in U.S. Pat. No. 8,028,562 issued on Oct. 4, 2011 and U.S. Pat. No. 7,384,453 issued on Jun. 10, 2008, each of which is hereby incorporated by reference in its entirety. The fluid analyzer  308  may also include a mass spectrometer, a visible absorption spectrometer, an infrared absorption spectrometer, a fluorescence spectrometer, a resistivity sensor, a pressure sensor, a temperature sensor, a densitometer, and/or a viscometer. The fluid analyzer  308  may also include combinations of such devices and systems. For example, the fluid analysis module  210  may include a spectrometer followed by a gas chromatograph as described in, for example, U.S. Pat. No. 7,637,151 issued on Dec. 29, 2009 and U.S. patent application Ser. No. 13/249,535 filed on Sep. 30, 2011, each of which is incorporated herein by reference in its entirety. 
       FIG. 3B  shows a fluid analysis module  310  in accordance with another embodiment of the present disclosure. In this example, a bypass flow line  301  is coupled to the main flow line  204  through a first valve  305 . The first valve  305  selectively passes formation fluid from the main flow line  204  into the bypass flow line  301 . A secondary flow line  307  (e.g., a channel) is coupled through a second valve  309  (e.g., an entrance valve) to the bypass flow line  301 . The second valve  309  selectively passes a sample of formation fluid into the secondary flow line  307 . The fluid analysis module  310  includes a membrane  311  to separate water from the formation fluid sample (e.g., a hydrophobic membrane). In this embodiment, the membrane  311  is disposed before the second valve  309 . The fluid analysis module  310  also includes a third valve  313  (e.g., an exit valve) between the secondary flow line  307  and the bypass flow line  301 . The second valve  309  and the third valve  313  can be used to isolate the formation fluid sample within the secondary flow line  307 . After analysis, the formation fluid sample can pass to the bypass flow line  301  through the third valve  313 . 
     In the example of  FIG. 3B , the fluid analysis module  310  further includes a spectrometer  315  followed by a densitometer  317  and a viscometer  319 . Such an arrangement provides both a chemical composition for the fluid sample and physical characteristics for the fluid sample (e.g., density and viscosity). As explained above, other combinations of devices and systems that analyze the formation fluid sample are also possible. 
     In  FIG. 3B , the fluid analysis module  310  also includes a pressure unit  321  for changing the pressure within the fluid sample and a pressure sensor  323  that monitors the pressure of the fluid sample within the secondary flow channel  307 . In some embodiments, the pressure unit  321  is a piston that is in communication with the secondary flow line  307  and that expands the volume of the fluid sample to decrease the pressure of the sample. As explained above, the second valve  309  and the third valve  313  can be used to isolate the formation fluid sample within the secondary flow line  307 . Also, in some embodiments, the pressure unit  321  can be used to extract the formation fluid sample from the bypass flow line  301  by changing the pressure within the secondary flow line  307 . The pressure sensor  323  is used to monitor the pressure of the fluid sample within the secondary flow line  307 . The pressure sensor  323  can be a strain gauge or a resonating pressure gauge. By changing the pressure of the fluid sample, the fluid analyzer module  310  can make measurements related to phase transitions of the fluid sample (e.g., bubble point or asphaltene onset pressure measurements). Further details of devices and systems that analyze the formation fluid sample are also provided in PCT Application Publication No. WO 2014/158376 A1, which is hereby incorporated herein by reference in its entirety. 
     Referring to  FIG. 1 , near the bottom of the wellbore  104 , the pressure may be sufficiently high that the fluid is single-phase. At a given mid-point (the location of which may vary depending on well properties), the pressure may reach the bubble point when the fluid breaks phase, producing gaseous and liquid phases. While the fluid is transiting from the wellbore bottom to the surface, the temperature is monotonically decreasing, increasing the fluid viscosity. 
     Fluids that may be produced from the formation have their temperature changed as they are brought to the surface, and hence experience a dramatic change in the fluid properties, including but not limited to their density. In order to accurately calculate the flow rate during production, an accurate knowledge of the density as a function of depth is useful. Along with temperature dependence, the fluid pressure may drop below the bubble point while in transit. Some example systems  100  may obtain a fluid sample from the formation and rapidly vary its temperature in order to simulate the fluid&#39;s passage through the oil well during the production stage. In some embodiments, the tool  102  may store a sample extracted from the formation after measurements are performed. The tool  102  may be raised to a shallower depth and allow the sample within the PVT device to come to equilibrium, after which additional measurements may be performed. It should be understood that although the tool  102  in the illustrated examples is a wireline tool, the features of the tool  102  may be implemented into any suitable apparatus and may be provided to operate in downhole and/or surface locations. 
