Pump control for formation testing

• US 8,967,253 B2
• Filed: 07/19/2011
• Issued: 03/03/2015
• Est. Priority Date: 12/27/2006
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (SLB)
• Original Assignee: Schlumberger Technology Corporation (SLB)
• Inventors: Ciglenec, Reinhart, Villareal, Steven G., Hoefel, Albert, Swinburner, Peter, Stucker, Michael J., Follini, Jean-Marc
• Primary Examiner(s): PATEL, RAMESH B
• Application Number:
  US13/185,609
• Publication Number:
  US 20110276187A1
• Time in Patent Office: 1,323 Days
• Field of Search: 700281-282, 702 45- 49, 702/55, 73 116- 136, 73 173- 174, 166/105, 166/264, 166/373, 166/255.2, 166/250.02, 166/250.05, 166/250.15
• US Class Current: 166/255.2
• CPC Class Codes: E21B 49/10 using side-wall fluid samplers or testers

Abstract

A downhole formation fluid pumping and a sampling apparatus are disclosed that may form part of a formation evaluation while drilling tool or part of a tool pipe string. The operation of the pump is optimized based upon parameters generated from formation pressure test data as well as tool system data thereby ensuring optimum performance of the pump at higher speeds and with greater dependability. New pump designs for fluid sampling apparatuses for use in MWD systems are also disclosed.

Claims

1. A method for controlling a pumping system of a formation fluid sampling tool during formation fluid sampling, comprising:

collecting in situ measurements from at least one sensor in the tool; and

using the measurements in adaptive feedback loops to control performance of the pumping system.

2. The method of claim 1 wherein the method is capable of operating the pumping system of the tool with no operator interference.

3. The method of claim 1 wherein the adaptive feedback loops at least partially comprise a multi-layer cascaded control loop system.

4. The method of claim 3 wherein the multi-layer cascaded control loop system comprises a first layer and a second layer, wherein the inner layer regulates a torque applied by a motor of the pumping system, and wherein the outer layer regulates a speed of the motor and thus a pump rate of the pumping system.

5. The method of claim 1 further comprising tracking temperatures of the pumping system to predict maximum available power from mud circulation, and using the tracked temperatures and predicted maximum available power to limit a flow rate so that power used by the pumping system does not exceed the maximum available power.

6. A method for controlling a pumping system of a formation fluid sampling tool during formation fluid sampling, comprising:

(a) obtaining formation or formation fluid pressure test data;

(b) determining another formation or formation fluid parameters using the pressure test data;

(c) determining a desired pump parameter based on the other parameter;

(d) determining an expected formation response to sampling the formation, wherein the expected formation response is determined based on the other formation parameter and the desired pump parameter;

(e) predicting maximum power available from a turbine or turbo-alternator of the pumping system;

(f) controlling operation of the pumping system based on the predicted maximum power available, electrical load limitations of the pumping system determined from torque limitations of the pumping system, mechanical load limitations of the pumping system, and losses in the pumping system;

(g) updating parameters of the pumping system as controlling operation of the pumping system proceeds;

(h) updating operation of the pumping system based on the updated parameters according to the desired pump parameters, under the control of prevailing operational conditions determined in one or more previous steps;

(i) measuring the formation response to sampling by the tool; and

(j) comparing the measured formation response to the expected formation response.

7. The method of claim 6 wherein the other formation or formation fluid parameter is selected from the group consisting of:

a hydrostatic pressure in the wellbore;

a circulating pressure in the wellbore;

a mobility of the fluid;

formation pressure; and

mudcake permeability.

8. The method of claim 6 wherein the desired pump parameter is a control sequence for the pumping system.

9. The method of claim 8 wherein the control sequence is formulated as prescribed pressure levels, pressure variations, and/or flow rates of the pumping system.

10. The method of claim 9 wherein the control sequence is formulated as a function of time or volume.

11. The method of claim 10 wherein the control sequence comprises:

an investigation phase in which a formation model is confirmed, refined or completed, a pump rate is fine tuned, and mud filtrate is pumped out of the formation; and

a storage phase in which formation fluid is pumped into a sample chamber of the tool.

12. The method of claim 10 wherein the control sequence is derived from the mobility of the fluid such that:

if the mobility is below a predetermined value, the control sequence corresponds to increasing a flow rate of the pumping system monotonically at a first rate; and

if the mobility is above the predetermined value, the control sequence corresponds to increasing the flow rate of the pumping system monotonically at a second rate that is greater than the first rate.

