WORKFLOW FOR PETROPHYSICAL AND GEOPHYSICAL FORMATION EVALUATION OF WIRELINE AND LWD LOG DATA

• US 20110208431A1
• Filed: 12/18/2009
• Published: 08/25/2011
• Est. Priority Date: 12/18/2009
• Status: Active Grant

• Current Assignee: Chevron USA Incorporated (Chevron Corp.)
• Original Assignee: Chevron USA Incorporated (Chevron Corp.)
• Inventors: Skelt, Christopher
• Granted Patent: US 8,219,319 B2
• Time in Patent Office: Days
• US Class Current: 702/7
• CPC Class Codes: G01V 20/00 Geomodelling in general
• CPC Class Codes: G01V 9/00 Prospecting or detecting by methods not provided for in groups G01V1/00 - G01V8/00
• CPC Class Codes: G01V 99/00 Subject matter not provided for in other groups of this subclass

Abstract

A computer-implemented method of characterizing elastic properties of a subsurface formation at various fluid saturation conditions is disclosed. The method includes the features of estimating densities and bulk moduli of fluids and surrounding rock matrix material present in an invaded zone around a wellbore and beyond the invaded zone to record a set of log curves of density and bulk modulus of the fluids and the surrounding rock matrix material present in the invaded zones and beyond the invaded zone versus depth; recording a set of shale trend compaction curves in each wellbore; solving a set of response equations for rock and fluid volumes based on the recorded set of log curves and shale trend compaction curves to compute lithology, porosity and hydrocarbon saturation to build computer models to estimate hydrocarbon saturation for the rock matrix material penetrated in the wellbore; and using the estimated densities and the bulk moduli of the fluids and the rock matrix material near the wellbore, the shale trend compaction curves and the computed lithology, porosity and hydrocarbon saturation near the wellbore to characterize elastic properties of a subsurface formation at various fluid saturation conditions.

Claims

1. A computer-implemented method of characterizing elastic properties of a subsurface formation at various fluid saturation conditions, the method comprising:

estimating densities and bulk moduli of fluids and surrounding rock matrix material present in an invaded zone around a wellbore and beyond the invaded zone to record a set of log curves of density and bulk modulus of the fluids and the surrounding rock matrix material present in the invaded zones and beyond the invaded zone versus depth;

recording a set of shale trend compaction curves in each wellbore;

solving a set of response equations for rock and fluid volumes based on the recorded set of log curves and shale trend compaction curves to compute lithology, porosity and hydrocarbon saturation to build computer models to estimate hydrocarbon saturation for the rock matrix material penetrated in the wellbore; and

using the estimated densities and the bulk moduli of the fluids and the rock matrix material near the wellbore, the shale trend compaction curves and the computed lithology, porosity and hydrocarbon saturation near the wellbore to characterize elastic properties of a subsurface formation at various fluid saturation conditions.

2. The computer-implemented method according to claim 1, wherein the estimated densities and bulk moduli of the surrounding rock matrix are determined based on one or more wireline and logging-while-drilling logs.

3. The computer-implemented method according to claim 2, further comprising:

editing the wireline and logging-while-drilling logs to correct for depth mismatching.

4. The computer-implemented method according to claim 3, wherein the one or more sonic logs is obtained from the wireline and logging-while-drilling logs.

5. The computer-implemented method according to claim 4, further comprising:

correcting the obtained one or more sonic logs for anisotropy if the sonic logs are obtained from deviated boreholes.

6. The computer-implemented method according to claim 5, further comprising:

normalizing the shale trend compaction curves with respect to a common datum in each wellbore.

7. The computer-implemented method according to claim 6, wherein the shale trend compaction curves include curves of at least one of density, neutron porosity, compressional sonic and resistivity.

8. The computer-implemented method according to claim 7, wherein the densities and bulk moduli of the fluids present in the invaded zone and reservoir, and other hypothecated aqueous or hydrocarbon fluids of interest are estimated from pressure and temperature.

9. The computer-implemented method according to claim 7, wherein the estimated densities and bulk moduli of fluids are determined based on laboratory measurements or established models.

10. The computer-implemented method according to claim 6, wherein the fluids present in the invaded zone include formation water, hydrocarbon and drilling mud filtrate.

11. The computer-implemented method according to claim 6, further comprising:

producing rock and mineral volume fractions based on the solved set of response equations for rock and fluid volumes for a predetermined depth interval below the wellbore.

12. The computer-implemented method according to claim 11, further comprising:

creating a regional sand porosity compaction trend curves based on the solved set of response equations.

13. The computer-implemented method according to claim 12, further comprising:

creating a data rehabilitation model based on the solved set of response equations.

14. The computer-implemented method according to claim 13, wherein typical reservoir saturations are modeled to represent oil or gas as a continuous phase or trapped gas at low saturation.

15. The computer-implemented method according to claim 14, wherein the estimated densities and bulk moduli of the surrounding rock matrix are determined based on the transformation of data from one or more wireline and logging-while-drilling logs to interpreted lithology or mineralogy.