     As an example, a description for measuring density will be discussed, with a comparison of the amount of energy to change the sample temperature for both mesoscopic and microfluidic approaches. This would apply as well to a bubble point measurement where one is interested in the temperature dependence as well. The present embodiments may be compared to a conventional viscometer that is macroscopic in size and is directly immersed in the flow-line which has an inner diameter of approximately 5.5 mm. The total amount of fluid to fill the conventional sensors and the surrounding region volume is on the order of 10 milliliters, with an associated heat capacity of, assuming the specific heat of mineral oil, 1.7 Joules/(gram Kelvin), or a heat capacity of approximately 20 Joules/Kelvin. Hence, 20 Joules of energy are removed to reduce the temperature by one-degree Kelvin. Furthermore, as the sensors are thermally connected to a large metallic assembly on the order of 1 kilogram (or more), in practice one would reduce the temperature of this assembly as well. Assuming a specific heat of 0.5 Joules/(gram Kelvin) for steel, one would have to remove 500 Joules of energy to reduce the temperature of the whole assembly by one degree. This approach using conventional technologies will be referred to as mesoscopic herein. 
     As a comparison, microfluidic environments of the present disclosure may use fluid volumes on the order of ten microliters, which corresponds to around 10 milligrams of liquid, which has a heat capacity of about 0.02 Joules/Kelvin (using the above numbers for the specific heat). In practice, one controls the temperature of the microfluidic chamber as well, which may have a mass on the order of 50 grams, and assuming this is fabricated from titanium, with a specific heat of 0.5 Joules/(gram Kelvin), it would use on the order of 25 Joules of energy to change the temperature by one degree. Note that this power usage for the microfluidic approach is 20 times smaller than for mesoscopic approach. Peltier (or thermoelectric) coolers reveals that models with dimensions with the proper scale exist and are specified to produce heat fluxes on the order of 1 Joule/second (1 watt), and one may quickly ramp up or down the temperature of such a device. Hence, a rapid ramping up or down of the temperature of a microfluidic-scale of fluidic volume and associated chamber is feasible. 
     As indicated above, during a process of sampling fluid into the microfluidic system  210 ,  310  of the tool  102 , a fluid may be sampled from the formation  106 . In some embodiments, a small volume (on the order of tens of microliters) of fluid will be sampled, filtered, and passed into the microfluidic system  210 ,  310 . The system  210 ,  310  may be placed into a pressure compensation system where during the initial phase of its operation, the pressure is approximately 100 psi lower (or less) than the flowline of the tool in which it will be implemented. As discussed above, the microfluidic system  210 ,  310  may include microfluidic sensors to measure the density, viscosity or any other physical properties of the fluid. The microfluidic system  210 ,  310  may either be located downhole or at the surface. 
     For downhole applications, the fluid evaluation may be motivated by the fact that wellbore temperature changes substantially from the formation to the surface. Fluids that are produced from the formation change their temperature accordingly and hence experience a dramatic change in their properties, including but not limited to their density. In order to accurately calculate the flow rate during production one should accurately know the density as a function of depth. This is further complicated by the fact that the fluid may drop below the bubble point while in transit. Hence, a system may be selected that can obtain a fluid sample from the formation and rapidly vary its temperature in order to simulate its passage through the wellbore during the production stage. 
     Generally, examples disclosed herein relate to collecting a fluid from a wellbore, a fracture in a formation, a body of water or oil or mixture of materials, or other void in a subterranean formation that is large enough from which to collect a sample. The fluid may contain solid particles such as sand, salt crystals, proppant, solid acids, solid or viscous hydrocarbon, viscosity modifiers, weighing agents, completions residue, or drilling debris. The fluid may contain water, salt water, hydrocarbons, drilling mud, emulsions, fracturing fluid, viscosifiers, surfactants, acids, bases, or dissolved gases such as natural gas, carbon dioxide, or nitrogen. 
     Systems for analyzing these fluids may be located in various locations or environments, including, but not limited to, tools for downhole use, permanent downhole installations, or any surface system that will undergo some combination of elevated pressures, temperatures, and/or shock and vibration. In some embodiments, temperatures may be as high as about 175° C. or about 250° C. with pressures as high as about 25,000 psi. 
     In general, energy added to a fluid at pressures near the bubble point to overcome the nucleation barrier associated with bubble production. Thus, energy may be added to a fluid thermally through the process of thermal nucleation. The quantity of bubbles produced at the thermodynamic bubble point via thermal nucleation is sufficiently small that their presence is detectable near the place of thermal nucleation in a phase transition cell and not in other components in the measurement system. However, upon further depressurization of the system, the supersaturation becomes large enough that bubble nucleation spontaneously occurs throughout the measurement system. In one or more embodiments, a fluid sample may be depressurized at a rate such that bubble detection may occur in a phase transition cell alone or may be sufficiently high enough to be detected throughout the overall system. 
     During depressurization of a sample, the density, viscosity, optical transmission through the phase transition cell, and sample pressure may be simultaneously measured. Depressurization starts at a pressure above the saturation pressure and takes place with a constant change in system volume, a constant change in system pressure, or discreet pressure changes. 