13. The method of claim 12 wherein the control sequence includes increasing the flow rate of the pumping system until predetermined system drive limits are approached, at which time the control sequence includes maintaining the current flow rate of the pumping system until a predetermined amount of mud filtrate is pumped out of the formation and a sample is taken.

14. The method of claim 10 wherein the control sequence is derived by achieving an optimum balance between minimum pump drawdown pressure and maximum fluid volume pumped in a given time using a cost function to determine a desired pumping system flow rate and its corresponding drawdown pressure differential for a storage phase, wherein the cost function penalizes large drawdown pressure and low pumping system flow rate.

15. The method of claim 14 further comprising adjusting the cost function using data collected during prior sampling operations performed with the tool.

16. The method of claim 14 wherein determining the expected formation response includes generating a formation model.

17. The method of claim 16 wherein the formation model relates a drawdown pressure differential as a function of formation flow rate, and wherein the formation model is parameterized by overbalance and mobility of the formation fluid.

18. The method of claim 16 wherein the formation model comprises a parameter describing depth of invasion by mud filtrate, and wherein the formation model predicts evolution of gas-oil ratio or contamination level for a plurality of sampling scenarios.

19. The method of claim 6 wherein predicting the maximum power available from the turbine or turbo-alternator of the pumping system includes using a model for the turbine or turbo-alternator.

20. The method of claim 19 wherein the model for the turbine or turbo-alternator comprises power curves each expressing generated power as a function of angular velocity.

21. The method of claim 6 wherein steps (g) and (h) comprise:

if the desired pump parameters meet the operational conditions, the desired pump parameters are used to update the pump operation;

if not, operational condition limits are used to update the pump operation.

22. The method of claim 6 wherein step (i) comprises measuring a flow line pressure and a pump flow rate, and then computing formation flow rate with a tool model.

23. The method of claim 22 further comprising using a fluid analysis module to provide feedback in the form of optical densities at different wavelengths to compute a gas-oil ratio of the sampled fluid, to monitor contamination of the sampled fluid, or to detect bubbles or sand in the flow line.

24. The method of claim 6 further comprising monitoring a fluid property to detect if the sample fluid that enters the tool comes in single phase, such that the sampling pressure is not below the bubble point or the dew precipitation of the formation fluid.

25. A method for controlling a pumping system of a formation fluid sampling tool during formation fluid sampling, comprising:

(a) obtaining formation or formation fluid pressure test data;

(b) determining another formation or formation fluid parameters using the pressure test data;

(c) determining a desired pump parameter based on the other parameter, wherein the desired pump parameter is a control sequence for the pumping system, wherein the control sequence is formulated as prescribed pressure levels, pressure variations, and/or flow rates of the pumping system, wherein the control sequence is formulated as a function of time or volume, and wherein the control sequence comprises an investigation phase and a storage phase;

(d) determining an expected formation response to sampling the formation, including generating a formation model, wherein the expected formation response is determined based on the other formation parameter and the desired pump parameter, wherein the formation model relates a drawdown pressure differential as a function of formation flow rate, wherein the formation model is parameterized by overbalance and mobility of the formation fluid, wherein the formation model comprises a parameter describing depth of invasion by mud filtrate, and wherein the formation model predicts evolution of gas-oil ratio or contamination level for a plurality of sampling scenarios;

(e) predicting maximum power available from a turbine or turbo-alternator of the pumping system, including using a model for the turbine or turbo-alternator, wherein the model for the turbine or turbo-alternator comprises power curves each expressing generated power as a function of angular velocity;

(f) controlling operation of the pumping system based on the predicted maximum power available, electrical load limitations of the pumping system determined from torque limitations of the pumping system, mechanical load limitations of the pumping system, and losses in the pumping system;

(g) updating parameters of the pumping system as controlling operation of the pumping system proceeds;

(h) updating operation of the pumping system based on the updated parameters according to the desired pump parameters, under the control of prevailing operational conditions determined in one or more previous steps;

(i) measuring the formation response to sampling by the tool, including measuring a flow line pressure and a pump flow rate and then computing formation flow rate with a tool model;

(j) comparing the measured formation response to the expected formation response;

(k) using a fluid analysis module to provide feedback in the form of optical densities at different wavelengths to compute a gas-oil ratio of the sampled fluid, to monitor contamination of the sampled fluid, or to detect bubbles or sand in the flow line; and

(l) monitoring a fluid property to detect if the sample fluid that enters the tool comes in single phase, such that the sampling pressure is not below the bubble point or the dew precipitation of the formation fluid;

wherein steps (g) and (h) comprise;

if the desired pump parameters meet the operational conditions, the desired pump parameters are used to update the pump operation;

if not, operational condition limits are used to update the pump operation.