Method and device for maintaining sub-cooled fluid to ESP system

• US 8,042,612 B2
• Filed: 06/15/2009
• Issued: 10/25/2011
• Est. Priority Date: 06/15/2009
• Status: Active Grant

• Current Assignee: Baker Hughes Holdings LLC (Baker Hughes Company)
• Original Assignee: Baker Hughes Incorporated (Baker Hughes Company)
• Inventors: Crossley, Alexander, Bearden, John L.
• Primary Examiner(s): Neuder; William P
• Assistant Examiner(s): ALKER, RICHARD K
• Application Number:
  US12/484,889
• Publication Number:
  US 20100314103A1
• Time in Patent Office: 862 Days
• Field of Search: 166/250.01, 166/250.15, 166/252.1, 166/369, 417/18, 417/32, 417/44.2, 417/53, 700/282
• US Class Current: 166/252.1
• CPC Class Codes: E21B 43/128 Adaptation of pump systems with down-hole electric drives
• CPC Class Codes: E21B 43/2406 Steam assisted gravity drainage [SAGD]
• CPC Class Codes: E21B 47/07 Temperature

Abstract

A method of operating an electrical submersible pumping system that includes realtime monitoring of the wellbore fluid and adjusting pump speed so the fluid entering the pump remains subcooled. The method can include adding sensors within the wellbore and digitally storing fluid data accessible by a pump controller. The pump speed can be increased or decreased by adjusting the frequency of the electrical power delivered to the pump motor.

Claims

1. A method of producing wellbore fluid comprising:

a) pumping wellbore fluid with an electrical submersible pump (ESP) assembly;

b) measuring fluid temperature and pressure before it enters the ESP assembly;

c) adding a subcooled margin to the measured fluid temperature to obtain a subcooled margin fluid temperature and identifying the fluid vapor pressure at the subcooled margin fluid temperature to define a subcooled fluid pressure; and

d) controlling the pump so that the fluid pressure entering the ESP assembly is at least as great as the subcooled fluid pressure.

2. The method of claim 1, further comprising slowing the pump speed if the measured pressure is less than the subcooled fluid pressure.

3. The method of claim 1, wherein the subcooled margin comprises a value selected from a list consisting of 5°

F., 10°

F., 15°

F., 20°

F., 25°

F., 30°

F., 35°

F., 40°

F., 50°

F., and temperature values between.

4. The method of claim 1, further comprising referencing a fluid information source for the fluid vapor pressure, wherein the fluid information source is selected from a list consisting of a table, a steam table, a chart, and an algorithm.

5. The method of claim 1, further comprising measuring wellbore fluid data realtime with a sensor.

6. The method of claim 1, further comprising maintaining pump speed if the measured pressure is at least as great as the subcooled fluid pressure.

7. The method of claim 1, further comprising automating steps (c) and (d) with an information handling system.

8. The method of claim 7, further comprising storing fluid data in a readable medium.

9. The method of claim 1, wherein the fluid comprises a liquid selected from the list consisting of formation fluid, water, and combinations thereof.

10. The method of claim 1, further comprising injecting steam into a formation adjacent the wellbore.

11. A method of producing fluid from a wellbore comprising:

providing a submersible pump in the wellbore;

pumping fluid with the pump;

measuring fluid pressure and temperature flowing to the pump;

defining a fluid subcooled pressure to be the fluid vapor pressure at a temperature exceeding the measured temperature by a subcooled margin value;

comparing the measured pressure and the subcooled pressure;

injecting steam into a formation adjacent the wellbore; and

lowering the pump speed if the subcooled pressure exceeds the measured pressure.

12. The method of claim 11, further comprising analyzing wellbore fluid produced from the wellbore data to determine the fluid vapor pressure.

13. The method of claim 11, further comprising retrieving the fluid vapor pressure from data storage.