     Collecting and analyzing a small sample with equipment with a small interior volume allows for precise control and rigorous observation when the equipment is appropriately tailored for measurement. At elevated temperatures and pressures, the equipment may also be configured for effective operation over a wide temperature range and at high pressures. Selecting a small size for the equipment is advantageous for rugged operation because the heat transfer and pressure control dynamics of a smaller volume of fluid are easier to control then those of large volumes of liquids. That is, a system with a small exterior volume may be selected for use in a modular oil field services device for use within a wellbore. A small total interior volume can also allow cleaning and sample exchange to occur more quickly than in systems with larger volumes, larger surface areas, and larger amounts of dead spaces. Cleaning and sample exchange are processes that may influence the reliability of the microfluidic system  210 ,  310 . That is, the smaller volume uses less fluid for observation, but also can provide results that are more likely to be accurate. 
     The minimum production pressure of the reservoir may be determined by measuring the saturation pressure of a representative reservoir fluid sample at the reservoir temperature. In a surface measurement, the reservoir phase envelope may be obtained by measuring the saturation pressure (bubble point or dewpoint pressures) of the sample using a traditional PVT view cell over a range of temperatures. Saturation pressure can be either the bubble or dewpoint of the fluid, depending upon the fluid type. At each temperature, the pressure of a reservoir sample is lowered while the sample is agitated with a mixer. This is done in a view cell until bubbles or condensate droplets are optically observed and is known as a Constant Composition Expansion (CCE). The PVT view cell volume is on the order of tens to hundreds of milliliters, thus using a large volume of reservoir sample to be collected for analysis. This sample can be consumed or altered during PVT measurements. A similar volume may be used for each additional measurement, such as density and viscosity, in a surface laboratory. Thus, the small volume of fluid used by microfluidic sensors of the present disclosure (approximately 1 milliliter total for measurements described herein) to make measurements may be highly advantageous. 
     In one or more embodiments, an optical phase transition cell may be included in a microfluidic PVT tool. It may be positioned in the fluid path line to subject the fluid to optical interrogation to determine the phase change properties and its optical properties. U.S. patent application Ser. No. 13/403,989, filed on Feb. 24, 2012 and United States Patent Application Publication Number 2010/0265492, published on Oct. 21, 2010 describe embodiments of a phase transition cell and its operation. Each of these applications is incorporated herein by reference in its entirety. The pressure-volume-temperature phase transition cell may contain as little as 300 μl, or less, of fluid. The phase transition cell detects the dew point or bubble point phase change to identify the saturation pressure while simultaneously nucleating the minority phase. 
     The phase transition cell may provide thermal nucleation which facilitates an accurate saturation pressure measurement with a rapid depressurization rate of from about 10 to about 200 psi/second. As such, a saturation pressure measurement (including depressurization from reservoir pressure to saturation pressure) may take place in less than 10 minutes, as compared to the saturation pressure measurement via standard techniques in a surface laboratory, wherein the same measurement may take several hours. 
     Some embodiments may include a view cell to measure the reservoir asphaltene onset pressure (AOP) as well as the saturation pressures. Hence, the phase transition cell becomes a configuration to facilitate the measurement of many types of phase transitions during a CCE. 
     In one or more embodiments, the densitometer  317 , viscometer  319 , a pressure gauge and/or a method to control the sample pressure with a phase transition cell may be integrated so that most sensors and control elements operate simultaneously to fully characterize a live fluid&#39;s saturation pressure. In some embodiments, each individual sensor itself (e.g., densitometer  317  or viscometer  319 ) has an internal volume of no more than 20 microliters (approximately 2 drops of liquid) and by connecting each in series, the total volume (500 microliters) to charge the system with live oil before each measurement may be minimized. In some embodiments, the fluid has a total fluid volume of about 1.0 mL or less. In other embodiments, the fluid has a total fluid volume of about 0.5 mL or less. 
     This configuration is substantially different than a traditional Pressure-Volume-Temperature (PVT) apparatus but provides similar information while reducing the amount of fluid consumed for measurement.  FIG. 3A  is a schematic of one embodiment of a PVT apparatus for use downhole. In some embodiments, the PVT apparatus may be included into another measurement tool or may be standalone on a drill string or wire line. 
     The system&#39;s  210 ,  310  small dead volume (less than 0.5 mL) facilitates pressure control and sample exchange. In some embodiments, the depressurization or pressurization rate of the fluid is less than 200 psi/second. In some embodiments, the fluid is circulated through the system at a volumetric rate of no more than 1 ml/sec. 
     As mentioned above, the tool of the present disclosure may include a densitometer  317  (or analogous densitometer of fluid analyzer  308 ) to measure fluid density which, in some examples, may be used to calculate compressibility. The fluid compressibility, k, can be calculated by precisely measuring the fluid density while varying the pressure. The compressibility can be defined as the relative change in fluid density with the change in pressure as in the following equation: 
     
