Control logic method and system for optimizing natural gas production

Abstract

In a system for optimizing natural gas production in response to real-time variations in wellbore parameters, a PLC or other wellsite intelligence technology is used to monitor liquid and gas production from the wellbore under friction-loaded conditions. Using baseline production data obtained during production tests, the PLC determines and initiates the appropriate operating mode for the wellbore to optimize a selected production criterion to suit measured wellbore parameters. The operating mode either a continuous clean-out mode, in which gas is continuously injected into the wellbore to control liquid loading, or an intermittent clean-out, in which liquid loading is regulated by intermittent gas injection. In preferred embodiments, the system uses bladder-type control valves having upstream and downstream solenoids, to control production tubing flow rate within a range between upper and lower set points.

1 . A method for optimizing production from a natural gas well associated with a gas compressor, wherein said gas well is adapted for injection of gas into a wellbore injection chamber to regulate wellbore velocity, said method comprising the following steps:
 (a) conducting a plurality of baseline production tests to gather selected well productivity information under operational conditions corresponding to a selected set of test input parameters;   (b) storing the test input parameters and the corresponding well productivity information in the memory of a programmable logic controller (PLC);   (c) by means of the PLC, identifying the set of test input parameters that results in the optimal well productivity characteristics; and   (d) operating the well using a first set of operational parameters points corresponding to the optimal input parameters determined in step  7 ( c ).   
     
     
         2 . A method as in  claim 1  wherein the test input parameters comprise compressor suction pressure and wellbore flow rate. 
     
     
         3 . A method as in  claim 1  wherein the well productivity information comprises a rate of gas production from the well. 
     
     
         4 . A method as in  claim 1  wherein the well productivity information comprises a rate of cash flow from the well. 
     
     
         5 . A method as in  claim 1 , comprising the further steps of:
 (a) conducting a plurality of supplementary production tests to gather selected well productivity information under operational conditions corresponding to a selected set of supplementary input parameters;   (b) storing the supplementary input parameters and the corresponding supplementary well productivity information in the memory of the PLC; and   (c) by means of the PLC, determining which supplementary input parameters resulted in the most favourable supplementary well productivity information, and:
 c.1 if the most favourable supplementary well productivity information represents an improvement over well productivity achieved using the first set of operational parameters, commence operating the well using the supplementary input parameters; and 
 c.2 if the most favourable supplementary well productivity information does not represent an improvement over well productivity achieved using the first set of operational parameters, revert to operating the well using the first set of operational parameters. 
   
     
     
         6 . A method as in  claim 5  wherein one or more control valve assemblies are used to regulate wellbore velocity in accordance with the operative input parameters, and wherein at least one of said one or more control valve assemblies comprises:
 (a) a valve having:
 a.1 a fluid inlet; 
 a.2 a fluid outlet; 
 a.3 a pressure port in fluid communication with a pressure source; and 
 a.4 a flow restriction element exposed to the pressure source via the pressure port, said flow restriction element being adapted to decrease flow through the valve in response to increases in the pressure source pressure, and to increase flow through the valve in response to decreases in the pressure source pressure; 
 
 (b) an upstream bypass line connecting the fluid inlet and the pressure source; 
 (c) an upstream solenoid operable to regulate fluid flow through the upstream bypass line; 
 (d) a downstream bypass line connecting the fluid outlet and the pressure source; and 
 (e) a downstream solenoid operable to regulate fluid flow through the downstream bypass line; 
 
       such that:
 (f) when the pressure at the fluid inlet is greater than the pressure source pressure, opening the upstream solenoid will increase the pressure source pressure; and 
 (g) when the pressure at the fluid outlet is less than the pressure source pressure, opening the downstream solenoid will decrease the pressure source pressure. 
 
     
     
         7 . A method as in  claim 6  wherein the PLC controls the operation of said one or more control valves. 
     
