METHOD AND PROCESS FOR PREDICTION OF SUBSURFACE FLUID AND ROCK PRESSURES IN THE EARTH

• US 20020169559A1
• Filed: 03/13/2001
• Published: 11/14/2002
• Est. Priority Date: 03/13/2001
• Status: Active Grant

• Current Assignee: Conocophillips Company (ConocoPhillips)
• Original Assignee: Conocophillips Company (ConocoPhillips)
• Inventors: Onyia, Ernest C., Bell, David W., Lahann, Richard Wayne, Huffman, Alan Royce
• Granted Patent: US 6,473,696 B1
• Time in Patent Office: Days
• US Class Current: 702/14
• CPC Class Codes: G01V 1/32 Transforming one recording into another or one representation into another

Abstract

A method of determination of fluid pressures in a subsurface region of the earth uses seismic velocities and calibrations relating the seismic velocities to the effective stress on the subsurface sediments. The seismic velocities may be keyed to defined seismic horizons and may be obtained from many methods, including velocity spectra, post-stack inversion, pre-stack inversion, VSP or tomography. Overburden stresses may be obtained from density logs, relations between density and velocity, or from inversion of potential fields data. The seismic data may be P-P, P-S, or S-S data. The calibrations may be predetermined or may be derived from well information including well logs and well pressure measurements. The calibrations may also include the effect of unloading. The determined pressures may be used in the analysis of fluid flow in reservoirs, basin and prospect modeling and in fault integrity analysis.

Claims

1. A method for determining a parameter of interest of a subsurface region of earth formations comprising:

(a) obtaining seismic survey information about the subsurface region;

(b) identifying a plurality of interpreted seismic horizons of interest from the obtained survey information;

(c) obtaining estimated seismic velocities corresponding to at least one interval between at least one pair of said plurality of seismic horizons;

(d) calibrating the estimated seismic velocities to the parameter of interest

(e) using the results of said calibration and the obtained seismic velocities to obtain the parameter of interest at any location within the seismic survey.

2. The method of claim 1 wherein calibrating the estimated seismic velocities further comprises at least one of:

(i) using a function determined independently from the seismic data using regional information

(ii) using data from a well corresponding to a specific calibration location that is outside the areal extent of the seismic velocity data.

(iii) using data from a well corresponding to a specific calibration location within the areal extent of the seismic velocity data.

(iv) using data from a well corresponding to a specific calibration location within the areal extent of the seismic velocity data combined with the velocity data from the seismic survey for the same said location.

3. The method of claim 2 where the calibrating the estimated seismic velocities includes the estimation of an overburden-depth relationship that is determined by integrating density data from at least one of:

I. a 1-D density function derived from density logs from at least one well;

II. a 1-D density function derived from density data from drop cores, side-wall cores or conventional cores;

III. a spatially varying density function based on the inversion of potential fields data, said potential fields data comprising at least one of gravity data, and magnetic data;

IV. a density function derived by performing inversion of at least one of PP data, and PS data.

4. The method of claim 1 wherein obtaining estimated seismic velocities further comprises using specific seismic pre-processing techniques including at least one of:

(i) Dip Move out (DMO)

(ii) Pre-stack time migration

(iii) Pre-stack depth migration

(iv) Multiple attenuation or suppression

(v) Reflection statics

(vi) Refraction statics

(vii) Wavefield reconstruction

(viii) The combination in undersampled seismic data from several gathers to form super-gathers.

5. The method of claim 1 wherein the parameter of interest is selected from the group consisting of:

(i) fluid pressure

(ii) fracture gradient

(iii) overburden pressure

(iv) effective stress

(v) excess pressure, defined as the difference between the actual fluid pressure and the normal pressure for the same depth

6. The method of claim 5 further comprising using the parameter of interest for performing further analysis at one of the following scales:

I. the scale of a specific well location, defined as a projected one-dimensional path that will be used to place a wellbore into the subsurface

II. the scale of an exploration prospect

III. the scale of a regional pressure evaluation to understand hydrocarbon systems

7. The method of claim 5 further comprising using the parameter of interest for performing specific analyses of the subsurface including at least one of the following:

I. basin modeling

II. hydrocarbon maturation in source rock intervals

III. lateral and vertical seal rock integrity

IV. fault seal integrity

V. evaluation of fluid migration pathways in the subsurface

VI. reservoir-specific lateral pressure changes

VII. shallow water flow risk evaluation

VIII. wellbore stability and failure analysis

8. The method of claim 1 wherein the seismic survey comprises one of:

(i) P-wave land seismic data

(ii) S-wave land seismic data

(iii) mode-converted S-wave land data (land PS data)