       
         
           
             
               
                 
                   
                     k 
                      
                     
                       [ 
                       ρ 
                       ] 
                     
                   
                   = 
                   
                     
                       1 
                       ρ 
                     
                      
                     
                       
                         ∂ 
                         ρ 
                       
                       
                         ∂ 
                         P 
                       
                     
                   
                 
               
               
                 
                   ( 
                   1 
                   ) 
                 
               
             
           
         
       
     
       FIGS. 4A to 5H  show components of the densitometer  317 . It should be understood that, although the example device is a configured to function as a densitometer, any suitable fluid analysis system may implement features analogous to those described in connection with the densitometer  317 . For example, a microfluidic coriolis force meter may implement analogous isolation, electrical, structural, and/or vibrational features to those described in connection with densitometer  317 . 
       FIGS. 4A and 4B  show a vibrating tube densitometer module  2000  of the densitometer  317  with integrated electrical isolation components. A U-shaped thin vibrating tube element  2002  functions as the vibrating element of the vibrating tube densitometer module  2000 . A proximal end portion of the vibrating tube element  2002  is supported at a body block  2010 , leaving the remaining portion of the vibrating tube element  2002  cantilevered to allow for the vibration utilized in the operation of the densitometer  2000 . The proximal portion of the tube element  2002 , which includes two open tube ends corresponding to two respective legs  2003 , is hermetically sealed with respect to the body block  2010  to prevent sample fluids from leaking as they pass into and out of the tube element  2002 . 
     Referring to the cross-sectional views of  FIGS. 4C and 4D  an electrical insulator  2015  couples the proximal end of each of the two legs of the vibrating tube element  2002  to the body block  2010 . This coupling  2015  mechanically supports the vibrating tube element  2002  and simultaneously provides electrical insulation to prevent electrical currents from passing from the body block  2010  or other portion of the densitometer  2000  to the vibrating tube element  2002  and vice-versa, thereby electrically isolating the vibrating tube element  2002  from the body block  2010 . This prevents electrical noise present in components such as conductive fluid delivery tubes and the body block  2010  from interfering with the electrical signals utilized with the vibrating tube element  2002  during density measurements. 
     As illustrated in  FIG. 4D , the electrical insulator  2015  extends along the proximal end portion of the leg  2003  of the vibrating tube element  2002 . The electrical insulator  2015  is formed of glass. In some examples, the electrical insulator  2015  is formed by glass frit bonding using doped glass powder. The doped glass powder has a low melting temperature (e.g., less than 450° C.) that will allow the doped glass powder to melt while avoiding melting of the body block  2010 . Such powders may be obtained commercial from, for example, Asahi Glass Co., LTD of Tokyo, Japan. 
     Although in some examples, the electrical insulator  2015  is a single monolithic component, the electrical insulator  2015  shown in  FIGS. 4C and 4D  is formed of two components. In particular, the insulator  2015  is formed of a doped glass body and a base body  2040 . It should be understood that the features corresponding to a cross section through the second leg  2003  are the same as the features described in connection with the cross section through the first leg  2003  illustrated in  FIGS. 4C and 4D , although in other examples, the features may differ between the two sides. 
     The doped glass powder is formed into a near-shape glass bead by compression molding. This near-shape bead is then placed in the position in the block  2010  where it is to provide an electrically insulative hermetic seal. In the illustrated example, the doped glass bead is placed into a channel  2011  in the block  2010  and corresponds to the general shape and position as the insulator  2015 . After the bead is placed in the channel  2011 , the vibrating tube element  2002  is inserted into the channel  2011  and into the bead. The structure is then heated to the melting point of the doped glass bead. During the heating and subsequent cooling, the doped glass will bond to the metal and became solid, thereby securing the tube  2002  in place relative to the block  2010 . 
