Systems and methods for inferring reservoir pressure based on initial coiled tubing run conditions

Abstract

Systems and methods presented herein facilitate coiled tubing operations, and generally relate to automatically improving performance of coiled tubing operations in substantially real time by inferring reservoir pressure based on initial coiled tubing run conditions. For example, a method includes performing a coiled tubing operation via a coiled tubing system at least partially disposed within a wellbore. The method also includes detecting data relating to operating parameters of the coiled tubing operation via sensors of the coiled tubing system during the coiled tubing operation. The method further includes determining an initial wellbore fluid distribution in the wellbore based on the detected data prior to pumping fluid into the wellbore from a surface location relative to the wellbore. In addition, the method includes inferring a reservoir pressure of a hydrocarbon-bearing reservoir through which the wellbore extends based on the initial wellbore fluid distribution in the wellbore.

1 . A method, comprising:
 receiving data relating to one or more operating parameters of a coiled tubing operation;   determining an average density of a fluid mixture in a wellbore between a bottom hole assembly (BHA) of a coiled tubing system and a downhole pressure gauge based at least in part on the received data; and   inferring a reservoir pressure of a reservoir through which the wellbore extends based at least in part on the average density of the fluid mixture in the wellbore between the BHA of the coiled tubing system and the downhole pressure gauge.   
     
     
         2 . The method of  claim 1 , wherein the data is received prior to pumping fluid into the wellbore from a surface location relative to the wellbore. 
     
     
         3 . The method of  claim 1 , comprising automatically optimizing the coiled tubing operation based on inferred reservoir pressure. 
     
     
         4 . The method of  claim 1 , comprising automatically optimizing a subsequent tubing operation based on inferred reservoir pressure. 
     
     
         5 . The method of  claim 1 , wherein the reservoir pressure is inferred by assuming that a measured depth of an oil-water interface in the wellbore is greater than or equal to a measured depth of the downhole pressure gauge when the average density of the fluid mixture in the wellbore between the BHA of the coiled tubing system and the downhole pressure gauge is less than or equal to a density of oil in the fluid mixture. 
     
     
         6 . The method of  claim 1 , wherein the reservoir pressure is inferred by assuming that a measured depth of an oil-water interface in the wellbore is approximately equal to a measured depth of a gas-oil interface in the wellbore when the average density of the fluid mixture in the wellbore between the BHA of the coiled tubing system and the downhole pressure gauge is greater than a density of oil in the fluid mixture. 
     
     
         7 . The method of  claim 1 , wherein the reservoir pressure is inferred based at least in part on a calculated measured depth of an oil-water interface in the wellbore when the average density of the fluid mixture in the wellbore between the BHA of the coiled tubing system and the downhole pressure gauge is greater than a density of oil in the fluid mixture and the average density of the fluid mixture in the wellbore between the BHA of the coiled tubing system and the downhole pressure gauge is less than a density of water in the fluid mixture. 
     
     
         8 . The method of  claim 1 , comprising determining an initial wellbore fluid distribution in the wellbore based on the detected data. 
     
     
         9 . The method of  claim 8 , wherein the initial wellbore fluid distribution is determined prior to pumping fluid into the wellbore. 
     
     
         10 . A method, comprising:
 determining an average density of a fluid mixture in a wellbore between a bottom hole assembly (BHA) of a coiled tubing system and a downhole pressure gauge;   inferring a reservoir pressure of a reservoir through which the wellbore extends based at least in part on the average density of the fluid mixture in the wellbore between the BHA of the coiled tubing system and the downhole pressure gauge; and   optimizing a coiled tubing operation based on the inferred reservoir pressure.   
     
     
         11 . The method of  claim 10 , comprising receiving data relating to one or more operating parameters of a coiled tubing operation. 
     
     
         12 . The method of  claim 11 , wherein the average density is determined based on the received data. 
     
     
         13 . The method of  claim 10 , wherein optimizing the coiled tubing operation comprises automatically adjusting an operating parameter of the coiled tubing system based on the 
     
     
         14 . The method of  claim 10 , wherein the average density of the fluid mixture in the wellbore between the BHA of the coiled tubing system and the downhole pressure gauge is measured when a density of a fluid in an annulus around the BHA of the coiled tubing system is not approximately equal to a density of gas in the fluid mixture. 
     
     
         15 . The method of  claim 10 , comprising setting a measured depth of a gas-oil interface in the wellbore equal to a measured depth of the BHA of the coiled tubing system, and running the coiled tubing system into the wellbore and updating a measured depth of the BHA of the coiled tubing system when the density of the fluid in the annulus around the BHA of the coiled tubing system is approximately equal to the density of gas in the fluid mixture. 
     
     
         16 . A method, comprising
 prior to pumping fluid into a wellbore:
 determining an initial wellbore distribution in the wellbore; 
 determining an average density of a fluid mixture in the wellbore between a bottom hole assembly (BHA) of a coiled tubing system and a downhole pressure gauge; and 
 inferring a reservoir pressure of a reservoir through which the wellbore extends based at least in part on the average density of the fluid mixture in the wellbore between the BHA of the coiled tubing system and the downhole pressure gauge and the initial wellbore distribution. 
   
     
     
         17 . The method of  claim 16 , comprising optimizing a coiled tubing operation based on the inferred reservoir pressure. 
     
     
         18 . The method of  claim 16 , comprising receiving data relating to one or more operating parameters of a coiled tubing operation. 
     
     
         19 . The method of  claim 18 , wherein the initial wellbore distribution is determined based on the received data. 
     
     
         20 . The method of  claim 18 , wherein the received data is detected via one or more sensors of the coiled tubing system.