     
         8 . A system for regulating multiple separate fluid flows originating from a single fluid flow source, said system comprising:
 (a) an apparatus adapted to receive an inlet fluid flow, said apparatus diverting a first portion of the inlet fluid flow into a first downstream fluid flow, and diverting a second portion of the inlet fluid flow into a second downstream fluid flow;   (b) a first control valve associated with the first downstream fluid flow and adapted to regulate a first flow variable relative to a first set point range, said first flow variable being the inlet fluid flow pressure;   (c) a second control valve associated with the second downstream fluid flow and adapted to regulate a second flow variable relative to a second set point range; and   (d) one or more additional downstream fluid flows, each having an associated control valve adapted to regulate an associated flow variable relative to an associated set point range;   
       wherein the first set point range is higher than the highest downstream fluid flow pressure, and the first control valve is the only valve regulating inlet fluid pressure. 
     
     
         9 . A system as in  claim 8  wherein the set point ranges for all valves are wide enough to prevent valve chatter. 
     
     
         10 . A system as in  claim 8  wherein the set point range of at least one control valve is a fixed set point range. 
     
     
         11 . A system as in  claim 8  wherein the set point range of at least one of the control valves is a variable set point range. 
     
     
         12 . A system as in  claim 8 , further comprising a programmable logic controller (PLC) having a memory storing the set point range of the control valves, said PLC being adapted to regulate fluid flow through the control valves by:
 (a) comparing, at selected time intervals, measured values of the flow variables regulated by the control valves against the corresponding set point ranges; and   (b) where a measured flow variable is outside its corresponding set point range and not trending toward the set point range, opening or closing the corresponding control valve as appropriate to move the value of the flow variable toward its set point range.   
     
     
         13 . A system as in  claim 12  wherein the PLC is adapted to open or close the control valves in pulsed fashion, and to compare measured flow variable values at selected time intervals. 
     
     
         14 . A system as in  claim 8  in which at least one of the control valves comprises a control valve assembly comprising:
 (a) a valve having:
 a.1 a fluid inlet; 
 a.2 a fluid outlet; 
 a.3 a pressure port in fluid communication with a pressure source; and 
 a.4 a flow restriction element exposed to the pressure source via the pressure port, said flow restriction element being adapted to decrease flow through the valve in response to increases in the pressure source pressure, and to increase flow through the valve in response to decreases in the pressure source pressure; 
 
 (b) an upstream bypass line connecting the fluid inlet and the pressure source; 
 (c) an upstream solenoid operable to regulate fluid flow through the upstream bypass line; 
 (d) a downstream bypass line connecting the fluid outlet and the pressure source; and 
 (e) a downstream solenoid operable to regulate fluid flow through the downstream bypass line; 
 
       such that:
 (f) when the pressure at the fluid inlet is greater than the pressure source pressure, opening the upstream solenoid will increase the pressure source pressure; and 
 (g) when the pressure at the fluid outlet is less than the pressure source pressure, opening the downstream solenoid will decrease the pressure source pressure. 
 
     
     
         15 . A system as in  claim 8  wherein:
 (a) the fluid flow source is a wellhead compressor associated with a natural gas well, said gas well including a string of tubing disposed within the wellbore and defining an annulus surrounding the tubing; 
 (b) the fluid is natural gas from the well; 
 (c) the first downstream fluid flow is into an injection chamber selected from the tubing and the annulus, with the first downstream control valve regulating compressor discharge pressure; and 
 (d) the second downstream fluid flow is into a sales flow line and the second downstream control valve is regulated based on total production rate up a production chamber selected from the tubing and casing other than the injection chamber. 
 
     
     
         16 . A system as in  claim 15  wherein the compressor speed can be varied. 
     
     
         17 . A system as in  claim 16  wherein both the compressor throughput and discharge pressure have fixed set point ranges, such that the compressor speed varies directly with suction pressure. 
     