     Referring to the example of  FIG. 4D , when the doped glass is in a liquid or non-rigid state during the melting process, the vibrating tube element  2002  is maintained in its position spaced apart from the annular channel wall  2011  by the base bodies  2040  which function as jigs, receiving the respective ends of the legs  2003 . The base bodies  2040  in the illustrated example are formed of an electrically insulative material (e.g., glass or ceramic) that has a melting temperature substantially higher than the melting temperature of the doped glass utilized to form the doped glass body. As such, when the densitometer module  2000  is heated to melt the doped glass to form the insulator doped glass body, the base bodies  2040  remain solid, thereby retaining adequate structure to maintain the insulator doped glass body in its position spaced apart from the channel  2011  of the block  2010  until the doped glass has cooled and solidified to produce the hermitically sealed solid insulator structure  2015 . The base body  2040  may also be utilized to block potential flow of the melted doped glass during the heating process. 
       FIGS. 5A and 5B  show a densitometer module  3000  that is analogous to the densitometer module  2000  except to the extent described otherwise. 
     The densitometer module  3000  differs in the structure of the base block  3010  and the insulator structure. Referring to the exploded view of  FIG. 5B  and the cross-sectional views of  FIGS. 5C and 5D , the channel  3011  has an enlarged section  3012  with a diameter that is larger than the remainder of the channel  3011 . This enlarged section  3012  receives a corresponding enlarged portion  3017  of the doped glass body  3016 . 
     Further, in addition to the base body  3040  and the doped glass body  3016 , the electrically insulating coupling  3015  further includes a cap body  3045 , which functions as a second jig disposed at the end of the doped glass body  3016  opposite the base body  3040 . This two-jig configuration—i.e., the base body  3040  and the cap body  3045 —serve to stably support the leg  3003  of the vibrating tube element  3002  during the melting of the doped glass and may also be utilized to resist flow of the liquefied or non-solid doped glass from its intended position during the heating process. 
     In the illustrated example, the cap body  3045  further receives and supports a mass block  3048 , which is coupled to the respective leg  3003  of the vibrating tube element  3002 . The mass block  3048  may be secured to the leg  3003  via the adhesion of the doped glass of the doped glass body  3016  and/or any other suitable coupling mechanism. In some examples, the mass block  3048  is present to provide additional vibrational isolation of the vibrating tube  3002  to improve performance during operation of the vibrating tube densitometer  3000  to measure fluid density. 
     In some examples, the presence of the mass block  3048 , in addition to the rigid connection of the mass block  3048  to the vibrating tube element  3002 , causes a standing wave node location at the location of the mass block  3048  during the vibration of the vibrating tube element  3002 . In this regard, the mass of the block  3048  coupled with the fact that its location corresponds to the vibrational node allows for electrical connections to be made without altering the vibrational properties of the vibrating tube element  3002 . For example, the electrical connections may be made directly to the electrically conductive mass blocks  3048 . Since the mass blocks  3048  are electrically coupled to the vibrating tube element  3002 , applying the electrical leads to the mass blocks  3048  provides a mechanism to apply an excitation current and/or measure vibrational response without having the physical electrical connection adversely impact the performance of the device. In particular, this structure allows for connecting the electrical leads without altering the resonance of the tube  3002 . 
     As with the base bodies  2040  described above, the base bodies  3040  and the cap bodies  3045  in the illustrated example are formed of an electrically insulative material (e.g., glass or ceramic) that has a melting temperature substantially higher than the melting temperature of the doped glass utilized to form the doped glass body  3016 . As such, when the densitometer  3000  is heated to melt the doped glass to form the doped glass body  3016 , the cap bodies  3045  remain solid, thereby retaining adequate structure to maintain the insulator  2015  in its position spaced apart from the channel  3011  of the block  2010  until the doped glass has cooled and solidified to produce the hermitically sealed solid insulator structure  2015 . It should be understood that the various instances of the base bodies  2040 ,  3040  and cap bodies  3045  in any given example may be formed of the same or different materials relative to each other. 
