FORMATION MODELING WHILE DRILLING FOR ENHANCED HIGH ANGLE FOR HORIZONTAL WELL PLACEMENT

• US 20110106514A1
• Filed: 09/08/2008
• Published: 05/05/2011
• Est. Priority Date: 10/22/2007
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Original Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Inventors: Chen, Yong-Hua, Maeso, Carlos, Omeragic, Dzevat, Polyakov, Valery, Hupp, Douglas, Altman, Raphael, Kocian, Raymond, Habashy, Tarek M., Davydycheva, Sofia
• Granted Patent: US 8,489,375 B2
• Time in Patent Office: Days
• US Class Current: 703/10
• CPC Class Codes: G01V 11/00 Prospecting or detecting by methods combining techniques covered by two or more of main groups G01V1/00 - G01V9/00

Abstract

Methods for three-dimensionally characterizing a reservoir while drilling a high angle or horizontal wellbore through the reservoir are disclosed. An initial reservoir model for the reservoir is selected and a section is extracted for a planned trajectory of the wellbore. A secondary model is generated by performing secondary modeling for at least part of the planned trajectory. An area of interest is identified within the secondary model where statistical uncertainty is high. Possible causes of the statistical uncertainty are identified for the area of interest within the secondary model that are not present or accounted for in the initial reservoir model. A set of parameters for the area of interest are defined at that are based on the possible causes of statistical uncertainty. The area of interest is logged with at least one logging while drilling LWD tool. Sensitivities of the LWD tool response to the subset of parameters are evaluated by performing at least one tertiary model for a range of the subset of parameters. The most sensitive parameters from the subset of parameters and corresponding measurements are identified. One or more real-time LWD measurements to be used for proactive well placement along the planned trajectory are identified and are based on the most sensitive parameters. The initial reservoir model is updated while drilling with information from the tertiary model. The model update is based on physics-based modeling or on inversion and on running multiple models and selection of a best candidate model based on correlations between the tool measurements and modeled results for each geologic model.

Claims

1. A method of three-dimensionally characterizing a reservoir using logging while drilling measurements from a high angle or horizontal wellbore, the method comprising:

providing an initial reservoir model for the reservoir;

extracting a section of the reservoir model for a planned trajectory of the wellbore;

generating a secondary model by performing secondary modeling for at least part of the planned trajectory;

identifying an area of interest within the secondary model where statistical uncertainty is high;

defining possible causes of the statistical uncertainty in the area of interest within the secondary model that are not present in the initial reservoir model;

defining a set of parameters for the area of interest based on the possible causes of statistical uncertainty;

modeling the well logging tool response in the area of interest with at least one logging tool;

evaluating sensitivities of the logging tool responses to the subset of parameters by performing at least one tertiary model for a range of the subset of parameters;

identifying the most sensitive parameters from the subset of parameters and corresponding measurements;

defining one or more real-time logging measurements to be used for proactive well placement along the planned trajectory based on the most sensitive parameters.

2. The method of claim 1 further comprising:

identifying characteristic patterns of the logging tool responses to changes in the subset of parameters;

generating a data base of measurement responses to be used in real-time well placement based on measurement sensitivity; and

defining a subset of measurements while drilling to be used in real-time interpretation as the wellbore is drilled though the reservoir.

3. The method of claim 1 wherein the defined possible causes of statistical uncertainty comprises one or more nearby bed boundaries or nearby faults and the set of parameters is selected from the group consisting of position, dip and azimuth for nearby boundaries, and shape of nearby non-parallel boundaries or nearby faults.

4. The method of claim 1 wherein the defined possible causes of statistical uncertainty comprises one or more nearby formation layers and the set of parameters is selected from the group consisting of resistivity, transversely isotropic (TI) anisotropy, anisotropy dip and azimuth for the one or more nearby formation layers.

5. The method of claim 1 wherein the defined possible causes of statistical uncertainty comprises wellbore fluid invasion and the set of parameters is selected from the group consisting of radial depth of wellbore fluid invasion, cross sectional shape of wellbore fluid invasion profile, wellbore fluid properties.

6. The method of claim 1 wherein the defined possible causes of statistical uncertainty comprises wellbore properties and the set of parameters is selected from the group consisting of wellbore size, wellbore shape, wellbore fluid resistivity, water saturation (Sw) and porosity, presence of casing, presence of casing and cement, quality of cement bond between casing and formation.

