System and method for reservoir characterization

• US 8,613,313 B2
• Filed: 07/19/2010
• Issued: 12/24/2013
• Est. Priority Date: 07/19/2010
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Original Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Inventors: Ziauddin, Murtaza, Brown, George A., Pipchuk, Douglas, Khan, Waqar
• Primary Examiner(s): WRIGHT, GIOVANNA COLLINS
• Application Number:
  US12/838,945
• Publication Number:
  US 20120012308A1
• Time in Patent Office: 1,254 Days
• Field of Search: 166/305.1, 166/250.01, 731/521.2
• US Class Current: 166/250.01
• CPC Class Codes: E21B 47/06 Measuring temperature or pressure
• CPC Class Codes: E21B 47/07 Temperature
• CPC Class Codes: E21B 47/135 using light waves, e.g. infrared or ultraviolet waves

Abstract

A method for determining flow distribution in a formation having a wellbore formed therein includes the steps of positioning a sensor within the wellbore, wherein the sensor generates a feedback signal representing at least one of a temperature and a pressure measured by the sensor, injecting a fluid into the wellbore and into at least a portion of the formation adjacent the sensor, shutting-in the wellbore for a pre-determined shut-in period, generating a simulated model representing at least one of simulated temperature characteristics and simulated pressure characteristics of the formation during the shut-in period, generating a data model representing at least one of actual temperature characteristics and actual pressure characteristics of the formation during the shut-in period, wherein the data model is derived from the feedback signal, comparing the data model to the simulated model, and adjusting parameters of the simulated model to substantially match the data model.

Claims

1. A method for determining characteristics of a formation having a wellbore formed therein, comprising:

positioning a sensor within the wellbore, wherein the sensor generates a feedback signal representing a temperature in the wellbore, wherein the sensor comprises distributed temperature sensing technology having an optical fiber disposed along an interval within the wellbore;

injecting a fluid into the formation via the wellbore;

generating a data model representing real-time temperature characteristics of the formation, wherein the data model is derived from the feedback signal resulting from the injected fluid; and

analyzing the data model based upon an instruction set to extrapolate characteristics of the formation by comparing the data model to at least a pre-defined thermal characteristic of the formation, wherein the instruction set comprises at least one pre-determined algorithm, mathematical process, or equation.

2. The method according to claim 1 further comprising the step of performing an underbalanced drilling operation in the wellbore.

3. The method according to claim 1 further comprising the step of monitoring a production rate of hydrocarbon flowing from the wellbore, wherein the instruction set includes a comparison of the production rate and the temperature characteristics.

4. The method according to claim 1 further comprising the step of monitoring a pressure in the wellbore, wherein the instruction set includes a comparison of the pressure in the wellbore and the temperature characteristics.

5. The method according to claim 1 wherein the fluid is at least one of a diverting agent, a stimulation fluid, and a drilling fluid.

6. The method according to claim 1 wherein the instruction set includes a log of at least one of a natural fracture in the formation and petrophysical properties of the formation.

7. The method of claim 1 wherein positioning comprises positioning a sensor within the wellbore by deploying a coiled tubing into the wellbore.

8. A method for determining characteristics of a formation having a wellbore formed therein, comprising:

positioning a sensor within the wellbore, wherein the sensor provides a substantially continuous temperature monitoring along a pre-determined interval of the wellbore, wherein the sensor includes distributed temperature sensing technology having an optical fiber disposed along the pre-determined interval within the wellbore, and wherein the sensor generates a feedback signal representing temperature measured by the sensor;

injecting a first fluid into the wellbore and into at least a portion of the formation adjacent the interval;

generating a data model representing actual substantially real-time thermal characteristics of at least a sub-section of the interval, wherein the data model is derived from the feedback signal resulting from the injected first fluid; and

analyzing the data model based upon an instruction set to identify temperature patterns in the formation and comparing the generated data model to at least one pre-defined thermal characteristic of the formation to thereby extrapolate characteristics of the formation.

9. The method according to claim 8 further comprising the step of performing an underbalanced drilling operation in the wellbore.

10. The method according to claim 8 further comprising the step of monitoring a production rate of hydrocarbon flowing from the wellbore, wherein the instruction set includes a comparison of the production rate and the temperature characteristics.

11. The method according to claim 8 further comprising the step of monitoring a pressure of in the wellbore, wherein the instruction set includes a comparison of the pressure in the wellbore and the temperature characteristics.

12. The method according to claim 8 wherein the instruction set includes a log of at least one of a natural fracture in the formation and petrophysical properties of the formation.

13. The method according to claim 8 further comprising the step of injecting a second fluid into the wellbore to generate a hot slug, wherein the first fluid includes a first reactant and the second fluid includes a second reactant, and wherein a reaction rate between the first and second reactants is controlled.

14. The method according to claim 13 wherein the first fluid is injected through a coiled tubing disposed in the wellbore.

15. The method according to claim 13 wherein the second fluid is injected through an annulus of a coiled tubing disposed in the wellbore.

16. A method for determining characteristics of a formation having a wellbore formed therein, comprising:

a) positioning a distributed temperature sensor within the wellbore by deploying a coiled tubing into the wellbore, wherein the sensor provides a substantially continuous temperature monitoring along a pre-determined interval of the wellbore, wherein the sensor includes distributed temperature sensing technology having an optical fiber disposed along an interval within the wellbore, and wherein the sensor generates a feedback signal representing temperature measured by the sensor;

b) injecting a first fluid through the coiled tubing and into the formation;

c) generating a data model representing thermal characteristics of at least a sub-section of the interval, wherein the data model is derived from the feedback signal resulting from the injected first fluid;

d) analyzing the data model based upon an instruction set to extrapolate characteristics of the formation by comparing the data model to at least a pre-defined thermal characteristic of the formation; and

repeating steps b) through d) for each of a plurality of sub-sections defining the interval within the wellbore to achieve an improved characterization of the entire interval.

17. The method according to claim 16 further comprising the step of injecting a second fluid into the wellbore to generate a hot slug.

18. The method according to claim 17 wherein the first fluid includes a first reactant and the second fluid includes a second reactant.

19. The method of claim 16 wherein the improved characterization is utilized to improve subsequent well completion decisions.