Determining Depth of Loss Zones in Subterranean Formations

Abstract

A method includes injecting a treatment fluid through a tubular in a wellbore created in a subterranean formation, wherein the treatment fluid is to return through an annulus defined between the tubular and a wall of the wellbore. The method includes logging, during the injecting, measurements comprising at least one of an actual wellhead pressure; treatment fluid inlet density, inlet flow rate, outlet flow rate, and treatment fluid inlet viscosity. The method includes determining a loss zone location in the wellbore based on the measurements.

What is claimed is: 
     
         1 . A method comprising:
 injecting a treatment fluid through a tubular in a wellbore created in a subterranean formation, wherein the treatment fluid is to return through an annulus defined between the tubular and a wall of the wellbore;   logging, during the injecting, measurements comprising at least one of an actual wellhead pressure; treatment fluid inlet density, inlet flow rate, outlet flow rate, and treatment fluid inlet viscosity; and   determining a loss zone location in the wellbore based on the measurements.   
     
     
         2 . The method of  claim 1 , further comprising:
 determining a calculated wellhead pressure based on the measurements; and   calculating a wellhead pressure differential based on a difference between the calculated wellhead pressure and the actual wellhead pressure,   wherein determining the loss zone location is based on the wellhead pressure differential.   
     
     
         3 . The method of  claim 2 , further comprising
 calculating a flowrate loss based on a difference between the inlet flow rate and the outlet flow rate, wherein determining the loss zone location is based on the wellhead pressure differential.   
     
     
         4 . The method of  claim 1 , wherein the treatment fluid comprises at least one of a non-aqueous fluid, an aqueous fluid, an aqueous-miscible fluid, a water-in-oil emulsion, and an oil-in-water emulsion. 
     
     
         5 . The method of  claim 1 , wherein the tubular comprises at least one of a casing string, a flexible tubing, an inflexible tubing, and a drill string. 
     
     
         6 . The method of  claim 1 , further comprising:
 performing a remedial operation to at least partially seal the loss zone location in the wellbore.   
     
     
         7 . The method of  claim 6 , wherein the remedial operation comprises at least one of ceasing operations, removing the treatment fluid from the wellbore, reformulating the treatment fluid, introducing a loss circulation pill into the wellbore, reducing the inlet flow rate, and increasing the inlet flow rate. 
     
     
         8 . The method of  claim 1 , further comprising:
 performing a preventative operation to at least partially seal a different loss zone location in a different wellbore based on the loss zone location in the wellbore.   
     
     
         9 . The method of  claim 8 , wherein the preventative operation comprises at least one of introducing a loss circulation material into the different wellbore, reducing the inlet flow rate, increasing the inlet flow rate, adjusting the wellbore geometry, and adjusting the location of the different wellbore. 
     
     
         10 . A system comprising:
 a tubular to be positioned in a wellbore created in a subterranean formation, wherein a treatment fluid is to be injected through the tubular and to return through an annulus defined between the tubular and a wall of the wellbore;   a processor; and   a machine-readable medium having instructions thereon that are executable by the processor to cause the processor to,
 log, during the injecting, measurements comprising at least one of an actual wellhead pressure; treatment fluid inlet density, inlet flow rate, outlet flow rate, and treatment fluid inlet viscosity; and 
 determine a loss zone location in the wellbore based on the measurements. 
   
     
     
         11 . The system of  claim 10 , wherein the instructions comprise instructions executable by the processor to cause the processor to,
 determine a calculated wellhead pressure based on the measurements; and   calculate a wellhead pressure differential based on a difference between the calculated wellhead pressure and the actual wellhead pressure,   wherein the loss zone location is determined based on the wellhead pressure differential.   
     
     
         12 . The system of  claim 11 , wherein the instructions comprise instructions executable by the processor to cause the processor to,
 calculate a flowrate loss based on a difference between the inlet flow rate and the outlet flow rate, wherein the loss zone location is determined based on the wellhead pressure differential.   
     
     
         13 . The system of  claim 10 , wherein the treatment fluid comprises at least one of a non-aqueous fluid, an aqueous fluid, an aqueous-miscible fluid, a water-in-oil emulsion, and an oil-in-water emulsion. 
     
     
         14 . The system of  claim 10 , wherein the tubular comprises at least one of a casing string, a flexible tubing, an inflexible tubing, and a drill string. 
     
     
         15 . The system of  claim 10 , wherein the instructions comprise instructions executable by the processor to cause the processor to:
 perform a remedial operation to at least partially seal the loss zone location in the wellbore.   
     
     
         16 . The system of  claim 6 , wherein the remedial operation comprises at least one of ceasing operations, removing the treatment fluid from the wellbore, reformulating the treatment fluid, introducing a loss circulation pill into the wellbore, reducing the inlet flow rate, and increasing the inlet flow rate. 
     
     
         17 . The system of  claim 10 , wherein the instructions comprise instructions executable by the processor to cause the processor to,
 perform a preventative operation to at least partially seal a different loss zone location in a different wellbore based on the loss zone location in the wellbore.   
     
     
         18 . The system of  claim 17 , wherein the preventative operation comprises at least one of introducing a loss circulation material into the different wellbore, reducing the inlet flow rate, increasing the inlet flow rate, adjusting the wellbore geometry, and adjusting the location of the different wellbore. 
     
     
         19 . A non-transitory, computer-readable medium having instructions thereon that are executable by a processor to cause the processor to:
 log, during injection of a treatment fluid through a tubular positioned in a wellbore created in a subterranean formation, measurements comprising at least one of an actual wellhead pressure; treatment fluid inlet density, inlet flow rate, outlet flow rate, and treatment fluid inlet viscosity; and   determine a loss zone location in the wellbore based on the measurements.   
     
     
         20 . The non-transitory, computer-readable medium of  claim 19 , wherein the instructions comprise instructions executable by the processor to cause the processor to,
 determine a calculated wellhead pressure based on the measurements; and   calculate a wellhead pressure differential based on a difference between the calculated wellhead pressure and the actual wellhead pressure,   wherein the loss zone location is determined based on the wellhead pressure differential.