Evaluating multiphase fluid flow in a wellbore using temperature and pressure measurements

Abstract

A system, method and program product for analyzing multiphase flow in a wellbore. A system is provided that includes: an input system for receiving pressure and temperature readings from a pair of sensors located in the wellbore; a computation system that utilizes a flow analysis model to generate a set of wellbore fluid properties, wherein the set of wellbore fluid properties includes at least one of: a fluid mixture value, a phase velocity value, a flow rate, a mixture density, a mixture viscosity, a fluid holdup, and a slip velocity; and a system for outputting the wellbore fluid properties.

1 . A system for analyzing multiphase flow in a wellbore, comprising:
 an input system for receiving pressure and temperature readings from a pair of sensors located in the wellbore;   a computation system that utilizes a flow analysis model to generate a set of wellbore fluid properties from the pressure and temperature readings, wherein the set of wellbore fluid properties includes at least one of: a fluid mixture value, a phase velocity value, a flow rate, a mixture density, a mixture viscosity, a fluid holdup, and a slip velocity; and   a system for outputting the wellbore fluid properties.   
     
     
         2 . The system of  claim 1 , wherein the pair of sensors are permanently mounted in the wellbore. 
     
     
         3 . The system of  claim 1 , further comprising a contribution analysis system for analyzing pressure and temperature from a plurality of sensor pairs to provide wellbore fluid properties for different inflow zones and/or branches of a multiple production zone well. 
     
     
         4 . The system of  claim 1 , wherein the flow analysis model includes a single-phase flow model that utilizes three equations to solve for a fluid superficial velocity (V si ), a Reynolds number (N Re ), and a Fanning friction factor (f). 
     
     
         5 . The system of  claim 1 , wherein the flow analysis model includes a two-phase oil-water flow model that utilizes 10 equations to solve for: oil and water holdups, oil, water, and mixture superficial velocities, mixture density and dynamic viscosity, a slip velocity between oil and water phases, a Reynolds number and Fanning friction factor, and a pressure loss that occurs over a metering length of a flow conduit. 
     
     
         6 . The system of  claim 1 , wherein the flow analysis model includes a two-phase gas-oil flow model that utilizes 10 equations to solve for: oil and gas holdups, superficial velocities, a mixture superficial velocity, density and viscosity, a gas-liquid slip velocity, a Reynolds number and a Fanning friction factor. 
     
     
         7 . The system of  claim 1 , wherein the flow analysis model includes a two-phase water-gas flow model that utilizes 10 equations to solve for: water and gas holdups, water and gas superficial velocities, a mixture superficial velocity, density and dynamic viscosity, a gas-liquid slip velocity, a Reynolds number and a Fanning friction factor. 
     
     
         8 . The system of  claim 1 , wherein the flow analysis model includes a three-phase flow model that utilizes 13 equations to solve for: holdups for oil, water and gas phases, superficial velocities of oil, water and gas, a mixture superficial velocity, a mixture density, a viscosity, a Reynolds number, a friction factor, a water-oil slip velocity and a gas-liquid slip velocity. 
     
     
         9 . The system of  claim 1 , wherein said wellbore is used to produce formation fluids or to inject fluids into a formation. 
     
     
         10 . The system of  claim 1 , wherein said computation system calibrates one or more of said wellbore fluid properties using data obtained from a retrievable production logging device. 
     
     
         11 . A method for analyzing multiphase flow in a wellbore, comprising:
 obtaining pressure and temperature readings from a pair of sensors located in the wellbore;   utilizing a flow analysis model to generate a set of wellbore fluid properties from the pressure and temperature readings, wherein the set of wellbore fluid properties includes at least one of: a fluid mixture value, a phase velocity value, a flow rate, a mixture density, a mixture viscosity, a fluid holdup, and a slip velocity; and   outputting the wellbore fluid properties.   
     
     
         12 . The method of  claim 11 , wherein the pair of sensors are permanently mounted in the wellbore. 
     
     
         13 . The method of  claim 11 , further comprising analyzing pressure and temperature from a plurality of sensor pairs to provide wellbore fluid properties for different inflow zones and/or branches of a multiple production zone well. 
     
     
         14 . The method of  claim 11 , wherein the flow analysis model includes a single-phase flow model that utilizes three equations to solve for a fluid superficial velocity, a Reynolds number, and a Fanning friction factor. 
     
