Formation testing

• US 10,711,607 B2
• Filed: 10/05/2018
• Issued: 07/14/2020
• Est. Priority Date: 04/27/2010
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (SLB)
• Original Assignee: Schlumberger Technology Corporation (SLB)
• Inventors: Bedouet, Sylvain, Eriksen, Kare Otto
• Primary Examiner(s): Andrews, D.
• Application Number:
  US16/152,609
• Publication Number:
  US 20190040740A1
• Time in Patent Office: 648 Days
• Field of Search: None
• 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 49/088 combined with sampling
• CPC Class Codes: E21B 49/10 using side-wall fluid samplers or testers

Abstract

Formation testing which may involve circulating mud in a pipe string from a mud pit through a port in the pipe string to a downhole diverter sub, wherein the pipe string is suspended in a wellbore extending into a subterranean formation, operating a downhole pump to pump formation fluid from the formation, wherein the formation fluid comprises gas, and mixing the pumped formation fluid with circulated mud such that a proportion of the pumped formation gas in the circulated mud is maintained below a threshold value.

Claims

1. A method, comprising:

(a) collecting data pertaining to at least one of a subterranean formation penetrated by a wellbore and a fluid in the subterranean formation;

(b) determining initial threshold values of test operating parameters for a test to be performed utilizing a testing tool positioned in the wellbore proximate the subterranean formation, wherein determining the initial threshold values is based on the collected data and a testing tool configuration to be utilized to perform the test;

(c) predicting wellbore fluid pressures along an open hole portion of the wellbore by performing a thermo-hydraulic simulation of the test utilizing the determined initial threshold values and the testing tool configuration;

(d) analyzing the predicted wellbore fluid pressures and, based thereon, determining that the predicted wellbore fluid pressures along the open hole portion of the wellbore are indicative of a well integrity problem, and then updating the test by adjusting at least one of;

a value of at least one of the test operating parameters; and

the testing tool configuration;

(e) iteratively repeating (c) and (d) until analysis of the predicted wellbore fluid pressures along the open hole portion of the wellbore is not indicative of a well integrity problem; and

then

(f) performing the updated test via operation of the testing tool in the wellbore.

2. The method of claim 1 wherein:

collecting data pertaining to at least one of the subterranean formation and the fluid in the subterranean formation comprises collecting data selected from the group consisting of;

formation fluid composition;

formation fluid gas-to-oil ratio (GOR);

formation gas density;

formation gas viscosity;

formation gas compressibility;

formation liquid density;

formation liquid viscosity;

formation liquid compressibility;

formation gas solubility in a drilling mud to be utilized during the test;

formation liquid solubility in the drilling mud;

a bubble point pressure and temperature curve of a mixture of formation gas and the drilling mud;

a bubble point pressure and temperature curve of a mixture of formation liquid and the drilling mud;

a temperature profile acquired along at least the open hole portion of the wellbore;

a sea floor temperature; and

regional geothermal gradient information; and

determining initial threshold values of test operating parameters for the test comprises determining initial threshold values of test operating parameters selected from the group consisting of;

formation fluid pumping flow rate;

ratio of formation fluid pumping rate and drilling mud circulation rate;

formation pumping duration; and

formation pumping volume.

3. The method of claim 1 wherein:

analyzing the predicted wellbore fluid pressures comprises comparing the predicted wellbore fluid pressures along the open hole portion of the wellbore to at least one of estimated formation fracture strength data and estimated formation pressure data;

the estimated formation pressure data is selected from the group consisting of;

an estimated formation pressure proximate the testing location;

a pressure profile measured across other subterranean formations traversed by the wellbore; and

data obtained from pressure sensors installed at locations along the wellbore; and

the well integrity problem is one of;

a flow of fluid from the subterranean formation into the open hole portion of the wellbore during the test, based on a pressure of the subterranean formation exceeding at least one of the wellbore fluid pressures along the open hole portion of the wellbore; and

a fracture of the subterranean formation and a resulting leakage of fluid from the wellbore into the subterranean formation during the test, based on at least one of the wellbore fluid pressures along the open hole portion of the wellbore exceeding a pressure of the subterranean formation.

4. The method of claim 1 wherein updating the test comprises changing at least one of:

a composition of a drilling mud to be utilized during the test;

a type of the drilling mud;

a density of the drilling mud;

a circulation rate of the drilling mud;

a flow rate at which fluid is pumped from the subterranean formation;

an amount of time during which fluid is pumped from the subterranean formation; and

a volumetric amount of fluid that is pumped from the subterranean formation.

5. The method of claim 1 further comprising, before (f), predicting wellbore fluid conditions related to the updated test, including at least one of a predicted wellbore pressure at a predetermined location within the wellbore, a predicted wellbore temperature at a predetermined location within the wellbore, a predicted pit gain, and a predicted gas elution rate from the wellbore.