7. The method of claim 1 wherein the defined possible causes of statistical uncertainty comprises one or more nearby fractures and the set of parameters is selected from the group consisting of position, orientation, and properties of the one or more nearby fractures and wherein the extracted section is one-dimensional, two-dimensional or three dimensional.

8. The method of claim 1 wherein the extracted section is defined by a depth of investigation of the logging tool.

9. The method of claim 1 wherein the generating of the secondary model further comprises performing tool response modeling at least part of the planned trajectory.

10. The method of claim 1 wherein the area of interest within the secondary model is further characterized as an area where the logging tool response does not match the secondary model.

11. The method of claim 1 wherein the defining of possible causes of the statistical uncertainty in area of interest within the secondary model and the defining of the set of parameters for the area of interest based on the possible causes of statistical uncertainty further comprises selecting the tertiary model from the group consisting of nearby bed boundaries, nearby formation layers, nearby faults, properties of wellbore fluid invasion, oil water contact (OWC), gas oil contact (GOC), wellbore properties and nearby fractures, wherein the tertiary model is not present in the secondary model.

15. The method of claim 1 wherein the initial reservoir model is a seismic reservoir model.

16. The method of claim 1 wherein the at least one logging tool comprises a resistivity imaging tool or an electromagnetic boundary mapping tool.

17. The method of claim 16 wherein the at least one logging tool comprises a plurality of tools including a resistivity imaging tool and a resistivity mapping tool, and

wherein the initial reservoir model is modified using measurements from both the resistivity imaging and resistivity mapping tools.

13. The method of claim 1 further comprising selecting the tertiary model from a plurality of other models by:

a) performing one of the other models for the range of the subset of parameters to generate a first result;

b) changing at least one of the most sensitive parameters;

c) performing the one of the other models for the range of the subset of changed parameters to generate a second result;

d) compare the first and second results;

e) if the first and second results do not agree to within a predetermined tolerance level, selecting another model from the plurality of models and repeating parts (a) through (d) until the first and second results agree within the predetermined tolerance level.

14. The method of claim 13 wherein the modifying of the initial reservoir model further comprises at least one change selected from the group consisting of:

changing a position or shape of a formation layer boundary;

changing a position or shape of a fault;

changing a layer property;

changing a cell property;

defining a heterogeneity in area of interest;

inserting new boundaries;

inserting new faults;

defining a new OWC contact; and

defining a new GOC contact.

13-1. The method of claim 12 further comprising modifying the initial reservoir model by incorporating the selected tertiary model therein.

18. A method of three-dimensionally characterizing a reservoir while drilling a high angle or horizontal wellbore, the method comprising:

providing an initial reservoir model for the reservoir;

extracting a section of the reservoir model for a planned trajectory of the wellbore;

generating a secondary model by performing secondary modeling for at least part of the planned trajectory;

identifying an area of interest within the secondary model where statistical uncertainty is high;

defining possible causes of the statistical uncertainty in area of interest within the secondary model that are not present in the initial reservoir model;

defining a set of parameters for the area of interest based on the possible causes of statistical uncertainty;

logging tool response in the area of interest with at least one logging tool;

evaluating sensitivities of the logging tool responses to the subset of parameters by performing at least one tertiary model for a range of the subset of parameters;

identifying the most sensitive parameters from the subset of parameters and corresponding measurements.

19. The method of claim 18 further comprising:

identifying characteristic patterns of the logging tool responses to changes in the subset of parameters;

generating a data base of measurement responses to be used in real-time well placement based on measurement sensitivity; and

defining a subset of measurements while drilling to be used in real-time interpretation as the wellbore is drilled though the reservoir.

20. The method of claim 18 wherein the defined possible causes of statistical uncertainty comprises one or more nearby bed boundaries or nearby faults and the set of parameters is selected from the group consisting of position, dip and azimuth for nearby boundaries, and shape of nearby non-parallel boundaries or nearby faults.

21. The method of claim 18 wherein the defined possible causes of statistical uncertainty comprises one or more nearby formation layers and the set of parameters is selected from the group consisting of resistivity, transversely isotropic (TI) anisotropy, anisotropy dip and azimuth for the one or more nearby formation layers.