     
         15 . The method of  claim 11 , wherein the flow analysis model includes a two-phase oil-water flow model that utilizes 10 equations to solve for: oil and water holdups, oil, water, and mixture superficial velocities, mixture density and dynamic viscosity, a slip velocity between oil and water phases, a Reynolds number and Fanning friction factor, and a pressure loss that occurs over a metering length of a flow conduit. 
     
     
         16 . The method of  claim 11 , wherein the flow analysis model includes a two-phase gas-oil flow model that utilizes 10 equations to solve for: oil and gas holdups, superficial velocities, a mixture superficial velocity, density and viscosity, a gas-liquid slip velocity, a Reynolds number and a Fanning friction factor. 
     
     
         17 . The method of  claim 11 , wherein the flow analysis model includes a two-phase water-gas flow model that utilizes 10 equations to solve for: water and gas holdups, water and gas superficial velocities, a mixture superficial velocity, density and dynamic viscosity, a gas-liquid slip velocity, a Reynolds number and a Fanning friction factor. 
     
     
         18 . The method of  claim 11 , wherein the flow analysis model includes a three-phase flow model that utilizes 13 equations to solve for: holdups for oil, water and gas phases, superficial velocities of oil, water and gas, a mixture superficial velocity, a mixture density, a viscosity, a Reynolds number, a friction factor, a water-oil slip velocity and a gas-liquid slip velocity. 
     
     
         19 . The method of  claim 11 , wherein said wellbore is used to produce formation fluids or to inject fluids into a formation. 
     
     
         20 . The system of  claim 11 , wherein data obtained from a retrievable production logging device is used to calibrate one or more of said wellbore fluid properties. 
     
     
         21 . A computer readable medium for storing a computer program product, which when executed by a computer system analyzes multiphase flow in a wellbore, comprising:
 program code for inputting pressure and temperature readings from a pair of sensors located in the wellbore;   program code for implementing a flow analysis model to generate a set of wellbore fluid properties from the pressure and temperature readings, wherein the set of wellbore fluid properties includes at least one of: a fluid mixture value, a phase velocity value, a flow rate, a mixture density, a mixture viscosity, a fluid holdup, and a slip velocity; and   program code for outputting the wellbore fluid properties.   
     
     
         22 . The computer readable medium of  claim 21 , wherein the wellbore fluid properties are outputted in an on-demand manner. 
     
     
         23 . The computer readable medium of  claim 21 , wherein the pair of sensors are permanently mounted in the wellbore. 
     
     
         24 . The computer readable medium of  claim 21 , further comprising program code for analyzing pressure and temperature from a plurality of sensor pairs to provide wellbore fluid properties for different branches of a multiple production zone well. 
     
     
         25 . The computer readable medium of  claim 21 , wherein the flow analysis model includes a single-phase flow model that utilizes three equations to solve for a fluid superficial velocity, a Reynolds number, and a Fanning friction factor. 
     
     
         26 . The computer readable medium of  claim 21 , wherein the flow analysis model includes a two-phase oil-water flow model that utilizes 10 equations to solve for: oil and water holdups, oil, water, and mixture superficial velocities, mixture density and dynamic viscosity, a slip velocity between oil and water phases, a Reynolds number and Fanning friction factor, and a pressure loss that occurs over a metering length of a flow conduit. 
     
     
         27 . The computer readable medium of  claim 21 , wherein the flow analysis model includes a two-phase gas-oil flow model that utilizes 10 equations to solve for: oil and gas holdups, superficial velocities, a mixture superficial velocity, density and viscosity, a gas-liquid slip velocity, a Reynolds number and a Fanning friction factor. 
     
     
         28 . The computer readable medium of  claim 21 , wherein the flow analysis model includes a two-phase water-gas flow model that utilizes 10 equations to solve for: water and gas holdups, water and gas superficial velocities, a mixture superficial velocity, density and dynamic viscosity, a gas-liquid slip velocity, a Reynolds number and a Fanning friction factor. 
     
     
         29 . The computer readable medium of  claim 21 , wherein the flow analysis model includes a three-phase flow model that utilizes 13 equations to solve for: holdups for oil, water and gas phases, superficial velocities of oil, water and gas, a mixture superficial velocity, a mixture density, a viscosity, a Reynolds number, a friction factor, a water-oil slip velocity and a gas-liquid slip velocity. 
     
     
         30 . The computer readable medium of  claim 21 , further including program code for calibrating one or more of said wellbore fluid properties using data obtained from a retrievable production logging device.