System for enhancing fluid flow in a well

• US 6,619,402 B1
• Filed: 03/13/2002
• Issued: 09/16/2003
• Est. Priority Date: 09/15/1999
• Status: Expired due to Fees

• Current Assignee: Shell Oil Company (Shell Plc)
• Original Assignee: Shell Oil Company (Shell Plc)
• Inventors: Amory, Marc Emmanuel, Worrall, Robert Nicholas, Daling, Roelof, Glandt, Carlos Alberto
• Primary Examiner(s): DANG, HOANG C
• Application Number:
  US10/088,151
• Time in Patent Office: 552 Days
• Field of Search: 166/313, 166/370, 166/117.5, 166/117.6, 166/50, 166/66.4, 166/68, 166/68.5, 166/105
• US Class Current: 166/370
• CPC Class Codes: E21B 43/128 Adaptation of pump systems with down-hole electric drives
• CPC Class Codes: E21B 43/129 Adaptations of down-hole pump systems powered by fluid supplied from outside the borehole gas-lift E21B43/122; jet pumps E21B43/124
• CPC Class Codes: E21B 43/14 Obtaining from a multiple-zone well
• CPC Class Codes: E21B 47/00 Survey of boreholes or wells monitoring pressure or flow of drilling fluid E21B21/08
• CPC Class Codes: E21B 49/08 Obtaining fluid samples or testing fluids, in boreholes or wells

Abstract

A system for enhancing fluid flow into and through a hydrocarbon fluid production well comprising a series of flow boosters, such as electrically or hydraulically driven moineau-type pumps or centrifugal pumps or turbines, for controlling and/or boosting fluid flow from various regions of a drainhole section of the well into a production tubing within the well.

Claims

1. A system for enhancing fluid flow into and through a hydrocarbon fluid production well, the system comprising a series of flow boosters which comprise pump and motor assemblies for controlling fluid flow from various regions of a drainhole or reservoir inflow section of a well into a production tubing within the well, characterized in that the flow boosters are retrievably mounted in side pockets of the production tubing.

2. The system of claim 1, wherein the production tubing extends through a substantially horizontal drainhole section and is surrounded by an annular inflow zone and the flow boosters are distributed along the length of said inflow zone such that each flow booster draws fluid from the annular inflow zone and discharges fluid into the production tubing.

3. The system of claim 2, wherein one or more annular insulation packers are arranged in said annular inflow zone to create an annular inflow zone in which a plurality of hydraulically insulated drainhole regions are present and a plurality of flow boosters draw fluid from a plurality of said regions.

4. The system of claim 1, wherein the flow boosters are positive displacement pumps or rotary turbines that are driven by electrical or hydraulic motors.

5. The system of claim 4, wherein the flow boosters are moineau-type positive displacement pumps of which a rotor is directly coupled to an output shaft of an asynchronous electrical motor having a rotor part comprising one or more permanent magnets.

6. The system of claim 5, wherein the flow booster and motor are located within a tubular mandrel which is retrievably mounted in a side pocket of the production tubing and the motor is connected to an electrical conductor passing along a liner or said production tubing via one or more wet mateable electrical connector.

7. The system of claim 6 wherein pressure, temperature and/or fluid composition measurement sensors are mounted inside each mandrel and are connected to a flowrate control system of each flow booster such that the pumprate of a flow booster is restricted in case the measured flowrate is significantly larger than that of one or more other flow boosters or if the produced fluids comprise a significant amount of water or sand or another undesired fluid, such as natural gas if the well is an oil well.

8. A method of operating the system of claim 1, wherein the flow boosters are in use controlled such that pumprate of each booster are in use controlled such that pumprate of each booster cyclically varies between a maximum and minimum value and the pumprate variations of the various flow boosters are out of phase relative to each other.

9. The method of claim 8, wherein the pumprates of the various flow boosters are cyclically varied such that the point of maximum influx into the inflow section of the well is cyclically moved between a lower end and an upper end of said inflow section.