     
         18 . A system as in  claim 15 , further comprising a PLC having a memory storing a selected suction pressure set point range, said PLC being adapted to control the compressor speed and thereby to regulate suction pressure by the steps of:
 (a) comparing measured values of suction pressure against the stored suction pressure set point range;   (b) where the measured suction pressure is outside the stored suction pressure set point range and not approaching the set point range, increasing or decreasing the compressor speed by a selected incremental amount to move the value of the suction pressure toward the stored suction pressure set point range; and   (c) repeating steps (a) and (b) at selected intervals until the measured suction pressure is within the stored suction pressure set point range.   
     
     
         19 . A system as in  claim 16  wherein the set point range of the suction pressure is variable. 
     
     
         20 . A method for optimizing production from a natural gas well associated with a gas compressor, wherein the well includes a string of tubing disposed within the wellbore and defining an annulus surrounding the tubing, said method comprising the steps of:
 (a) providing a system as in  claim 8 , adapted for selective diversion of the second downstream gas flow into an injection chamber selected from the tubing and the annulus;   (b) providing a PLC having a processor and a memory, said PLC being programmed to control the operation of the control valves and the compressor speed, in response to input signals corresponding to selected flow variables;   (c) storing in the PLC memory a selected number of test data sets each containing test values for a selected set of flow variables;   (d) conducting a selected number of well production tests, during each of which the well operates under conditions corresponding to the flow variable values of a selected test data set, with all well production tests being of the same selected duration;   (e) measuring the total volume of gas produced during each production test and storing the measured gas volumes in the PLC memory with reference to their corresponding test data sets;   (f) determining which production test produced the highest volume of gas, and storing the corresponding test data set as the default operational parameters for the well in the PLC memory; and   (g) operating the well in accordance with the default operational parameters.   
     
     
         21 . A method as in  claim 20 , comprising the further steps of:
 (a) after a selected time interval, conducting a subsequent set of well production tests in accordance with steps (d) and (e) in  claim 20 ;   (b) determining which subsequent production test produced the highest volume of gas, and identifying the test data set corresponding to that subsequent production test;   (c) if the test data set identified in step  21 ( b ) does not correspond to the default parameters stored in the PLC memory, establishing the test data set identified in step  21 ( b ) as the new default parameters and store same in the PLC memory; and   (d) operating the well in accordance with the new default parameters.   
     
     
         22 . A method for optimizing production from a natural gas well associated with a gas compressor, wherein the well includes a string of tubing disposed within the wellbore and defining an annulus surrounding the tubing, said method comprising the steps of:
 (a) providing a system as in  claim 8 , adapted for selective diversion of the second downstream gas flow into an injection chamber selected from the tubing and the annulus;   (b) providing a PLC having a processor and a memory, said PLC being programmed to control the operation of one or more of the control valves each in response to input signals from a sensor measuring a selected flow variable;   (c) storing, in the PLC memory, initial set point ranges for tubing flow rate, suction pressure, and discharge pressure;   (d) conducting an initial well production test for a selected test duration, during which the well operates under conditions corresponding to said initial set point ranges;   (e) logging selected well productivity data during the initial well production test, and storing said data in the PLC memory; and   (f) storing the initial set point ranges in the PLC memory as the default optimum set points.   
     
     
         23 . A method as in  claim 22 , further comprising the steps of:
 (a) after a selected time interval, adjusting the suction pressure set point range by a selected amount, while maintaining the initial tubing rate and discharge pressure set point ranges;   (b) conducting a supplemental well production test for test duration corresponding to the initial test duration;   (c) logging the selected well productivity data during the supplemental well production test, and storing said data in the PLC memory; and   (d) comparing the logged well productivity data for the initial and supplemental production tests; and   (e) if the supplemental well productivity data is more favourable than the initial well productivity data, establishing the supplemental set point ranges as the new default parameters and storing same in the PLC memory.   
     
     
         24 . A method as in  claim 23  wherein the adjustment to the suction pressure set point range corresponds to a suction pressure reduction. 
     
     
         25 . A method as in  claim 23  wherein the adjustment to the suction pressure set point range corresponds to a suction pressure increase.