Formation modeling while drilling for enhanced high angle for horizontal well placement

• US 8,489,375 B2
• Filed: 09/08/2008
• Issued: 07/16/2013
• Est. Priority Date: 10/22/2007
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Original Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Inventors: Omeragic, Dzevat, Habashy, Tarek M., Polyakov, Valery, Kocian, Raymond, Chen, Yong-Hua, Davydycheva, Sofia, Altman, Raphael, Maeso, Carlos, Hupp, Douglas
• Primary Examiner(s): Thangavelu, Kandasamy
• Application Number:
  US12/738,225
• Publication Number:
  US 20110106514A1
• Time in Patent Office: 1,772 Days
• Field of Search: 703/10, 702/6, 702/9, 333/04, 367/37, 324/303
• 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

LWD measurements to be used for proactive well placement while drilling a high angle or horizontal wellbore in a reservoir are defined. An initial reservoir model is provided and a section is extracted for a planned wellbore trajectory. A secondary model is generated for the planned trajectory. An area of interest is identified where statistical uncertainty is high. Possible causes of the statistical uncertainty are identified that are not present in the initial reservoir model. A set of parameters are defined based on the possible causes of statistical uncertainty. The area of interest is logged with LWD tool. Sensitivities of the LWD tool response to a subset of parameters are evaluated by performing tertiary model for a range of the subset of parameters. The most sensitive parameters from the subset of parameters and corresponding measurements are identified. LWD measurements are defined based on the most sensitive parameters.

Claims

1. A method for defining logging while drilling measurements to be used for proactive well placement while drilling a high angle or horizontal wellbore in a reservoir, 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, using a computer, a secondary model by performing secondary modeling for at least part of the planned trajectory;

identifying, using the computer, 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, using the computer, logging tool responses in the area of interest for at least one logging while drilling tool;

evaluating, using the computer, sensitivities of the modeled logging tool responses to a subset of the set of parameters by generating and assessing at least one tertiary model for a range of the subset of parameters;

identifying, using the computer, which parameters correlate to greatest sensitivities in the modeled logging tool responses from the subset of parameters and corresponding logging while drilling measurements; and

defining, using the computer, one or more logging while drilling measurements to be used for proactive well placement along the planned trajectory based on the parameters that correlate to the greatest sensitivities in the modeled logging tool responses.

2. The method of claim 1, further comprising:

identifying characteristic patterns of the modeled 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 comprise 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 comprise 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 comprise 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, and wellbore fluid properties.

6. The method of claim 1, wherein the defined possible causes of statistical uncertainty comprise 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, and quality of cement bond between casing and formation.

7. The method of claim 1, wherein the defined possible causes of statistical uncertainty comprise 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 while drilling tool.

9. The method of claim 1, wherein the generating of the secondary model further comprises performing tool response modeling on 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 while drilling tool responses do not match the secondary model.

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

a) executing 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 parameters that correlate to the greatest sensitivities in the modeled logging tool responses;

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

d) comparing 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 other models and repeating parts (a) through (d) until the first and second results agree within the predetermined tolerance level.

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

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 the area of interest;

inserting new boundaries;

inserting new faults;

defining a new oil-water contact; and

defining a new gas-oil contact.

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 while drilling tool comprises a resistivity imaging tool or an electromagnetic boundary mapping tool.

17. The method of claim 16, wherein the at least one logging while drilling 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.

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 at least to the reservoir forward modeling library, the inversion library, and a well placement or formation evaluation station;

wherein

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

wherein the system is configured to perform the method of claim 1 or claim 18.

35. The system of claim 34, wherein the reservoir forward modeling 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 computing of multiple algorithms.

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

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

11. The method of claim wherein the defining of possible causes of the statistical uncertainty in the 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.

18. A method for defining logging while drilling measurements to be used for proactive well placement while drilling a high angle or horizontal wellbore in a reservoir, 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, using a computer, a secondary model by performing secondary modeling for at least part of the planned trajectory;

identifying, using the computer, 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;

logging the area of interest with at least one logging while drilling tool to produce logging while drilling tool responses;

evaluating, using the computer, sensitivities of the produced logging while drilling tool responses to a subset of the set of parameters by generating and assessing at least one tertiary model for a range of the subset of parameters;

identifying, using the computer, which parameters correlate to greatest sensitivities in the produced logging while drilling tool responses from the subset of parameters and corresponding logging while drilling measurements; and

defining, using the computer, one or more logging while drilling measurements to be used for proactive well placement along the planned trajectory based on the parameters that correlate to the greatest sensitivities in the produced logging while drilling tool responses.

19. The method of claim 18, further comprising:

identifying characteristic patterns of the produced logging while drilling 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 comprise 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 comprise 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 comprise 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, and wellbore fluid properties.

23. The method of claim 18, wherein the defined possible causes of statistical uncertainty comprise 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, and quality of cement bond between casing and formation.

24. The method of claim 18, wherein the defined possible causes of statistical uncertainty comprise 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 while drilling tool.

26. The method of claim 18, wherein the generating of the secondary model further comprises performing tool response modeling on 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 while drilling tool responses do not match the secondary model.

28. The method of claim 27, wherein the defining of possible causes of the statistical uncertainty in the 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) executing 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 parameters that correlate to the greatest sensitivities in the produced logging while drilling tool responses;

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

d) comparing 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 other 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 the area of interest;

inserting new boundaries;

inserting new faults;

defining a new oil-water contact; and

defining a new gas-oil contact.

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

32. The method of claim 18, wherein the at least one logging while drilling tool comprises a resistivity imaging tool or an electromagnetic boundary mapping tool.

33. The method of claim 32, wherein the at least one logging while drilling 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.