       FIG. 5E  shows a densitometer subassembly  3500  that includes the vibrating tube densitometer module  3000 . The subassembly  3500  further includes high-pressure sealed tube fittings  3155  that mate with receptacles  3050 , which are visible in  FIG. 5C , to couple a metal flowline to the sensor module  3000  in order to deliver sample fluids to and away from the vibrating tube element  3002  for density measurements. Because of the insulating coupling  3015 , any electrical noise that may be present in the flowline or other conductive structures is isolated from the vibrating tube element  3002  to prevent such noise from interfering with the density measurement during operation of the densitometer. At the same time, the insulating coupling  3015  maintains a hermetic seal between the flowline and the vibrating tube  3002  under operating conditions of the densitometer. The same features apply with regard to the insulating coupling  2015 . 
     The densitometer subassembly  3500  further includes a magnet unit  3100  that includes a mounting bracket  3105  having mounting flanges  3110 . The mounting flanges  3110  include recesses  3112  to receive alignment pins, and holes  3114  to receive fasteners  3610  to locate and secure the magnet unit  3100  to a base chassis  3605 , as shown in further detail in connection with  FIG. 5F . Similarly, the base block  3010  includes recesses  3013  to receive locating pins  3615 , and a hole  3014  to receive a fastener  3611  to locate and secure the densitometer module  3000  to the base chassis  3605 . Although various fasteners and locating devices may be described herein, it should be understood that any suitable assembly and/or manufacturing methods may be employed, and the present disclosure is in no way limited to the specific examples shown and described. 
     The magnet unit  3100  further includes a pair of magnets  3150  disposed on opposite sides of the vibrating tube element  3002  and adjacent to respective legs  3003  of the vibrating tube element  3002 . Magnets  3150  are oriented in the same polarized direction. As such, these two magnets  3150  are magnetically coupled in series. The magnets  3150  in the illustrated example are permanent magnets that are high temperature-resistant. 
     There is also a yoke  3160  disposed between the two legs  3003  of the vibrating tube element  3002 . The yoke acts to optimize the magnetic field of the magnets  3150  acting on the vibrating tube  3002 . The yoke  3160  and the mounting bracket  3105  are formed of a soft magnetic material such as a ferrous magnetic material. 
     The two magnets  3150 , the yoke  3160 , the mounting bracket  3105 , and two gaps  3153  form a magnetic circuit in the illustrated example. The gaps  3153  may be filled with air or any other suitable medium and are disposed between the yoke  3160  and a respective magnet  3150  for accommodating the legs  3003  of the vibrating tube  3002 . 
     Magnetic flux travels through the magnetic mounting bracket  3105  to the magnet  3150  and through gap  3153  resulting in a closed-loop magnetic circuit. In this regard, the element  3105  is not only a mounting bracket but also a magnetic flux path to enhance permeance of the magnetic circuit. 
     The magnets  3150  and the yoke  3160  are mounted to a block  3170  which is attached to the mounting bracket  3105 . The block  3170  acts to secure and locate the magnets  3150  and yoke  3160  relative to each other and, as a result of the various components being mounted to the base chassis  3605  as shown in  FIG. 5F , relative to the vibrating tube element  3002 . This spacing and locating allows the magnets  3150  and yoke  3160  to act on the vibrating tube  3002  without coming into contact with the tube  3002  as it vibrates during density measurements. It should be understood that although an example of a magnet configuration is provided in connection with  FIG. 5E , other magnet configurations may be provided. For example, for different resonances, different magnet positioning and arrangement may be provided. Some examples do not employ a yoke. Some examples include a single magnet or more than two magnets. 
       FIG. 5F  shows a densitometer assembly  3600  that incorporates the subassembly  3500 . In particular, the subassembly  3500  is mounted to the base chassis  3605  via fasteners  3610  and  3600  and the locating pins as discussed above. The assembly  3600  further includes a sensor front end circuit board  3620 . The front-end circuit board  3620  is mounted to the base chassis  3605  via fasteners  3625 , and the base chassis  3605  is attached to a base tool via fasteners  3630 . As with the other fasteners  3610  and  3611  described above, the fasteners  3625  and  3630  may be bolts or any other suitable fasteners. 
     The tubing  2002 ,  3002  may have an outer diameter of 1 mm or less in some non-limiting examples. The tubing  2002  may be made of stainless steel, Hastelloy, medical grade tubing, etc. In some examples, the tubing  2002  and/or other metallic components may be made of spring metal such as SPRON, developed by Seiko Instruments Inc. 
     The electrical isolation structures illustrated, for example, in  FIGS. 4D and 5D  function to fluidically and hydraulically connect the metal tubes  2002  and  3002  while maintaining electrical isolation of the tubes  2002  and  3002  with respect to the inlet tubes and other conductive structures external to the tubes  2002  and  2003 . 
     In some examples, the block  2010 ,  3010  is metal (e.g., aluminum or stainless steel), although the block may be formed of any other suitable material. 