(iv) mode-converted S-wave marine ocean-bottom cable data (marine PS data)

(v) P-wave marine streamer data

(vi) P-wave marine ocean bottom cable data (PP data)

9. The method of claim 1 wherein the obtained seismic velocities are selected from the group consisting of:

(i) P-wave velocity data generated from normal moveout (NMO) velocity analysis

(ii) P-wave or S-wave velocity data generated from coherency inversion analysis

(iii) P-wave velocity generated from pre-stack inversion

(iv) P-wave velocity generated from post-stack inversion

(v) S-wave velocity generated from pre-stack inversion

(vi) S-wave velocity generated from post-stack inversion

(vii) S-wave velocity data generated from normal moveout (NMO) velocity analysis

(viii) P-wave velocity generated from tomography

(ix) S-wave velocity generated from tomography

(x) P-wave velocity data from vertical seismic profiling (VSP)

(xi) P-wave velocity data from VSP took-ahead inversion

(xiii) S-wave velocity data from vertical seismic profiling (VSP)

(xiv) S-wave velocity data from VSP look-ahead inversion

10. The method of claim 2 wherein the data from a well comprises at least one of:

I. sonic logs

II. shear sonic logs

II. density logs

IV. Lithology logs in the form of gamma ray or Spontaneous Potential logs

V. formation fluid pressure data. (further dependent claims)

VI. formation fracture pressures in the form of Leak Off Tests

11. The method of claim 1 wherein using the results of said calibration and the obtained seismic velocities to obtain the parameter of interest further comprises using at least one of:

(ii) the Eaton method

(ii) the effective stress method

(iii) the equivalent depth method

12. The method of claim 1 wherein calibrating the estimated seismic velocities further comprises using at least one of:

(i) a linear curve fitting

(ii) a curve fitting based on a power law

(iii) a curve fitting based on exponentials,

(iv) a quadratic curve fitting.

13. The method of claim 12 wherein calibrating the estimated seismic velocities further comprises:

using an interactive display, said interactive display allowing modification of a displayed calibration curve and observing changes in a plurality of other displayed curves simultaneously, said interactive display further allowing at least one of;

I. manually changing a coefficient or exponent in the fitting equation, and

II. using a cursor to graphically manipulate the fitting curve

14. The method of claim 1 further comprising:

obtaining a porosity calibration curve from well data using at least one of;

(i) editing of erroneous porosity values for at least one well;

(ii) displaying in a single plot, a depth-correlated porosity and velocity data for the at least one well;

(iii) curve fitting of the velocity and porosity data using at least one of;

I. a linear curve fitting

II. a curve fitting based on a power law

III. a curve fitting based on exponentials,

IV. a quadratic curve fitting; and

predicting porosity at a specified location using the obtained porosity calibration curve and the seismic velocity data from the specified location

15. The method of claim 1 wherein the parameter of interest is a fracture gradient, the method further comprising:

(i) deleting erroneous leak-off test values for at least one well;

(ii) displaying depth-correlated leak-off test and overburden data for the at least one well, and

(iii) applying one of the two following methods

I. curve fitting of the leak off test data to determine a fracture gradient, and

II. applying an appropriate stress ratio (Ko) to fit the leak-off test data

16. The method of claim 1 further comprising displaying the parameter of interest on one of:

(i) stacked seismic section, and

(ii) migrated seismic section.

17. The method of claim 1 further comprising displaying the parameter of interest interactively and simultaneously on at least one of:

(i) a seismic display

(ii) a velocity versus depth display including a velocity function for a specific location and a calibration function for velocity versus effective stress,

(iii) a stress versus depth display including the overburden stress calibration for said specific location and the effective stress calculated from the velocity versus depth display,

(iv) a pressure-gradient versus depth display including the fracture gradient or overburden gradient, the fluid pressure gradient calculated from the stress versus depth display, and pressure data points from a well that applies to said specific location.

18. The method of claim 1 wherein the at least one pair of the plurality of seismic horizons comprises at least two pairs, the method further comprising performing step (d) of claim 1 separately for each of the at least two pairs of seismic horizons.

19. The method of claim 1 further comprising displaying the parameter of interest in at least one of:

(i) a tabular display; and

(ii) a graphical display

20. The method of claim 1 wherein calibrating the estimated seismic velocities further comprises:

(i) deleting or correcting for zones of abnormal velocity caused by the presence of hydrocarbon fluids; and

(ii) deleting zones of abnormal velocity caused by the presence of non-clastic rocks.