16. The computer-implemented method according to claim 15, wherein fluid substitution is performed by inputting density and bulk modulus trends for fluids and their individual saturations, bulk moduli and volume fractions of each rock type, density, compressional and shear wave slowness or velocity of the formation, and cutoffs to identify intervals where fluid substitution is not to be done.

17. The computer-implemented method according to claim 16, further comprising:

producing quality control curves based on the fluid substitution results.

18. The computer-implemented method according to claim 17, wherein the quality control curves are produced for individual wells or across multiple wells.

19. The computer-implemented method according to claim 17, wherein the quality control curves are displayed as scatter plots including density, shear wave slowness or velocity, bulk modulus, compressional wave slowness or velocity, compressional impedance and compressional to shear wave velocity, Poisson'"'"'s ratio against effective porosity or shale fraction.

20. The computer-implemented method according to claim 15, further comprising:

determining local Greenberg-Castagna coefficients to estimate shear wave slowness or shear wave velocity for shale, sand and any other rock types present.

21. The computer-implemented method according to claim 20, wherein simultaneous fluid substitution and shear velocity estimation is performed by inputting density and bulk modulus trends for fluids and their individual saturations, bulk moduli and volume fractions of each rock type, density and compressional wave slowness or velocity of the formation, Greenberg-Castagna coefficients for all rock types, and cutoffs to identify intervals where fluid substitution is not to be done.

22. The computer-implemented method according to claim 21, further comprising:

producing quality control curves based on the fluid substitution results.

23. The computer-implemented method according to claim 22, wherein the quality control curves are produced for individual wells or across multiple wells.

24. The computer-implemented method according to claim 22, wherein the quality control curves are displayed as scatter plots including density, shear wave slowness or velocity, bulk modulus, compressional wave slowness or velocity, compressional impedance and compressional to shear wave velocity, Poisson'"'"'s ratio against effective porosity or shale fraction.

25. The computer-implemented method according to claim 20, further comprising determining local Greenberg-Castagna coefficients to estimate shear slowness of laminated shale beds present in a thinly-laminated formation.

26. The computer-implemented method according to claim 25, wherein fluid substitution is performed using a laminated model where the dependence of the elastic properties of the porous sand laminations on fluid content is modeled using an iterative optimization of Greenberg-Castagna and Gassmann models, by inputting density and bulk modulus trends for fluids and their individual saturations, bulk moduli and volume fractions of the sand and shale laminations, density, compressional and shear wave slowness or velocity of the formation, and cutoffs to identify intervals where fluid substitution is not to be done.

27. The computer-implemented method according to claim 26, further comprising:

producing quality control curves based on the fluid substitution results.

28. The computer-implemented method according to claim 27 wherein the quality control curves are produced for individual wells or across multiple wells.

29. The computer-implemented method according to claim 27, wherein the quality control curves are displayed as scatter plots including density, shear wave slowness or velocity, bulk modulus, compressional wave slowness or velocity, compressional impedance and compressional to shear wave velocity, Poisson'"'"'s ratio against effective porosity or shale fraction.

30. The computer-implemented method according to claim 24, wherein fluid substitution is performed using a laminated model where the dependence of the elastic properties of the porous sand laminations on fluid content is modeled using an iterative optimization of Greenberg-Castagna and Gassmann models, and the estimation of the shear velocity of the shale laminations is achieved using the Greenberg-Castagna equation, by inputting density and bulk modulus trends for fluids and their individual saturations, bulk moduli and volume fractions of the sand and shale laminations, density and compressional or velocity of the formation, and cutoffs to identify intervals where fluid substitution is not to be done.

31. The computer-implemented method according to claim 30, further comprising:

producing quality control curves based on the fluid substitution results.

32. The computer-implemented method according to claim 31, wherein the quality control curves are produced for individual wells or across multiple wells.

33. The computer-implemented method according to claim 31, wherein the quality control curves are displayed as scatter plots including density, shear wave slowness or velocity, bulk modulus, compressional wave slowness or velocity, compressional impedance and compressional to shear wave velocity, Poisson'"'"'s ratio against effective porosity or shale fraction.

34. A system for performing a method of characterizing elastic properties of a subsurface formation at various fluid saturation conditions comprising:

a data storage device having computer readable data including data relating to the plurality of well logs; and

a processor, configured and arranged to execute machine executable instructions stored in a processor accessible memory for performing a method comprising;

estimating densities and bulk moduli of fluids and surrounding rock matrix material present in an invaded zone around a wellbore and beyond the invaded zone to record a set of log curves of density and bulk modulus of the fluids and the surrounding rock matrix material present in the invaded zones and beyond the invaded zone versus depth;

recording a set of shale trend compaction curves in each wellbore;

solving a set of response equations for rock and fluid volumes based on the recorded set of log curves and shale trend compaction curves to compute lithology, porosity and hydrocarbon saturation to build computer models to estimate hydrocarbon saturation for the rock matrix material penetrated in the wellbore; and

using the estimated densities and the bulk moduli of the fluids and the rock matrix material near the wellbore, the shale trend compaction curves and the computed lithology, porosity and hydrocarbon saturation near the wellbore to characterize elastic properties of a subsurface formation at various fluid saturation conditions.

35. A system as in claim 34, further comprising a user interface configured and arranged to allow a user to input parameters for controlling the method.