     Referring again to  FIG. 5E , the vibrating tube element  3002  mounted in the body block  3010  and wrapped about a yoke  3160  and between magnets  3150  such as, for example, SmCo permanent magnets, wherein an alternating current is driven through the tube element  3002  and the resulting Lorentz force provides actuation to drive the tube  3002  in a torsional mode and the resulting electromagnetic field (EMF) (Faraday&#39;s law) is proportional to the tube velocity. 
     It is noted that motion may be monitored by measuring the small EMF voltage that develops due to Faraday&#39;s law. Example embodiments of the densitometer are operable to high pressures up to 15,000 psi or more and high temperatures up to 150° C. or more for determining measurements in a tube having an outer diameter approximately 1/32″ along with a fluid sampling volume of less than 20 microliters. It is noted that temperatures in some oilfield applications may reach 150° C. (it is noted the temperatures could be as high as 350° C.) along with pressures of 15,000 psi (it is also noted the pressures could be as high as 35,000 psi). Further, the diameter of the tube can be greater or less and the fluid sampling volume may be up to, for example, 1000 micro-liters. Further still, the tubes used in this densitometer configuration are made of stainless steel or other related materials having similar properties. However, other types of metals may be used (for example, titanium, nickel and related alloys). It is further noted that the above-described glass insulator configurations are also able to withstand the aforementioned pressure and temperature conditions, such as may be found, for example, downhole during open-hole operations. 
     In the illustrated example, each leg  2003 ,  3003  of the tube  2002 ,  3002  is of approximately length 4.5 cm. The end of the tube  2002 ,  3002  may be bent into a half circle of an approximate diameter of 1 cm so as to create an approximate total internal volume of approximately 20 μl (as noted above the total internal volume may be approximately up to 1000 μl. However, alternative shapes and dimensions for the tube may be provided, such as a straight tube or a tube with differing bends. The body block  2010 ,  3010  may be secured in the downhole housing by any suitable fastening mechanism (e.g., screws, adhesive, soldering, welding, brazing, etc.) and in some examples electrically isolated from the downhole housing. 
     A typical high-pressure fluidic system connects a metal flowline to the electrical ground plane, thereby introducing stray impedances which would alter if not completely ruin the signal used here to measure fluid density. Thus, the glass insulators  2015 ,  3015  are provided to electrically isolate the two coupled tubes, along with being capable of operating in high shock and high temperature device conditions. In contrast with some other potential solutions, the electrical isolation structure of, e.g.,  FIGS. 4D and 5D  provide electrical isolation without adding an unacceptable amount of dead volume. Since these sensors are considered to be microfluidic, the addition of a significant amount of dead volume (e.g. greater than a few, e.g., 3, microliters) would render the sensor inoperable in some intended microfluidic applications or would require greater flushing volume. 
     Electrical connections to the tube  3002  may be provided in the form of, referring to  FIG. 5G , wires  3640 , may be soldered or otherwise attached to be in electrical communication with respective legs of the tube  3002 . As indicated above, the connection of the electrical leads at the mass blocks  3048  in the illustrated example allows for an electrical connection that does not mechanically affect the vibrational properties of the tube  3002  by, for example, altering the relevant resonance frequency of the tube  3002  in the absence of such connection. 
     An electrical control system  3650 , which may be, for example, front end circuit board  3620 , is connected to the electrical connections  3640  to provide the voltage and current across the electrical leads and corresponding legs of the tube element  3002  to induce the aforementioned vibrations. The control system  3650  is also configured to measure the resulting EMF, which is in turn used to determine the density of the fluid present in the vibrating tube element  3002 . In this regard, the EMF reflects the resonant frequency of the tube  3002  together with the sample fluid inside the tube  3002 . Since this frequency varies as a function of the density of the sample fluid in the tube  3002 , it provides a mechanism by which to measure the density of the fluid. It should be understood that instead of a single unit  3650  that drives the current and senses the EMF, separate systems may be provided. Moreover, alternatively or additionally, the frequency of the vibrating tube  3002  may be measured by any other suitable mechanism, e.g., using optical detection.  FIG. 5H  shows an example of an optical detection system  3700  including a light source  3705  and a light sensor  3710 . In this arrangement, the signal generated from the light sensor  3710  varies as a function of the frequency at which the tube  3002  vibrates. Accordingly, the control system  3650  can process the signal to determine the frequency. 
