Method for detecting wellbore influx

Patent metadata

Field	Value
Publication number	US-9759025-B2
Application number	US-201515317120-A
Country	US
Kind code	B2
Filing date	May 20, 2015
Priority date	Jun 10, 2014
Publication date	Sep 12, 2017
Grant date	Sep 12, 2017

Abstract

A method for detecting an influx in a wellbore with first and second pressure transmitters arranged in a fixed vertical distance in relation to each other. The method includes calculating an expected density of a return flow between the first and second pressure transmitters, continuously measuring an actual density of the return flow based on a measured pressure at the first and second pressure transmitters, comparing the calculated expected density of the return flow and the measured actual density of the return flow to determine the influx in the wellbore, and predicting a probability of hydrates forming in the well by measuring a temperature via a temperature transmitter arranged in a section of the well adjacent to the first and/or the second pressure transmitter, and using the temperature together with the measurements from the first and second pressure transmitters.

First claim

The invention claimed is:

1. A method for detecting an influx in a wellbore with at least one first pressure transmitter arranged in a first position in a well and at least one second pressure transmitter arranged in a second position in the well, the at least one first pressure transmitter and the at least one second pressure transmitter being arranged in a fixed vertical distance in relation to each other, the method comprising:
calculating an expected density of a return flow between the at least one first pressure transmitter and the at least one second pressure transmitter by measuring or predicting a mud or sacrificial fluids density, a rock density, a first flow rate, a true vertical depth, a rate of penetration, and a wellbore diameter;
continuously measuring an actual density of the return flow based on a measured pressure at each of the at least one first pressure transmitter and the at least one second pressure transmitter, the actual density being computed based on the fixed vertical distance between the at least one first pressure transmitter and the at least one second pressure transmitter as adjusted for a frictional pressure drop between each of the at least one first pressure transmitter and the at least one second pressure transmitter based on a direction and a second flow rate in an annulus in the wellbore;
comparing the calculated expected density of the return flow and the measured actual density of the return flow to determine the influx in the wellbore;
predicting a probability of hydrates forming in the well by,
using at least one first temperature transmitter arranged in a section of the well adjacent to the at least one first pressure transmitter and/or adjacent to the at least one second pressure transmitter,
measuring a temperature at the at least one first temperature transmitter, and
using the temperature together with the measurements from the at least one first pressure transmitter and the at least one second pressure transmitter;

confirming a possible hydrate formation; and
generating a warning if a temperature reading is below a predefined safety margin of a corresponding hydrate formation temperature.

2. The method as recited in claim 1 , wherein the at least one first pressure transmitter and the at least one second pressure transmitter are arranged in an open-hole section of the well.

3. The method as recited in claim 1 , wherein the at least one first temperature transmitter is arranged in an open-hole section of the well.

4. The method as recited in claim 1 , further comprising:
providing a plurality of pressure transmitters in a fixed vertical distance in the well; and
repeating the calculating, continuously measuring and comparing steps of claim 1 between two adjacent pressure transmitters of the plurality of pressure transmitters.

5. The method as recited in claims 1 , further comprising:
confirming a wellbore influx if the measured actual density of the return flow is significantly less than the calculated expected density of the return flow.

6. The method as recited in claim 5 , further comprising:
monitoring a possible rapid gas expansion in the well;
automatically regulating a riser gas handling or a managed pressure drilling choke by applying a constant value of an applied surface back pressure; and, if a high risk of hydrates is determined,
reducing the applied surface back pressure; and
injecting a hydrate inhibitor below a rotating control device.

7. The method as recited in claim 5 , further comprising:
displacing fluids in a riser if a temperature in the riser is below a hydrate formation temperature;
pumping fresh mud down at least one booster line so as to circulate out gas cut mud;
monitoring a possible rapid gas expansion under consideration that hydrates “melt” at low pressure; and
preparing to divert overboard so as to avoid a riser blow-out on a drill floor.

8. The method as recited in 5 , further comprising, in case the influx in the wellbore has passed a subsea blowout preventer:
pumping mud down at least one booster line so as to circulate out gas cut mud;
monitoring a possible rapid gas expansion; and
preparing to divert overboard so as to avoid a riser blow-out on a drill floor.

9. The method as recited in claim 5 , further comprising:
providing a temperature transmitter adjacent to each of the at least one first pressure transmitter and the at least one second pressure transmitter in the well;
predicting a probability of hydrates forming in the well using temperature readings from each temperature transmitter together with the measurements from the at least one first pressure transmitter and the at least one second pressure transmitter.

10. The method as recited in claim 1 , further comprising:
filling at least one kill line with a hydrate inhibitor fluid;
injecting the hydrate inhibitor fluid in the at least one kill line in a blow out preventer; and, simultaneously therewith,
pumping fresh mud down a drill string so as to circulate out wellbore fluids and an inhibitor up at least one choke line and to divert to a mud gas separator.

11. The method as recited in claim 1 , further comprising:
determining whether a choke line shut-in pressure is showing an abnormal pressure decrease; and
generating a wellbore influx and hydrate alarm.

12. The method as recited in claim 11 , further comprising:
identifying a stuck pipe situation as a possible result of hydrate formation by,
observing an increased drag trend or torque oscillation during connections and/or an abnormal pressure increase or a pressure oscillation during circulation, and
confirming that all of the following conditions are fulfilled:
drilling in a permeable formation which has been identified to have an ability to act as a reservoir rock as well as having a pressure close to or higher than a bottom hole pressure or a measured pressure at a pressure transmitter in the well,
observing that the temperature in the wellbore is below a hydrate formation temperature, and
observing a circulation restriction or a pressure peak.

13. The method as recited in claim 12 , wherein, in case of the stuck pipe situation caused by hydrate formation, the method further comprises:
injecting hydrate inhibitor fluid close to a wellhead,
stopping a circulation so as to allow a temperature in a formation to increase a temperature of fluids in the well so as to perfom a hydrate dissociation process comprising melting or dissociating the hydrates into water and dense gas;
performing a flow check to verify that the hydrate dissociation process has started;
shutting-in the well if the well starts to flow; and
monitoring a shut-in pressure increase to determine a size of a hydrate plug/kick.

14. A method for detecting an influx in a wellbore with at least one first pressure transmitter arranged in a first position in a well and at least one second pressure transmitter arranged in a second position in the well, the at least one first pressure transmitter and the at least one second pressure transmitter being arranged in a fixed vertical distance in relation to each other, the method comprising:
calculating an expected density of a return flow between the at least one first pressure transmitter and the at least one second pressure transmitter by measuring or predicting a mud or sacrificial fluids density, a rock density, a first flow rate, a true vertical depth, a rate of penetration, and a wellbore diameter;
continuously measuring an actual density of the return flow based on a measured pressure at each of the at least one first pressure transmitter and the at least one second

Assignees

• Mhwirth As

Inventors

• Vavik Dag

Classifications

• E21B47/103 Primary

  using thermal measurements · CPC title

• E21B44/00

  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

• E21B7/12

  Underwater drilling (using heave compensators E21B19/09) · CPC title

• E21B21/067

  Separating gases from drilling fluids · CPC title