Determining gradients using a multi-probed formation tester

• US 20040230378A1
• Filed: 05/03/2004
• Published: 11/18/2004
• Est. Priority Date: 05/02/2003
• Status: Active Grant

• Current Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Original Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Inventors: Proett, Mark A., Gilbert, Gregory N., Ball, David E.
• Granted Patent: US 7,021,405 B2
• Time in Patent Office: Days
• US Class Current: 702/6
• CPC Class Codes: E21B 49/005 Testing the nature of borehole walls or the formation by using drilling mud or cutting data
• CPC Class Codes: E21B 49/08 Obtaining fluid samples or testing fluids, in boreholes or wells
• CPC Class Codes: E21B 49/0875 determining specific fluid parameters
• CPC Class Codes: G01N 9/26 by measuring pressure differences

Abstract

Methods for operating multi-probed formation testers to determine a fluid density gradient in the formation. The probes of the multi-probed formation tester are connected to a pressure gauge through a flowline that establishes a differential height between the probes. In some embodiments, a gradient of the fluid density in the flowline is determined as a function of the gradient of fluid density in the wellbore. The flowline fluid density gradient is then used to determine a formation fluid density gradient as a function of the flowline fluid density gradient.

Claims

1. A method for determining a formation fluid density gradient comprising:

disposing a multi-probed formation testing tool in a wellbore;

determining a wellbore fluid density gradient;

determining a flowline fluid density gradient as a function of the wellbore fluid gradient; and

determining a formation fluid density gradient as a function of the flowline fluid density gradient.

2. The method of claim 1 wherein the wellbore fluid density gradient is calculated based on a known density of a known fluid in the wellbore.

3. The method of claim 1 wherein determining the wellbore fluid density gradient further comprises:

measuring a first pressure in the wellbore at a first depth;

measuring a second pressure in the wellbore at a second depth; and

calculating the wellbore fluid density gradient using the first and second measured pressures and the difference between the first and second depths.

4. The method of claim 3 wherein the wellbore fluid density gradient is calculated by dividing the difference between the first and second measured pressures by the difference between the first and second depths.

5. The method of claim 1 wherein the flowline fluid density gradient is equal to the wellbore fluid density gradient.

6. The method of claim 1 wherein determining the flowline fluid density gradient further comprises:

measuring a first pressure in the wellbore through a first port in fluid communication with a first end of the flowline;

measuring a second pressure in the wellbore through a second port in fluid communication with a second end of the flowline; and

calculating the flowline fluid density gradient as a function of the first and second measured pressures and the wellbore fluid density gradient.

7. The method of claim 1 wherein determining the formation fluid density gradient further comprises:

measuring a first formation pressure through a first probe in fluid communication with a first end of the flowline;

measuring a second formation pressure through a second probe in fluid communication with a second end of the flowline; and

calculating the formation fluid density gradient as a function of the first and second formation pressures and the flowline fluid density gradient.

8. The method of claim 1 further comprising:

calibrating a plurality of strain gauges using the flowline fluid density gradient, wherein the strain gauges are used to measure formation pressure; and

using the strain gauges to monitor changes in the flowline fluid density gradient.

9. A method for operating a multi-probed formation testing tool comprising;

disposing the tool in a wellbore formed in a formation;

determining a wellbore fluid density gradient;

using the wellbore fluid density gradient to determine a flowline fluid density gradient; and

using the flowline fluid density gradient to correct the formation fluid density gradient.

10. The method of claim 9 wherein the formation testing tool comprises:

an upper section having a first extendable probe and a first port;

a lower section having a second extendable probe and a second port;

a flowline providing fluid communication between the upper and lower sections; and

a first pressure gauge in communication with the flowline.

11. The method of claim 10 wherein determining the wellbore fluid density gradient further comprises:

providing isolated fluid communication between the first port and the first pressure gauge at a first depth in the wellbore;

measuring a first pressure with the first pressure gauge;

providing isolated fluid communication between the first port and the first pressure gauge at a second depth in the wellbore;

measuring a second pressure with the first pressure gauge; and

calculating the wellbore fluid density gradient by dividing the difference between the first and second pressures by the difference between the first and second depths.

12. The method of claim 10 wherein determining the flowline fluid density gradient further comprises:

providing isolated fluid communication between the first port and the first pressure gauge at a first depth;

measuring a first pressure with the first pressure gauge;

providing isolated fluid communication between the second port and the first pressure gauge at a first depth;

measuring a second pressure with the first pressure gauge; and

calculating the flowline fluid density gradient as a function of the first and second measured pressures and the wellbore fluid density gradient.

13. The method of claim 10 wherein determining the formation fluid density gradient further comprises:

extending the first probe into fluid communication with the formation;

providing isolated fluid communication between the first probe and the first pressure gauge at a first depth;

measuring a first pressure with the first pressure gauge;

extending the second probe into fluid communication with the formation;

providing isolated fluid communication between the second probe and the first pressure gauge at a first depth;

measuring a second pressure with the first pressure gauge; and

calculating the formation fluid density gradient as a function of the first and second formation pressures and the fowline fluid density gradient.

14. The method of claim 10 wherein the formation testing tool further comprises a plurality of strain gauges, wherein both the first and second probes are in fluid communication with a dedicated strain gauge.

15. The method of claim 14 further comprising:

calibrating the plurality of strain gauges using the flowline fluid density gradient;

using the strain gauges to measure the pressure at each of the probes; and

using the strain gauges to monitor changes in the flowline fluid density gradient.

16. A method for correcting a formation gradient determined by formation pressure measurements made by a first and second probe of a multi-probe formation tester, the method comprising:

determining a flowline density gradient in a flowline having a length approximately equal to the distance between the first and second probes;

using the flowline density gradient to correct the determined formation gradient.

17. The method of claim 16 wherein the determination of the flowline density gradient further comprises:

measuring a first pressure through a first port in fluid communication with a first end of the flowline;

measuring a second pressure through a second port in fluid communication with a second end of the flowline; and

calculating the flowline fluid density gradient as a function of the first and second measured pressures and the distance between the first and second ports, wherein the distance between the first and second ports is approximately equal to the distance between the first and second probes.

18. The method of claim 16 wherein the flowline density gradient is dependent on a wellbore fluid density gradient.

19. The method of claim 16 wherein the determination of the formation gradient further comprises:

calibrating a strain gauge using the flowline fluid density gradient;

extending a probe into fluid communication with the formation;

using the strain gauge to measure the pressure at the probe; and

using the strain gauges to monitor changes in the flowline fluid density gradient.