Automated well pressure control and gas handling system and method

Patent metadata

Field	Value
Publication number	US-10648315-B2
Application number	US-201615197449-A
Country	US
Kind code	B2
Filing date	Jun 29, 2016
Priority date	Jun 29, 2016
Publication date	May 12, 2020
Grant date	May 12, 2020

Abstract

A method includes pumping fluid into a drill string extending through a riser into a well. A managed pressure drilling system is operated to maintain a selected fluid pressure in the well between the well and the drill string. A fluid influx into the well or a fluid loss into a formation traversed by the well is detected using measurements of fluid pressure in the well and fluid flow into and out of the well. The method includes automatically abating the fluid influx by closing an annular blowout preventer disposed in the riser or abating the fluid loss by operating the annular blowout preventer and pumping a sacrificial fluid into the drill string.

First claim

What is claimed is:

1. An apparatus, comprising:
an annular blowout preventer disposed in a riser between a subsea wellhead and a drilling platform, wherein the subsea wellhead is coupled to a top of a subsea well that is provided at a water bottom;
a subsea blowout preventer assembly stack connected to the subsea wellhead, provided proximate the water bottom, and disposed below the annular blowout preventer, wherein the subsea blowout preventer assembly stack is separate and distinct from the annular blowout preventer;
a pump provided adjacent to the subsea wellhead, wherein the pump is fluidly connected to the riser via a valve that is connected to a riser section of the riser adjacent to the subsea wellhead, wherein an inlet pressure to the pump is selected by a drilling unit, and the riser extends to the drilling unit;
a first manifold in fluid communication with the subsea well;
a choke in fluid communication with the first manifold;
a second manifold in fluid communication with the annular blowout preventer;
a choke manifold in fluid communication with the second manifold; and
a flow meter in fluid communication with the choke manifold and configured to determine an amount of fluid influx from a formation through which the subsea well extends, an amount of fluid loss into the formation, or both;
wherein, when the flow meter determines that the amount of fluid influx is less than a first predetermined threshold and the amount of fluid loss is less than a second predetermined threshold, then the fluid from the subsea well is directed to the first manifold and then to the choke to maintain a predetermined fluid pressure in the subsea well;
wherein, when the flow meter determines that the amount of fluid influx is greater than the first predetermined threshold, then the annular blowout preventer is closed, the fluid below the annular blowout preventer is diverted from the riser to the second manifold and then to the choke manifold; and
wherein, when the flow meter determines that the amount of fluid loss is greater than the second predetermined threshold, then the annular blowout preventer is closed, and a sacrificial fluid is pumped into a drill string in the subsea well, wherein the sacrificial fluid comprises additives that seal cracks in the formation.

2. The apparatus of claim 1 , wherein the choke comprises a controllable orifice choke in a fluid discharge path from the subsea well.

3. The apparatus of claim 1 , further comprising a rotating control device positioned such that at least a portion of the riser is located between the rotating control device and a drilling fluid flow system disposed on the drilling platform.

4. The apparatus of claim 1 , wherein the flow meter is located in a fluid outlet path from the subsea well.

5. The apparatus of claim 1 , wherein the annular blowout preventer is configured to be closed if either the fluid influx into the subsea well is detected or the fluid loss into the formation is detected.

6. The apparatus of claim 1 , further comprising a riser gas handler associated with the annular blowout preventer, wherein the riser gas handler is configured to divert fluid to the second manifold.

7. The apparatus of claim 1 , further comprising a source of the sacrificial fluid, wherein the sacrificial fluid is pumpable from the source into the subsea well below the annular blowout preventer.

8. The apparatus of claim 1 , further comprising a pressure transducer forming part of a measurement while drilling/logging sensor suite.

9. A method, comprising: pumping fluid of a drilling unit into a drill string extending through a riser into a well;
detecting a fluid influx into the well or a fluid loss into a formation;
abating the fluid influx by closing an annular blowout preventer disposed in the riser and diverting the fluid flowing through a flow spool below the annular blowout preventer from the riser to a distribution manifold and then to a choke manifold;
abating the fluid loss by closing the annular blowout preventer and pumping a sacrificial fluid into the drill string using a pump that is located adjacent to the well by lifting fluid from a base of the riser, wherein the pump is in fluid communication with the riser at the base of the riser;
maintaining a predetermined fluid pressure in the well when neither the fluid influx nor the fluid loss is detected by directing the fluid from the well to a manifold and then to a choke;
coupling the flow spool to the annular blowout preventer such that the annular blowout preventer is disposed above the flow spool; and
connecting a blowout preventer assembly stack to a wellhead of the well such that the blowout preventer assembly stack is disposed below the flow spool.

10. The method of claim 9 , wherein the fluid influx and the fluid loss are detected by measurements from one or more flow meters in a fluid return path from the well.

11. The method of claim 9 , wherein the abating the fluid influx by closing the annular blowout preventer comprises automatically switching to a riser gas handling mode.

12. The method of claim 9 , wherein abating the fluid influx comprises diverting gas entering the well around the annular blowout preventer.

13. The method of claim 9 , wherein the sacrificial fluid is pumped into the well below the annular blowout preventer while the annular blowout preventer is closed.

14. The method of claim 9 , wherein the predetermined fluid pressure is maintained in the well by operating a controllable orifice of the choke, wherein the choke is located in a fluid return path from the well.

15. The method of claim 9 , wherein the fluid influx or fluid loss is detected by determining a position of a controllable orifice of the choke.

16. The method of claim 9 , wherein detecting the fluid influx or fluid loss is determined using measurements of fluid pressure in the well and measurements of fluid flow rate into the well.

17. The method of claim 9 , wherein measurements of pressure in the wellbore are made by a pressure transducer forming part of a measurement while drilling/logging sensor suite.

18. An apparatus, comprising:
a drilling unit comprising a derrick and hoisting equipment, the drilling unit comprising drilling mud pumps having a discharge in fluid communication with an interior of a drill string suspended in a well by the hoisting equipment;
a riser extending from a subsea blowout preventer assembly stack to the drilling unit, wherein the subsea blowout preventer assembly stack is coupled to a top of the well;
a pump in fluid communication with the riser at a base of the riser adjacent the top of the well, wherein an inlet pressure to the pump is selected by the drilling unit;
an annular blowout preventer disposed between the subsea blowout preventer assembly stack and the riser, the annular blowout preventer having a controllable flow bypass;
a flow spool separating the subsea blowout preventer assembly stack and the annular blowout preventer such that the annular blowout preventer is disposed above the flow spool, and the subsea blowout preventer assembly stack is disposed below the flow spool;
a managed pressure drilling system disposed proximate the drilling unit and comprising a controllable orifice choke in a fluid discharge path from the well, wherein the pump is in fluid communication with the managed pressure drilling system via the fluid discharge path;
a first manifold in fluid communication with the well and the controllable orifice choke;
a second manifold in fluid communication with the annular blowout preventer;

Assignees

• Schlumberger Technology Corp

Inventors

• Couturier Yawan
• Liezenberg Bastiaan
• Johnson Glenn
• Rakhunde Vikas
• Hardt Jesse

Classifications

• E21B34/06

  in wells · CPC title

• E21B17/01

  Risers · CPC title

• E21B21/106

  Valve arrangements outside the borehole, e.g. kelly valves (valves specifically for maintaining circulation of drilling fluid while connecting or disconnecting tubular joints E21B21/019) · CPC title

• E21B44/00 Primary

  Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions · CPC title

• E21B47/06

  Measuring temperature or pressure · CPC title