21. The method of claim 1 further comprising at least one of:

(i) determining an overburden stress from a density function based on inversion of 2-D or 3-D potential fields;

(ii) determining an overburden stress from a density function derived by performing a simultaneous inversion of PP and PS data;

(iii) correcting for zones of abnormal density caused by the presence of hydrocarbon fluids by inserting a correct density for said zones and recalculating the overburden at the specific location;

(iv) correcting for zones of abnormal velocity caused by the presence of hydrocarbon fluids by deleting said zones from the calculation of the parameter of interest;

(v) correcting for zones of abnormal density caused by the presence of non-clastic rocks by inserting a correct density for said zones and recalculating the overburden at the specific location; and

(vi) correcting for zones of abnormal velocity caused by the presence of non-clastic rocks by deleting said zones from the calculation of the parameter of interest.

22. The method of claim 1 further comprising at least one of:

(i) using an interactive help menu;

(ii) performing a coordinate transformation; and

(iii) automatically propagating results of an editing.

23. The method of claim 3 wherein the calibration includes the estimation of an overburden-depth relationship that is determined by integrating density data obtained by inversion of 2-D or 3-D potential fields data.

24. The method of claim 3 wherein the calibration includes the estimation of an overburden-depth relationship that is determined by integrating density data obtained by inversion of at least one of 2-D or 3-D seismic data, and wherein said seismic data further comprise at least one of PP data and PS data.

26. The method of claim 25 wherein calibrating the estimated seismic velocities further comprises at least one of:

(i) using a function determined independently from the seismic data using regional information

(ii) using data from a well corresponding to a specific calibration location that is outside the areal extent of the seismic velocity data.

(iii) using data from a well corresponding to a specific calibration location within the areal extent of the seismic velocity data.

(iv) using data from a well corresponding to a specific calibration location within the areal extent of the seismic velocity data combined with the velocity data from the seismic survey for the same said location.

27. The method of claim 26 where calibrating the estimated seismic velocities includes further comprises estimating an overburden-depth relationship by integrating density data from at least one of:

I. a 1-D density function derived from density logs from at least one well;

II. a 1-D density function derived from density data from drop cores, side-wall cores or conventional cores;

III. a spatially varying density function based on the inversion of potential fields data, said potential fields data comprising at least one of gravity data, and magnetic data;

IV. a density function derived by performing an inversion of at least one of PP data, and PS data.

28. The method of claim 25 wherein obtaining seismic velocity data further comprises using seismic processing techniques that include at least one of:

(i) Dip Move out (DMO)

(ii) Pre-stack time migration

(iii) Pre-stack depth migration

(iv) Multiple attenuation or suppression

(v) Reflection statics

(vi) Refraction statics

(vii) Wavefield reconstruction

(viii) The combination in undersampled seismic data from several gathers to form super-gathers.

29. The method of claim 25 wherein the parameter of interest is selected from the group consisting of:

(i) fluid pressure

(ii) fracture gradient

(iii) overburden pressure

(iv) effective stress

(v) excess pressure, defined as the difference between the actual fluid pressure and the normal pressure for the same depth

30. The method of claim 25 further comprising using the parameter of interest to perform further analysis at one of the following scales:

I. the scale of a specific well location, defined as a projected one-dimensional path that will be used to place a wellbore into the subsurface

II. the scale of an exploration prospect

III. the scale of a regional pressure evaluation to understand hydrocarbon systems

31. The method of claim 26 further comprising using the parameter of interest for performing specific analyses of the subsurface including at least one of the following:

I. basin modeling

II. hydrocarbon maturation in source rock intervals

III. lateral and vertical seal rock integrity

IV. fault seal integrity

V. evaluation of fluid migration pathways in the subsurface

VI. reservoir-specific lateral pressure changes

VII. shallow water flow risk evaluation

VIII. wellbore stability and failure analysis

32. The method of claim 25 wherein the seismic survey comprises one of:

(i) P-wave land seismic data

(ii) S-wave land seismic data

(iii) mode-converted S-wave land data (land PS data)

(iv) mode-converted S-wave marine ocean-bottom cable data (marine PS data)

(v) P-wave marine streamer data

(vi) P-wave marine ocean bottom cable data (PP data)

33. The method of claim 26 wherein the data from a well comprises at least one of:

I. sonic logs

II. shear sonic logs

III. density logs

IV. Lithology logs in the form of gamma ray or Spontaneous Potential logs

V. formation fluid pressure data. (further dependent claims)

VI. formation fracture pressures in the form of Leak Off Tests

34. The method of claim 25 wherein using the results of said calibration and the obtained seismic velocities to obtain the parameter of interest further comprises using at least one of:

(ii) the Eaton method

(ii) the effective stress method

(iii) the equivalent depth method

35. The method of claim 25 wherein calibrating the estimated seismic velocities further comprises using at least one of:

(i) a linear curve fitting

(ii) a curve fitting based on a power law

(iii) a curve fitting based on exponentials,

(iv) a quadratic curve fitting.

