Real Time Artificial Lift Timing and Selection Using Hybrid Data-Driven and Physics Models

Abstract

A method of forecasting production using an artificial lift operation in a well penetrating a reservoir in a subterranean formation, comprising: receiving sensor feedback from the well during well production; receiving a flowrate of oil, gas, and water for the well; calculating average reservoir pressure and productivity index (PI) of the well based on a cumulative liquid rate; estimating reservoir deliverability based on the PI and average reservoir pressure; estimating well deliverability, based on one or more artificial lift parameters; estimating a bottomhole pressure (BHP) of the well based, at least in part, on the estimated reservoir deliverability and well deliverability; generating a multiphase forecast of an estimated liquid, gas, water, and oil production of the well, based, at least in part, on the estimated BHP and the sensor feedback; and producing fluids from the well based on the estimated liquid, gas, water, and oil production of the well.

What is claimed is: 
     
         1 . A method of forecasting production using an artificial lift operation in a well penetrating a reservoir in a subterranean formation, comprising:
 (a) receiving sensor feedback from the well during well production;   (b) receiving a flowrate of oil, water, and gas for the well;   (c) calculating an average reservoir pressure and a productivity index (PI) of the well based on a cumulative liquid rate;   (d) estimating a reservoir deliverability of the reservoir based on the PI and the average reservoir pressure;   (e) estimating well deliverability with vertical lift of the well, based at least in part on one or more artificial lift parameters;   (f) estimating based, at least in part, on the estimated reservoir deliverability and the estimated well deliverability to estimate a bottomhole pressure (BHP) of the well;   (g) generating a multiphase forecast of an estimated liquid, gas, water, and oil production of the well, based, at least in part, on the estimated BHP and the sensor feedback from the well; and   (h) producing fluids from the well based, at least in part, on the estimated liquid, gas, water, and oil production of the well.   
     
     
         2 . The method of  claim 1 , further comprising iteratively repeating steps (c)-(g) using a cumulative flowrate of the estimated liquid production of step (g) for the cumulative liquid rate of step (c) to generate a multiphase forecast of a plurality of values of the estimated liquid, gas, water, and oil production of the well over a pre-selected time period; and
 producing the fluids from the well based, at least in part, on the multiphase forecast.   
     
     
         3 . The method of  claim 2 , further comprising:
 performing an iterative process of steps (a)-(g) a second time for the well using a different one or more artificial lift parameters in step (e);   comparing the multiphase forecasts resulting from the first iterative process of steps (a)-(g) using the one or more artificial lift parameters and second iterative process of steps (a)-(g) using the different one or more artificial lift parameters;   selecting an artificial lift operation method based on a comparison of the multiphase forecasts; and   producing the fluids from the well using the selected artificial lift operation method.   
     
     
         4 . The method of  claim 1 , wherein step (g) comprises:
 calculating a transient PI of the well based on the estimated BHP;   computing a plurality of PVT properties for the well at the average reservoir pressure based on the sensor feedback from the well; and   conducting the multiphase forecast of the estimated liquid, gas, water, and oil production of the well, based on the transient PI and the plurality of PVT properties.   
     
     
         5 . The method of  claim 4 , wherein the PVT properties comprise at least solution gas-oil ratio, gas formation volume factor, oil formation volume factor, and water formation volume factor. 
     
     
         6 . The method of  claim 4 , wherein step (g) further comprises:
 estimating a cumulative gas-oil ratio (GOR) based on the plurality of PVT properties; and   conducting the multiphase forecast of the estimated liquid, gas, water, and oil production of the well, based on the transient PI and the cumulative GOR.   
     
     
         7 . The method of  claim 1 , wherein step (f) further comprises:
 using a nodal analysis of the estimated reservoir deliverability and the estimated well deliverability to estimate the BHP of the well.   
     