22. The method of claim 18 wherein the defined possible causes of statistical uncertainty comprises wellbore fluid invasion and the set of parameters is selected from the group consisting of radial depth of wellbore fluid invasion, cross sectional shape of wellbore fluid invasion profile, wellbore fluid properties.

23. The method of claim 18 wherein the defined possible causes of statistical uncertainty comprises wellbore properties and the set of parameters is selected from the group consisting of wellbore size, wellbore shape, wellbore fluid resistivity, water saturation (Sw) and porosity, presence of casing, presence of casing and cement, quality of cement bond between casing and formation.

24. The method of claim 18 wherein the defined possible causes of statistical uncertainty comprises one or more nearby fractures and the set of parameters is selected from the group consisting of position, orientation, and properties of the one or more nearby fractures.

25. The method of claim 18 wherein the extracted section is defined by a depth of investigation of the logging tool.

26. The method of claim 18 wherein the generating of the secondary model further comprises performing tool response modeling of at least part of the planned trajectory.

27. The method of claim 18 wherein the area of interest within the secondary model is further characterized as an area where the logging tool response does not match the secondary model.

28. The method of claim 27 wherein the defining of possible causes of the statistical uncertainty in area of interest within the secondary model and the defining of the set of parameters for the area of interest based on the possible causes of statistical uncertainty further comprises selecting the tertiary model from the group consisting of nearby bed boundaries, nearby formation layers, nearby faults, properties of wellbore fluid invasion, oil water contact (OWC), gas oil contact (GOC), wellbore properties and nearby fractures.

29. The method of claim 18 further comprising selecting the tertiary model from a plurality of other models by:

a) performing one of the other models for the range of the subset of parameters to generate a first result;

b) changing at least one of the most sensitive parameters;

c) performing the one of the other models for the range of the subset of changed parameters to generate a second result;

d) compare the first and second results;

e) if the first and second results do not agree to within a predetermined tolerance level, selecting another model from the plurality of models and repeating parts (a) through (d) until the first and second results agree within the predetermined tolerance level.

30. The method of claim 29 further comprising modifying the initial reservoir model by incorporating the selected tertiary model therein, wherein the modifying of the initial reservoir model further comprises at least one change selected from the group consisting of:

changing a position or shape of a formation layer boundary;

changing a position or shape of a fault;

changing a layer property;

changing a cell property;

defining a heterogeneity in area of interest;

inserting new boundaries;

inserting new faults;

defining a new OWC contact; and

defining a new GOC contact.

31. The method of claim 18 wherein the initial reservoir model is a seismic reservoir model.

32. The method of claim 19 wherein the at least one logging tool comprises a resistivity imaging tool or an electromagnetic boundary mapping tool.

33. The method of claim 32 wherein the at least one logging tool comprises a plurality of tools including a resistivity imaging tool and a resistivity mapping tool, and

wherein the initial reservoir model is modified using measurements from both the resistivity imaging and resistivity mapping tools.

comprising updating the initial reservoir model with the best candidate model.

34. A system for three-dimensionally characterizing a reservoir while drilling a high angle or horizontal wellbore through the reservoir, the system comprising:

a reservoir modeling and visualization environment;

a reservoir forward modeling library;

an inversion algorithm library;

a high performance computing (HPC) infrastructure linked to the reservoir and inversion libraries, a well placement or formation evaluation station;

the well placement or formation evaluation station comprising a display for displaying two and three dimensional models of the wellbore before, during drilling for geo-steering purposes, and after drilling for refinement of reservoir model.

35. The system of claim 34 wherein the reservoir model library comprises two and three dimensional modeling codes for electro-magnetic (EM), acoustic, fluid flow and nuclear tools.

36. The system of claim 34 wherein the inversion algorithm library comprises deterministic and probabilistic inversion algorithms.

37. The system of claim 34 wherein the HPC infrastructure is linked to a plurality of logging control centers located at a plurality of sites and the HPC infrastructure comprises parallelization, scheduling and load-balancing for the computing of multiple algorithms.

38. The system of claim 34 wherein the HPC infrastructure comprises a one or more of subsystems selected from the group consisting of computing clusters, multiple-core personal computers, and multiple operating systems.

39. The system of claim 34, where reservoir modeling and visualization environment is web-browser based.