36. The method of claim 26 wherein calibrating the estimated seismic velocities further comprises:

using an interactive display, said interactive display allowing modification of a displayed calibration curve and observing changes in a plurality of other displayed curves simultaneously, said interactive display further allowing at least one of;

I. manually changing a coefficient or exponent in the fitting equation, and

II. using a cursor to graphically manipulate the fitting curve.

37. The method of claim 25 further comprising:

obtaining a porosity calibration curve from well data using at least one of;

(i) editing of erroneous porosity values for at least one well;

(ii) displaying in a single plot, a depth-correlated porosity and velocity data for the at least one well;

(iii) curve fitting of the velocity and porosity data using at least one of;

I a linear curve fitting

II. a curve fitting based on a power law

III. a curve fitting based on exponentials,

IV. a quadratic curve fitting; and

predicting porosity at a specified location using the obtained porosity calibration curve and the seismic velocity data from the specified location.

38. The method of claim 25 wherein the parameter of interest is a fracture gradient, the method further comprising:

(i) deleting erroneous leak-off test values for at least one well;

(ii) displaying depth-correlated leak-off test and overburden data for the at least one well, and

(iii) applying one of the two following methods

I. curve fitting of the leak off test data to determine a fracture gradient, and

II. applying an appropriate stress ratio (Ko) to fit the leak-off test data.

39. The method of claim 25 further comprising displaying the parameter of interest on one of:

(i) stacked seismic section, and

(ii) migrated seismic section.

40. The method of claim 25 further comprising displaying the parameter of interest interactively and simultaneously on at least one of:

(i) a seismic display

(ii) a velocity versus depth display including a velocity function for a specific location and a calibration function for velocity versus effective stress,

(iii) a stress versus depth display including the overburden stress calibration for said specific location and the effective stress calculated from the velocity versus depth display,

(iv) a pressure-gradient versus depth display including the fracture gradient or overburden gradient, the fluid pressure gradient calculated from the stress versus depth display, and pressure data points from a well that applies to said specific location.

41. The method of claim 25 wherein the at least one pair of the plurality of seismic horizons comprises at least two pairs, the method further comprising performing step (d) of claim 1 separately for each of the at least two pairs of seismic horizons.

42. The method of claim 25 further comprising displaying the parameter of interest in at least one of:

(i) a tabular display; and

(ii) a graphical display

43. The method of claim 25 wherein calibrating the estimated seismic velocities at a specific location further comprises:

(i) deleting or correcting for zones of abnormal velocity caused by the presence of hydrocarbon fluids; and

(ii) deleting zones of abnormal velocity caused by the presence of non-clastic rocks.

44. The method of claim 25 further comprises using at least one of:

(i) determining an overburden stress from a density function based on inversion of 2-D or 3-D potential fields;

(ii) determining an overburden stress from a density function derived by performing a simultaneous inversion of PP and PS data;

(iii) correcting for zones of abnormal density caused by the presence of hydrocarbon fluids by inserting a correct density for said zones and recalculating the overburden at the specific location;

(iv) correcting for zones of abnormal velocity caused by the presence of hydrocarbon fluids by deleting said zones from the calculation of the parameter of interest;

(v) correcting for zones of abnormal density caused by the presence of non-clastic rocks by inserting a correct density for said zones and recalculating the overburden at the specific location; and

(vi) correcting for zones of abnormal velocity caused by the presence of non-clastic rocks by deleting said zones from the calculation of the parameter of interest.

45. The method of claim 25 further comprising at least one of:

(i) using an interactive help menu;

(ii) performing a coordinate transformation; and

(iii) automatically propagating results of an editing.

46. The method of claim 27 wherein the calibration includes the estimation of an overburden-depth relationship that is determined by integrating density data obtained by inversion of 2-D or 3-D potential fields data.

47. The method of claim 27 wherein the calibration includes the estimation of an overburden-depth relationship that is determined by integrating density data obtained by inversion of at least one of 2-D or 3-D seismic data, and wherein said seismic data further comprise at least one of PP data and PS data.

