Method for determining injector bottom hole pressure in a hydrocarbon recovery operation using liner-deployed outflow control devices

Abstract

Methods for determining hydrocarbon recovery injection well bottom hole pressures where a downhole liner has liner-deployed outflow control devices, for attempting to ensure operation below a maximum operating pressure. Steam flowrate is varied using a range of valve positions, including shut-in periods (0-5% flowrate) sufficient to approach equilibrium between a surface pressure and bottom hole pressure, generating a determined bottom hole pressure which can be used to calculate an average bottom hole pressure. An average steam flowrate and average surface pressure are determined for a range of valve positions. A pressure drop is calculated for each of the valve positions by subtracting the average bottom hole pressure from the measured surface pressure. Plotting the pressure drop against the average surface pressure for each of the valve positions allows generation of a best fit model defining a polynomial relationship between the pressure drop and the surface pressure. Parameters can then be derived from the best fit model, enabling prediction of the bottom hole pressure for any steam flowrate for the well. The maximum operating pressure can then be more confidently determined for various steam flowrate values. The methods may be automated using a programmable logic controller (PLC) or similar platform located at the well pad.

1 . A method for determining bottom hole pressure for a steam injection well used in hydrocarbon recovery, the steam injection well configured to introduce steam to a subsurface reservoir containing hydrocarbon, wherein a downhole liner of the well is provided with at least one liner-deployed outflow control device for introducing the steam to the reservoir, the steam injection well further provided with (i) a valve at surface for controlling steam flowrate into the well, (ii) a meter at the surface for measuring the steam flowrate, and (iii) a gauge at the surface for measuring pressure upstream of the at least one liner-deployed outflow control device, the method comprising the steps of:
 a. opening the valve to allow the steam to pass through the well and the at least one liner-deployed outflow control device into the subsurface reservoir;   b. selecting a shut-in period for at least one shut-in sufficient to reduce the pressure to approach the bottom hole pressure;   c. operating the valve to implement the at least one shut-in for the shut-in period;   d. during the shut-in period, allowing the pressure to approach the bottom hole pressure, resulting in a reduced pressure at the surface; and   e. measuring the reduced pressure using the gauge to arrive at a determined bottom hole pressure.   
     
     
         2 . The method of  claim 1 , wherein:
 the shut-in period is sufficient to allow the pressure to reach equilibrium with the bottom hole pressure.   
     
     
         3 . The method of  claim 1 , wherein:
 the steam injection well is an injector well of a steam-assisted gravity drainage well pair.   
     
     
         4 . The method of  claim 1 , further comprising:
 operating the valve at step c. at a variety of valve positions to implement a range of steam flowrates including the at least one shut-in, and measuring the pressure for each of the variety of valve positions.   
     
     
         5 . The method of  claim 1 , wherein:
 the at least one shut-in is achieved by operating the valve at step c. to between a full shut-in (0%) and a partial shut-in (5%) valve position.   
     
     
         6 . The method of  claim 1 , further comprising:
 monitoring for changes in the determined bottom hole pressure.   
     
     
         7 . The method of  claim 1 , further comprising:
 the step of, in response to a determined bottom hole pressure exceeding a maximum operating pressure for the reservoir, operating the valve to reduce the steam flowrate.   
     
     
         8 . The method of  claim 1 , wherein:
 step c. comprises at least two shut-ins.   
     
     
         9 . The method of  claim 4 , wherein:
 each of the valve positions is maintained for at least 15 minutes.   
     
     
         10 . The method of  claim 4 , wherein:
 the variety of valve settings ranges from 0% to a selected maximum steam flowrate.   
     
     
         11 . The method of  claim 1 , wherein:
 the pressure at the surface is a wellhead pressure.   
     
     
         12 . A method for predicting a bottom hole pressure for a steam injection well used in hydrocarbon recovery for a range of steam flowrate values, the steam injection well configured to introduce steam to a subsurface reservoir containing hydrocarbon, wherein a downhole liner of the well is provided with at least one liner-deployed outflow control device for introducing the steam to the reservoir, the steam injection well further provided with (i) a valve at surface for controlling steam flowrate into the well, (ii) a meter at the surface for measuring the steam flowrate, and (iii) a gauge at the surface for measuring the pressure upstream of the at least one liner-deployed outflow control device, the method comprising the steps of:
 a. opening the valve to allow the steam to pass through the well and the at least one liner-deployed outflow control device into the subsurface reservoir;   b. measuring the steam flowrate using the meter and measuring the pressure using the gauge;   c. selecting a shut-in period for at least one shut-in sufficient to reduce the pressure to approach the bottom hole pressure, resulting in a reduced pressure at the surface, and measuring the reduced pressure to provide a determined bottom hole pressure for the at least one shut-in;   d. using the valve, varying the steam flowrate between a plurality of selected values falling within the range of steam flowrate values, including the at least one shut-in;   e. measuring the steam flowrate using the meter and measuring the pressure using the gauge for each of the plurality of selected values falling within the range of steam flowrate values;   f. determining an average steam flowrate and an average pressure for the measured steam flowrate and the measured pressure for each of the plurality of selected values;   g. calculating a pressure drop for each of the plurality of selected values by subtracting an average determined bottom hole pressure for the at least one shut-in from the measured pressure for each of the plurality of selected values;   h. plotting the pressure drop against the average steam flowrate for each of the selected values as points, and generating a best fit model for the points defining a polynomial relationship between the pressure drop and the steam flowrate;   i. deriving a set of parameters from the best fit model; and   j. using the set of parameters to predict the bottom hole pressure for any steam flowrate along the range of steam flowrate values.   
     
     
         13 . The method of  claim 12 , wherein:
 the shut-in period is sufficient to allow the pressure to reach equilibrium with the bottom hole pressure.   
     
     
         14 . The method of  claim 12 , wherein:
 the at least one shut-in is achieved by operating the valve at step d. to between a full shut-in (0%) and a partial shut-in (5%) valve position.   
     
     
         15 . The method of  claim 12 , further comprising the step of:
 in response to a determined bottom hole pressure exceeding a maximum operating pressure for the reservoir, operating the valve to reduce the steam flowrate.   
     
     
         16 . The method of  claim 12 , wherein:
 step d. comprises at least two shut-ins.   
     
     
         17 . The method of  claim 12 , wherein:
 the plurality of selected values ranges from 0% to a selected maximum steam flowrate.   
     
     
         18 . The method of  claim 12  wherein each of the steam flowrate values is a valve position. 
     
     
         19 . The method of  claim 16 , wherein the determined bottom hole pressures for the at least two shut-ins are averaged to arrive at the average determined red bottom hole pressure for the pressure drop calculation of step g. 
     
     
         20 . The method of  claim 12 , comprising:
 identifying a maximum steam flowrate by determining where the polynomial relationship changes.   
     
     
         21 . The method of  claim 12 , wherein:
 the pressure at the surface is a wellhead pressure.