Intermittent well state sampling in managed pressure drilling applications
A method of monitoring a well state with intermittent well state sampling includes determining a measured volume differential by measuring flow out of a wellbore, measuring flow into the wellbore, and calculating a difference between the measured flow out and the measured flow in. The method includes determining an expected volume differential by calculating a fluid volume of the wellbore system, determining a wellbore pressure difference, determining a well system bulk modulus, and multiplying the fluid volume of the wellbore by the wellbore pressure difference and dividing a result by the well system bulk modulus. If the expected volume differential is not substantially equal to the measured volume differential, reporting to the user that the well state is experiencing a significant change requiring user intervention.
1. A method of monitoring a well state with intermittent well state sampling comprising:
determining a measured volume differential comprising:
measuring flow out of a wellbore,
measuring flow into the wellbore, and
calculating a difference between the measured flow out and the measured flow in;
determining an expected volume differential comprising:
calculating a fluid volume of the wellbore system,
determining a wellbore pressure difference,
determining a well system bulk modulus, and
multiplying the fluid volume of the wellbore by the wellbore pressure difference and dividing a result by the well system bulk modulus; and
if the expected volume differential is not substantially equal to the measured volume differential, reporting to a user that the well state is experiencing a significant change requiring user intervention.
2. The method of claim 1 , further comprising measuring a wellbore pressure.
3. The method of claim 2 , further comprising controlling the wellbore pressure through applied surface backpressure with a pressure control valve disposed on or near a drilling rig.
4. The method of claim 1 , wherein the flow out of the wellbore is measured with a Coriolis flow meter, a wedge meter, or other device capable of measuring volumetric flow rate.
5. The method of claim 1 , wherein the flow into the wellbore is measured with a Coriolis flow meter, a wedge meter, or other device capable of measuring volumetric flow rate.
6. The method of claim 1 , wherein calculating the measured volume differential comprises calculating a difference between measured continuous values of flow out and measured continuous values of flow in.
7. The method of claim 1 , wherein the well system bulk modulus is calculated based on one or more of historical fluid system volumes, pressure data, and volume differential values.
8. The method of claim 2 , wherein a change in the wellbore pressure initiates a calculation of an updated bulk modulus value for the wellbore system and an analysis of historical fluid system volume, pressure data, and volume differential values used to calculate the expected volume differential.
9. The method of claim 1 , wherein a change to measured flow into the wellbore initiates an analysis of historical fluid system volume, pressure data, and volume differential values used to calculate the expected volume differential.
10. The method of claim 1 , wherein an expected volume differential is calculated on a continuous basis through analysis of historical fluid system volume, pressure data, and volume differential values.
11. The method of claim 1 , wherein an expected wellbore storage volume is calculated through analysis of instantaneous values of historical fluid system volume, pressure data, and volume differential.
12. The method of claim 1 , wherein a change to measured flow out of the wellbore initiates an analysis of historical fluid system volume, pressure data, and volume differential values used to calculate an expected wellbore storage volume.
13. The method of claim 1 , wherein an actual wellbore storage volume is calculated using measured volume differential values.
14. The method of claim 1 , wherein a data acquisition and control system plots one or more of an actual wellbore storage volume, expected wellbore storage volume, actual wellbore gain, expected wellbore gain, actual wellbore loss, expected wellbore loss, or corrected volume differential for use by an operator.
15. The method of claim 1 , wherein a data acquisition and control system compares actual and expected values of wellbore storage at a first time and determines a first well state as an indicator of an influx of formation fluids, a loss of wellbore fluids, or a hydraulic connection of additional fluid volumes.
16. The method of claim 1 , wherein a data acquisition and control system alerts a user of a deviation from expected wellbore storage volume, expected gain, expected loss, or corrected volume differential.
17. The method of claim 1 , wherein a data acquisition and control system compares actual and expected values of wellbore storage volume at a second point in time and determines a second well state as an indicator of an influx of formation fluids, a loss of wellbore fluids, or a hydraulic connection of additional fluid volumes.
18. The method of claim 1 , wherein a first and a second well state are compared to indicate whether the well state is improving, unchanged, or degrading with time.
19. The method of claim 1 , wherein a data acquisition and control system analyses actual and expected values of wellbore storage volume to determine a worst-case surface pressure following an influx event based on an analysis of historical fluid system volume, pressure data, and volume differential values.
20. The method of claim 1 , wherein a data acquisition and control system alerts a user when a worst-case surface pressure following an influx event exceeds an allowed surface pressure of a drilling system.