Thermal Modulated Vibrating Sensing Module for Gas Molecular Weight Detection

Abstract

A downhole formation fluid identification sensing module for measuring averaged gas molecular weight of wellbore formation fluid acquires simultaneous temperature, pressure, and density measurements. The sensing module includes two venturi-type gas sensors that both contain vibrating tubes. During operation, formation fluid flows through the vibrating tubes whereby resonant frequency measurements are acquired simultaneously with temperature and pressure measurements. Each measurement is then utilized to determine the gas molecular weight of the dry, wet or saturated formation fluid.

What is claimed is: 
     
         1 . A method to determine gas molecular weight of wellbore formation fluid, the method comprising:
 receiving wellbore formation fluid into a sensing module comprising:
 a first sensor comprising a tube; and 
 a second sensor comprising a tube; 
   vibrating the tubes of the first and second sensors;   communicating the wellbore formation fluid through the first and second vibrating tubes;   acquiring vibrational measurements of the wellbore formation fluid flowing through the vibrating tubes; and   utilizing the vibrational measurements to determine the gas molecular weight of the wellbore formation fluid.   
     
     
         2 . A method as defined in  claim 1 , wherein acquiring the vibrational measurements comprises:
 acquiring a first resonant frequency of the vibrating tube of the first sensor as the wellbore formation fluid flows therethrough;   acquiring a second resonant frequency of the vibrating tube of the second sensor as the wellbore fluid flows therethrough;   acquiring temperature and pressure measurements of the wellbore formation fluid; and
 utilizing a differentiation between the first and second resonant frequencies to determine a gas density measurement of the wellbore formation fluid. 
   
     
     
         3 . A method as defined in  claim 2 , wherein the gas density, temperature, and pressure measurements of the wellbore formation fluid are acquired simultaneously. 
     
     
         4 . A method as defined in  claim 1 , further comprising maintaining the first and second sensors under an isothermal condition. 
     
     
         5 . A method as defined in  claim 1 , wherein the first and second sensors are maintained at a same temperature. 
     
     
         6 . A method as defined in  claim 1 , wherein the first and second temperatures are maintained at different temperatures. 
     
     
         7 . A method as defined in  claim 1 , wherein vibrating the tubes comprises activating an excitation mechanism positioned on the tubes. 
     
     
         8 . A method as defined in  claim 1 , further comprising utilizing the gas molecular weight to identify the wellbore formation fluid. 
     
     
         9 . A method as defined in  claim 1 , further comprising utilizing the gas molecular weight to predict phase behavior of the wellbore formation fluid. 
     
     
         10 . A method as defined in  claim 1 , wherein the sensing module is deployed into a wellbore. 
     
     
         11 . A method as defined in  claim 10 , wherein the gas molecular weight of the wellbore formation fluid is determined in-situ. 
     
     
         12 . A method to determine gas molecular weight of wellbore formation fluid, the method comprising:
 receiving a wellbore formation fluid into a sensing module comprising a tube;   vibrating the tube;   communicating the wellbore formation fluid into the vibrating tube;   acquiring vibrational measurements of the wellbore fluid flowing through the vibrating tube; and   utilizing the vibrational measurements to determine the gas molecular weight of the wellbore fluid.   
     
     
         13 . A method as defined in  claim 12 , wherein acquiring the vibrational measurements comprises simultaneously acquiring a gas density measurement, temperature measurement, and pressure measurement of the wellbore fluid. 
     
     
         14 . A method as defined in  claim 13 , further comprising maintaining the sensing module under an isothermal condition with an operation temperature maximum allowed by a downhole logging service tool. 
     
     
         15 . A method as defined in  claim 12 , wherein vibrating the tube comprises activating an excitation mechanism positioned on the tube. 
     
     
         16 . A method as defined in  claim 12 , further comprising utilizing the gas molecular weight to identify the wellbore formation fluid. 
     
     
         17 . A method as defined in  claim 12 , further comprising utilizing the gas molecular weight to predict phase behavior of the wellbore fluid. 
     
     
         18 . A method as defined in  claim 12 , wherein:
 the sensing module comprises a first and second gas sensor, each of the first and second gas sensors comprising a tube;   vibrating the tube comprises vibrating the tubes of the first and second sensors;   communicating the wellbore fluid into the vibrating tube comprises:
 communicating the wellbore formation fluid into the vibrating tube of the first sensor; and 
 communicating the wellbore formation fluid into the vibrating tube of the second sensor; 
   acquiring vibrational measurements of the wellbore fluid comprises:
 acquiring temperature and pressure measurements of the wellbore fluid traveling through the vibrating tube of the first sensor; 
 acquiring a first gas density measurement of the wellbore fluid traveling through the vibrating tube of the first sensor; 
 acquiring temperature and pressure measurements of the wellbore fluid traveling through the vibrating tube of the second sensor; and 
 acquiring a second gas density measurement of the wellbore fluid traveling through the vibrating tube of the second sensor; and 
   determining the gas molecular weight of the wellbore fluid is achieved using a differentiation of the first and second gas density measurements.   
     