25. A method for determining a parameter of interest of a subsurface region of earth formations comprising:

(a) obtaining seismic survey information about the subsurface region;

(b) obtaining estimated seismic velocities corresponding to at least one interval of the subsurface from;

(i) coherency inversion analysis of P-wave or S-wave seismic data;

(ii) pre-stack inversion of P-wave seismic data;

(iii) post-stack inversion of P-wave seismic data;

(iv) pre-stack inversion of S-wave seismic data;

(v) post-stack inversion of S-wave seismic data;

(vi) normal moveout (NMO) velocity analysis of S-wave seismic data;

(vii) tomographic analysis of P-wave seismic data;

(viii) tomographic analysis of S-wave seismic data;

(ix) analysis of P-wave data from vertical seismic profiling (VSP) data;

(x) analysis of P-wave data from inversion of VSP look-ahead data;

(xi) analysis of S-wave data from vertical seismic profiling (VSP) data

(xii) analysis of S-wave data from inversion of VSP look-ahead data;

(c) calibrating the estimated seismic velocities to the parameter of interest

(d) using the results of said calibration and the obtained seismic velocities to obtain the parameter of interest at any location within the seismic survey.

48. A method for determining fluid pressure in a subsurface region of earth formations comprising:

(a) obtaining seismic survey information about the subsurface region;

(b) identifying a plurality of interpreted seismic horizons of interest from the obtained survey information;

(c) obtaining estimated seismic velocities corresponding to at least one interval between at least one pair of said plurality of seismic horizons;

(d) calibrating the estimated seismic velocities to the parameter of interest

(e) using the results of said calibration and the obtained seismic velocities to obtain the parameter of interest at any location within the seismic survey.

49. A method for determining an effective stress in a subsurface region of earth formations comprising:

(a) obtaining seismic survey information about the subsurface region;

(b) identifying a plurality of interpreted seismic horizons of interest from the obtained survey information;

(c) obtaining estimated seismic velocities corresponding to at least one interval between at least one pair of said plurality of seismic horizons;

(d) calibrating the estimated seismic velocities to the parameter of interest

(e) using the results of said calibration and the obtained seismic velocities to obtain the parameter of interest at any location within the seismic survey.

50. A method for determining fluid pressure in a subsurface region of earth formations comprising:

(a) obtaining seismic survey information about the subsurface region;

(b) obtaining estimated seismic velocities corresponding to at least one interval of the subsurface from;

(i) coherency inversion analysis of P-wave or S-wave seismic data;

(ii) pre-stack inversion of P-wave seismic data;

(iii) post-stack inversion of P-wave seismic data;

(iv) pre-stack inversion of S-wave seismic data;

(v) post-stack inversion of S-wave seismic data;

(vi) normal moveout (NMO) velocity analysis of S-wave seismic data;

(vii) tomographic analysis of P-wave seismic data;

(viii) tomographic analysis of S-wave seismic data;

(ix) analysis of P-wave data from vertical seismic profiling (VSP) data;

(x) analysis of P-wave data from inversion of VSP look-ahead data;

(xi) analysis of S-wave data from vertical seismic profiling (VSP) data

(xii) analysis of S-wave data from inversion of VSP look-ahead data;

(c) calibrating the estimated seismic velocities to the parameter of interest

(d) using the results of said calibration and the obtained seismic velocities to obtain the parameter of interest at any location within the seismic survey.

51. A method for determining an effective stress in a subsurface region of earth formations comprising:

(a) obtaining seismic survey information about the subsurface region;

(b) obtaining estimated seismic velocities corresponding to at least one interval of the subsurface from;

(i) coherency inversion analysis of P-wave or S-wave seismic data;

(ii) pre-stack inversion of P-wave seismic data;

(iii) post-stack inversion of P-wave seismic data;

(iv) pre-stack inversion of S-wave seismic data;

(v) post-stack inversion of S-wave seismic data;

(vi) normal moveout (NMO) velocity analysis of S-wave seismic data;

(vii) tomographic analysis of P-wave seismic data;

(viii) tomographic analysis of S-wave seismic data;

(ix) analysis of P-wave data from vertical seismic profiling (VSP) data;

(x) analysis of P-wave data from inversion of VSP look-ahead data;

(xi) analysis of S-wave data from vertical seismic profiling (VSP) data

(xii) analysis of S-wave data from inversion of VSP look-ahead data;

(c) calibrating the estimated seismic velocities to the parameter of interest

(d) using the results of said calibration and the obtained seismic velocities to obtain the parameter of interest at any location within the seismic survey.