     It is further noted that in addition to the vibration, the control system of the illustrated example, factors in temperature and pressure in determining the density of the fluid. 
     Additional details of the operation of the densitometer configurations  2000  and  3500  may be found in U.S. Patent Application Publication No. 2010/0268469, which is incorporated herein by reference in its entirety and provides an analogous densitometer structure and function, but without, for example, the glass isolator configuration of the present application. 
     Further details of using the PVT apparatus in conjunction with a wellbore tool and methods for implementing the PVT apparatus are described in U.S. Patent Application Publication No. 2014/0260586 and PCT International Publication No. WO 2014/158376, each of which is incorporated herein by reference in its entirety. 
     The methods and processes described above such as, for example, operation of valves and pistons and the performance of the various described fluid analyses, may be performed by a processing system. The processing system may correspond at least in part to element  3650  described above. The term “processing system” should not be construed to limit the embodiments disclosed herein to any particular device type or system. The processing system may include a single processor, multiple processors, or a computer system. Where the processing system includes multiple processors, the multiple processors may be disposed on a single device or on different devices at the same or remote locations relative to each other. The processor or processors may include one or more computer processors (e.g., a microprocessor, microcontroller, digital signal processor, or general-purpose computer) for executing any of the methods and processes described above. The computer system may further include a memory such as a semiconductor memory device (e.g., a RAM, ROM, PROM, EEPROM, or Flash-Programmable RAM), a magnetic memory device (e.g., a diskette or fixed disk), an optical memory device (e.g., a CD-ROM), a PC card (e.g., PCMCIA card), or other memory device. 
     The methods and processes described above may be implemented as computer program logic for use with the computer processor. The computer processor may be for example, part of a system such as system  100  described above. The computer program logic may be embodied in various forms, including a source code form or a computer executable form. Source code may include a series of computer program instructions in a variety of programming languages (e.g., an object code, an assembly language, or a high-level language such as C, C++, Matlab, JAVA or other language or environment). Such computer instructions can be stored in a non-transitory computer readable medium (e.g., memory) and executed by the computer processor. The computer instructions may be distributed in any form as a removable storage medium with accompanying printed or electronic documentation (e.g., shrink wrapped software), preloaded with a computer system (e.g., on system ROM or fixed disk), or distributed from a server or electronic bulletin board over a communication system (e.g., the Internet or World Wide Web). 
     Alternatively or additionally, the processing system may include discrete electronic components coupled to a printed circuit board, integrated circuitry (e.g., Application Specific Integrated Circuits (ASIC)), and/or programmable logic devices (e.g., a Field Programmable Gate Arrays (FPGA)). Any of the methods and processes described above can be implemented using such logic devices. 
     Any of the methods and processes described above can be implemented as computer program logic for use with the computer processor. The computer program logic may be embodied in various forms, including a source code form or a computer executable form. Source code may include a series of computer program instructions in a variety of programming languages (e.g., an object code, an assembly language or a high-level language such as C, C++ or JAVA). Such computer instructions can be stored in a non-transitory computer readable medium (e.g., memory) and executed by the computer processor. The computer instructions may be distributed in any form as a removable storage medium with accompanying printed or electronic documentation (e.g., shrink wrapped software), preloaded with a computer system (e.g., on system ROM or fixed disk), or distributed from a server or electronic bulletin board over a communication system (e.g., the Internet or World Wide Web). 
     To the extent used in this description and in the claims, a recitation in the general form of “at least one of [a] and [b]” should be construed as disjunctive. For example, a recitation of “at least one of [a], [b], and [c]” would include [a] alone, [b] alone, [c] alone, or any combination of [a], [b], and [c]. 
     Although a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from embodiments disclosed herein. Accordingly, all such modifications are intended to be included within the scope of this disclosure.