     
         8 . The method of  claim 1 , wherein the one or more artificial lift parameters include a plurality of artificial lift types, the plurality of artificial lift types selected from the group consisting of: a beam pump, a jet pump, a progressive cavity pump (PCP), a hydraulic pump, a gas lift, a sucker rod pump (SRP), an electric submersible pump (ESP), a plunger lift, and a gas-assisted plunger lift (GAPL), and any combination of thereof. 
     
     
         9 . The method of  claim 7 , further comprising:
 determining a best type of artificial lift using one or more parameters selected from the group consisting of: target liquid rate, highest predicted gas-liquid ratio (GLR), influence of dog leg severity (DLS) during operation, anticipated line pressure, downhole temperature, and any combination thereof.   
     
     
         10 . A system for forecasting production using an artificial lift operation in a well penetrating a reservoir in a subterranean formation, comprising:
 one or more processors; and   one or more computer-readable non-transitory storage media comprising instructions that, when executed by the one or more processors, cause one or more components of the system to perform operations comprising:   (a) receiving sensor feedback from the well during well production;   (b) receiving a flowrate of oil, water, and gas for the well;   (c) calculating an average reservoir pressure and a productivity index (PI) of the well based on a cumulative liquid rate;   (d) estimating a reservoir deliverability of the reservoir based on the PI and the average reservoir pressure;   (e) estimating well deliverability with vertical lift of the well, based at least in part on one or more artificial lift parameters;   (f) estimating a bottomhole pressure (BHP) of the well based, at least in part, on the estimated reservoir deliverability and the estimated well deliverability;   (g) generating a multiphase forecast of an estimated liquid, gas, water, and oil production of the well, based, at least in part, on the estimated BHP and the sensor feedback from the well; and   (h) generate a production plan for fluids from the well based, at least in part, on the estimated liquid, gas, water, and oil production of the well.   
     
     
         11 . The system of  claim 10 , the operations further comprising iteratively repeating steps (c)-(g) using a cumulative flowrate of the estimated liquid production of step (g) for the cumulative liquid rate of step (c) to provide a multiphase forecast of a plurality of values of the estimated liquid, gas, water, and oil production of the well over a pre-selected time period; and
 generating the production plan for producing the fluids from the well based, at least in part, on the multiphase forecast.   
     
     
         12 . The system of  claim 11 , the operations further comprising:
 performing an iterative process of steps (a)-(g) a second time for the well using a different one or more artificial lift parameters in step (e);   comparing the multiphase forecasts resulting from the first iterative process of steps (a)-(g) using the one or more artificial lift parameters and second iterative process of steps (a)-(g) using the different one or more artificial lift parameters;   selecting an artificial lift operation method based, at least in part, on a comparison of the multiphase forecasts; and   generating the production plan for producing the fluids from the well using the selected artificial lift operation method.   
     
     
         13 . The system of  claim 10 , wherein step (g) comprises:
 calculating a transient PI of the well based, at least in part, on the estimated BHP;   computing a plurality of PVT properties for the well at the average reservoir pressure based, at least in part, on the sensor feedback from the well; and   generating the multiphase forecast of the estimated liquid, gas, water, and oil production of the well, based on the transient PI and the plurality of PVT properties.   
     
     
         14 . The system of  claim 13 , wherein the PVT properties comprise at least solution gas-oil ratio, gas formation volume factor, oil formation volume factor, and water formation volume factor. 
     
     
         15 . The system of  claim 13 , wherein step (g) further comprises:
 estimating a cumulative gas-oil ratio (GOR) based, at least in part, on the plurality of PVT properties; and   generating the multiphase forecast of the estimated liquid, gas, water, and oil production of the well, based on the transient PI and the cumulative GOR.   
     
     
         16 . The system of  claim 10 , wherein the step (f) further comprises:
 using a nodal analysis to estimate the BHP of the well based, at least in part, on the estimated reservoir deliverability and the estimated well deliverability.   
     