     
         19 . A method as defined in  claim 12 , wherein:
 the sensing module comprises a first and second gas sensor arranged in series configuration with relation to one another, the first and second sensors each comprising a tube;   vibrating the tube comprises vibrating the tubes of the first and second sensors;   communicating the wellbore formation fluid into the vibrating tube comprises:
 communicating the wellbore formation fluid into the vibrating tube of the first sensor; and 
 communicating the wellbore formation fluid into the vibrating tube of the second sensor; 
   acquiring vibrational measurements of the wellbore formation fluid comprises:
 acquiring inlet temperature and pressure measurements of the wellbore fluid entering the first sensor; 
 acquiring a first gas density measurement of the wellbore fluid as the wellbore fluid travels through the vibrating tube of the first sensor; 
 acquiring a second gas density measurement of the wellbore fluid as the wellbore fluid travels through the vibrating tube of the second sensor; and 
 acquiring outlet temperature and pressure measurements of the wellbore formation fluid exiting the second sensor; and 
   determining the gas molecular weight of the wellbore formation fluid is achieved using a differentiation of the first and second gas density measurements.   
     
     
         20 . A method as defined in  claim 12 , wherein:
 the sensing module comprises a first and second sensor arranged in parallel configuration with relation to one another, the first and second sensors each comprising a tube;   vibrating the tube comprises vibrating the tubes of the first and second sensors;   communicating the wellbore formation fluid into the vibrating tube comprises:
 communicating the wellbore fluid into the vibrating tube of the first sensor; and 
 communicating the wellbore formation fluid into the vibrating tube of the second sensor; 
   acquiring vibrational measurements of the wellbore formation fluid comprises:
 acquiring inlet temperature and pressure measurements of the wellbore formation fluid entering the first sensor; 
 acquiring inlet temperature and pressure measurements of the wellbore formation fluid entering the second sensor; 
 acquiring a first gas density measurement of the wellbore formation fluid as the wellbore formation fluid flows through the vibrating tube of the first sensor; 
 acquiring a second gas density measurement of the wellbore formation fluid as the wellbore fluid flows through the vibrating tube of the second sensor; 
 acquiring outlet temperature and pressure measurements of the wellbore fluid exiting the first sensor; and 
 acquiring outlet temperature and pressure measurements of the wellbore fluid exiting the second sensor; and 
   determining the gas molecular weight of the wellbore formation fluid is achieved using a differentiation of the first and second gas density measurements.   
     
     
         21 . A method as defined in  claim 12 , wherein the sensing module is deployed into a wellbore. 
     
     
         22 . A method as defined in  claim 12 , wherein communicating the wellbore formation fluid into the vibrating tube comprises utilizing a coalesce filter to remove particles from the wellbore formation fluid before communicating the wellbore formation fluid into the vibrating tube. 
     
     
         23 . A method as defined in  claim 12 , communicating the wellbore formation fluid into the vibrating tube comprises utilizing a low-density PTFE or high-density polyethylene filter to separate gas/liquid phases of the wellbore formation fluid before communicating the wellbore formation fluid into the vibrating tube. 
     
     
         24 . A sensing module to determine gas molecular weight of wellbore formation fluid, the sensing module comprising:
 a first sensor comprising:
 a vibrating tube through which wellbore formation fluid may flow; and 
 a vibrational excitation mechanism positioned on the tube; and 
   a second sensor comprising:
 a vibrating tube through which wellbore fluid may flow; and 
 a vibrational excitation mechanism positioned on the tube. 
   
     
     
         25 . A sensing module as defined in  claim 24 , wherein the first and second sensors each comprise:
 a hollow tube body having first and second ends;   a venturi inlet positioned at the first end; and   a venturi outlet positioned at the second end,   wherein the vibrating tube is coupled between the venturi inlet and outlet.   
     
     
         26 . A sensing module as defined in  claim 25 , wherein the hollow tube body comprises a heating element. 
     
     
         27 . A sensing module as defined in  claim 26 , further comprising:
 is a first temperature sensor embedded within the heating element; and   a second temperature sensor positioned inside the hollow tube body.   
     
     
         28 . A sensing module as defined in  claim 26 , wherein the second temperature sensor comprises part of a temperature control loop feedback mechanism. 
     
     
         29 . A sensing module as defined in  claim 24 , further comprising processing circuitry operationally coupled to the vibrational excitation mechanism to thereby communicate electrical signals therebetween. 
     
     
         30 . A sensing module as defined in  claim 24 , wherein the vibrational excitation mechanism is at least one of a magnetic assembly or coil assembly. 
     
     
         31 . A sensing module as defined in  claim 24 , wherein the first and second sensors are arranged in series configuration relative to one another. 
     
     
         32 . A sensing module as defined in  claim 31 , wherein the sensing module further comprises:
 a flow inlet coupled to the venturi inlet of the first sensor; and   a flow outlet coupled to the venturi outlet of the second sensor.   
     
     
         33 . A sensing module as defined in  claim 24 , wherein the first and second sensors are arranged in parallel configuration relative to one another. 
     
     
         34 . A sensing module as defined in  claim 33 , wherein the sensing module further comprises:
 a flow inlet coupled to the venturi inlets of the first and second sensors; and   a flow outlet coupled to the venturi outlets of the first and second sensors.   
     
     
         35 . A sensing module as defined in  claim 24 , further comprising:
 a coalesce or polymer filter coupled to a flow inlet of the sensing module; and   a pressure and flow control mechanism coupled to the flow inlet and a flow outlet of the sensing module.   
     
     
         36 . A sensing module as defined in  claim 24 , wherein the sensing module forms part of a downhole assembly. 
     
     
         37 . A sensing module as defined in  claim 24 , wherein the vibrating tubes of the first and second sensors comprises a Ti or Ti-alloy, or a carbon fiber reinforced polymer composite material based high-strength tube.