System and method for estimating porosity of porous formations using permittivity measurements

Patent metadata

Field	Value
Publication number	US-12130405-B2
Application number	US-202217950216-A
Country	US
Kind code	B2
Filing date	Sep 22, 2022
Priority date	Sep 30, 2021
Publication date	Oct 29, 2024
Grant date	Oct 29, 2024

Abstract

A system for analysis of isolated and connected porosities of a porous formation using permittivity is disclosed. An electrical subsystem can provide electrical signals for one or more of the porous formation or a representation of the porous formation; and the system can determine one or more of a rate of permittivity change (RPC) or permittivity ratio (PR) from a first estimation model that relates permittivity measurements and frequencies that are associated with the electrical signals, so that the system can generate a second estimation model using one or more of the RPC or the PR, associated with the isolated and connected porosities, where the second estimation model can be used with a total porosity of the porous formation to estimate or predict an isolated porosity and a connected porosity of a production porous formation.

First claim

What is claimed is:

1. A system for downhole wellbore or testing operations, the system comprising:
an electrical subsystem to provide electrical signals for one or more of a porous formation or a representation of the porous formation; and
at least one processor to execute instructions from a memory to cause the system to:
determine one or more dielectric property values that relate changes in permittivity measurements with times or frequencies based in part on the electrical signals;
generate a model using the one or more dielectric property values, the model providing structural property values associated with isolated and connected porosities of the porous formation or the representation of the porous formation;
determine a rock formation petrophysical property value for porous formation or the representation of the porous formation using the model and using a total porosity of the porous formation or the representation of the porous formation;
estimate or predict one or more of an isolated porosity or a connected porosity of a downhole rock formation based at least on the rock formation petrophysical property value; and
enable the wellbore or testing operation based at least in part on the estimated or predicted one or more of the isolated porosity or the connected porosity of the downhole rock formation.

2. The system of claim 1 , wherein the one or more dielectric property values is a rate of permittivity change (RPC) or permittivity ratio (PR).

3. The system of claim 2 , wherein the RPC is a slope of the best-fit at a determined frequency interval of the curve.

4. The system of claim 2 , wherein the PR is a ratio of a first permittivity value and a second permittivity value of the permittivity measures, the first permittivity value being a difference of two permittivity measures taken at two determined frequencies of the curve, and the second permittivity value being a permittivity at a third determined frequency that is higher than the two determined frequencies.

5. The system of claim 1 , wherein the total porosity is one or more of a Nuclear Magnetic Resonance (NMR) measurement, a bulk density measurement, or a neutron porosity measurement associated with the porous formation.

6. The system of claim 1 , wherein the connected porosity of the downhole rock formation is determined using the total porosity and a percentage of the connected porosity (PCP) of the rock formation petrophysical property value.

7. The system of claim 6 , wherein the PCP is determined using one or more of an RPC or a PR of the one or more dielectric property values and using the total porosity, a water saturation measurement, a temperature measurement, a water salinity measurement, a wettability measurement, and a mineralogy measurement for the porous formation or the representation of the porous formation.

8. The system of claim 6 , wherein the isolated porosity is determined using a difference of the total porosity and the connected porosity.

9. The system of claim 1 , wherein the representation of the porous formation comprises one or more of a synthetic model from a random sphere pack or comprises a computerized tomography (CT) image from a reservoir rock.

10. The system of claim 1 , wherein the porous formation or the representation of the porous formation utilizes two samples that are taken alone or as a combination, wherein a first of the two samples has a determined porosity and a second of the two samples has a determined PCP, and wherein the determined porosity and the determined PCP are combined to create the porous formation or the representation of the porous formation.

11. A method for wellbore or testing operations, the method comprising:
providing, using an electrical subsystem, electrical signals for one or more of the porous formation or a representation of the porous formation;
determining, by a processor, one or more dielectric property values that relate changes in permittivity measurements with times or frequencies based in part on the electrical signals;
generating, by the processor, a model using the one or more dielectric property values, the model providing structural property values associated with isolated and connected porosities of the porous formation or the representation of the porous formation;
determining a rock formation petrophysical property value for porous formation or the representation of the porous formation using the model and using a total porosity of the porous formation or the representation of the porous formation;
estimating or predicting one or more of an isolated porosity or a connected porosity of a downhole rock formation based at least on the rock formation petrophysical property value; and
performing the wellbore or testing operation based at least in part on the estimated or predicted one or more of the isolated porosity or the connected porosity of the downhole rock formation.

12. The method of claim 11 , wherein the one or more dielectric property values is a rate of permittivity change (RPC) or permittivity ratio (PR).

13. The method of claim 12 , wherein the RPC is a slope of the best-fit at a determined frequency interval of the curve.

14. The method of claim 13 , wherein the total porosity is one or more of a Nuclear Magnetic Resonance (NMR) measurement, a bulk density measurement, or a neutron porosity measurement associated with the porous formation.

15. The method of claim 12 , wherein the PR is a ratio of a first permittivity value and a second permittivity value of the permittivity measures, the first permittivity value being a difference of two permittivity measures taken at two determined frequencies of the curve, and the second permittivity value being a permittivity at a third determined frequency that is higher than the two determined frequencies.

16. The method of claim 11 , wherein the connected porosity of the downhole rock formation is determined using the total porosity and a percentage of the connected porosity (PCP) of the rock formation petrophysical property value.

17. The method of claim 16 , wherein the PCP is determined using one or more of an RPC or a PR of the one or more dielectric property values and using the total porosity, a water saturation measurement, a temperature measurement, a water salinity measurement, a wettability measurement, and a mineralogy measurement for the porous formation or the representation of the porous formation.

18. The method of claim 16 , wherein the isolated porosity is determined using a difference of the total porosity and the connected porosity.

19. The method of claim 11 , wherein the representation of the porous formation comprises one or more of a synthetic model from a random sphere pack or comprises a computerized tomography (CT) image from a reservoir rock.

20. The method of claim 11 , wherein the porous formation or the representation of the porous formation utilizes two samples that are taken alone or as a combination, wherein a first of the two samples has a determined porosity and a second of the two samples has a determined PCP, and wherein the determined porosity and the determined PCP are combined to create the porous formation or the representation of the porous formation.

Assignees

• Baker Hughes Oilfield Operations Llc
• Saudi Arabian Oil Co

Inventors

• Ma Shouxiang
• Jin Guodong
• Antle Ryan
• Le Fei
• Al-Ofi Salah M

Classifications

• G01V3/32

  operating with electron or nuclear magnetic resonance · CPC title

• G01V3/26

  operating with magnetic or electric fields produced or modified either by the surrounding earth formation or by the detecting device (with electromagnetic waves G01V3/30) · CPC title

• G01V3/18 Primary

  specially adapted for well-logging · CPC title

• G01V3/38 Primary

  Processing data, e.g. for analysis, for interpretation, for correction · CPC title

• E21B49/08 Primary

  Obtaining fluid samples or testing fluids, in boreholes or wells · CPC title