     
         17 . The system of  claim 16 , wherein the one or more artificial lift parameters comprise a plurality of artificial lift types, the plurality of artificial lift types selected from the group consisting of: a beam pump, a jet pump, a progressive cavity pump (PCP), a hydraulic pump, a gas lift, a sucker rod pump (SRP), an electric submersible pump (ESP), a plunger lift, a gas-assisted plunger lift (GAPL), and any combination thereof. 
     
     
         18 . The system of  claim 16 , further comprising:
 determining a best type of artificial lift using one or more parameters selected from the group consisting of: target liquid rate, highest predicted gas-liquid ratio (GLR), influence of dog leg severity (DLS) during operation, anticipated line pressure, downhole temperature, and any combination thereof.   
     
     
         19 . A method of producing fluids using an artificial lift operation in a well penetrating a reservoir in a subterranean formation, comprising:
 (a) receiving sensor feedback from the well during well production;   (b) receiving a flowrate of oil, gas, and water for the well;   (c) calculating an average reservoir pressure and a productivity index (PI) of the well based on a cumulative liquid rate;   (d) estimating a reservoir deliverability of the reservoir based on the PI and the average reservoir pressure;   (e) estimating well deliverability with vertical lift of the well, based at least in part on one or more first artificial lift parameters for first artificial lift equipment;   (f) estimating based, at least in part, on the estimated reservoir deliverability and the estimated well deliverability to estimate a bottomhole pressure (BHP) of the well;   (g) generating a multiphase forecast of an estimated liquid, gas, water, and oil production of the well, based, at least in part, on the estimated BHP and the sensor feedback from the well;   (h) performing steps (a)-(g) a second time for the well using one or more second artificial lift parameters for second artificial lift equipment;   (i) comparing the multiphase forecasts resulting from the first process of steps (a)-(g) using the one or more first artificial lift parameters and second process of steps (a)-(g) using the one or more second artificial lift parameters;   (j) selecting artificial lift equipment to be used in the artificial lift operation based on a comparison of the multiphase forecasts; and   (k) producing the fluids from the well using the selected artificial lift equipment.   
     
     
         20 . The method of  claim 19 , wherein the second artificial lift equipment comprises a different type of artificial lift equipment than the first lift equipment, or a same type of artificial lift equipment having different operational properties. 
     
     
         21 . The method of  claim 19 , wherein:
 the step (g) further comprises iteratively repeating steps (c)-(g) using a cumulative flowrate of the estimated liquid production of step (g) for the cumulative liquid rate of step (c) to provide a multiphase forecast of a plurality of values of the estimated liquid, gas, water, and oil production of the well over a pre-selected time period, and   the one or more artificial lift parameters for the second artificial lift equipment in step (h) being indicative of artificial lift equipment being used during a different portion of the pre-selected time period.   
     
     
         22 . A method of producing fluids using gas lift injection equipment in multiple wells of a well pad, each well extending through a subterranean formation, comprising:
 for each well of the multiple wells:
 (a) receiving sensor feedback from the well during well production; 
 (b) receiving a flowrate of oil, gas, and water for the well; 
 (c) calculating an average reservoir pressure and a productivity index (PI) of the well based on a cumulative liquid rate; 
 (d) estimating a reservoir deliverability of the reservoir based on the PI and the average reservoir pressure; 
 (e) estimating well deliverability with vertical lift of the well, based at least in part on one or more gas lift injection parameters; 
 (f) estimating based, at least in part, on the estimated reservoir deliverability and the estimated well deliverability to estimate a bottomhole pressure (BHP) of the well; 
 (g) generating a multiphase forecast of an estimated liquid, gas, water, and oil production of the well, based, at least in part, on the estimated BHP and the sensor feedback from the well; 
 (h) generating a gas lift performance (GLP) curve for the well based, at least in part, on the estimated oil production of the well; 
   comparing the GLP curves of the multiple wells; and   adjusting amounts of pressure output from a compressor to the gas lift injection equipment at two or more of the multiple wells based, at least in part, on the comparison of the GLP curves.