Method for determining rock matrix and fracture permeability by using poroelastodynamics and density averaging schemes

Patent metadata

Field	Value
Publication number	US-12378881-B2
Application number	US-202217804273-A
Country	US
Kind code	B2
Filing date	May 26, 2022
Priority date	May 26, 2022
Publication date	Aug 5, 2025
Grant date	Aug 5, 2025

Abstract

A method of determining rock matrix and fracture permeability to perform a reservoir fluid flow simulation. The method includes: obtaining a petrophysical characterization of a formation sample, measuring a first and second elastic wave velocity of the formation sample at a first and second frequency, calculating an average rock matrix density and an average porosity of the formation sample, determining a set of calculated elastic wave velocities for the first and second frequencies over a range of candidate permeabilities, and determining a rock matrix permeability and a fracture permeability based on the set of calculated elastic wave velocities at the first and second frequency respectively. The method further including performing a reservoir fluid flow simulation based, at least in part, on at least one of the rock matrix permeability and the fracture permeability.

First claim

What is claimed:

1. A method comprising:
obtaining a petrophysical characterization of a formation sample;
measuring a first elastic wave velocity of the formation sample at a first frequency and measuring a second elastic wave velocity of the formation sample at a second frequency, wherein the first frequency is lower than the second frequency;
calculating, based on the petrophysical characterization, an average rock matrix density and an average porosity of the formation sample;
determining a first set of calculated elastic wave velocities at the first frequency over a range of candidate rock matrix permeabilities using the average rock matrix density and the average porosity;
determining a second set of calculated elastic wave velocities at the second frequency over a range of candidate fracture permeabilities using the average rock matrix density and the average porosity;
determining a rock matrix permeability based on the first set of calculated elastic wave velocities, the range of candidate rock matrix permeabilities, and the first elastic wave velocity;
determining a fracture permeability based on the second set of calculated elastic wave velocities, the range of candidate fracture permeabilities, and the second elastic wave velocity; and
performing a reservoir fluid flow simulation based on at least one of the rock matrix permeability or the fracture permeability;
determining a wellbore path based on the reservoir fluid flow simulation; and
drilling, using a drilling system, a wellbore guided by the wellbore path.

2. The method of claim 1 , wherein each of the average rock matrix density and the average porosity comprises an arithmetic mean, a geometric mean, or a harmonic mean.

3. The method of claim 1 , wherein:
the first elastic wave velocity comprises a measured P-wave phase velocity;
the first set of calculated elastic wave velocities at the first frequency comprises a first set of calculated P-wave phase velocities; and
the second set of calculated elastic wave velocities at the second frequency comprises a second set of calculated P-wave phase velocities.

4. The method of claim 1 , further comprising:
obtaining the formation sample from a formation; and
determining at least one petrophysical characteristic among the petrophysical characterization from the formation sample.

5. The method of claim 1 , wherein the petrophysical characterization of the formation sample comprises at least one of a density of a mineral grain within the formation sample, a volume fraction of the mineral grain, a density of an organic material within the formation sample, a volume fraction of the organic material, a porosity of the formation sample, or a volume fraction of a fracture within the formation sample.

6. A system comprising:
a core sample analyzer configured to determine:
a petrophysical characterization of a formation sample, and
a first elastic wave velocity at a first frequency and a second elastic wave velocity at a second frequency for the formation sample, wherein the first frequency is lower than the second frequency; and

a computer processor configured to:
receive the petrophysical characterization of the formation sample;
receive the first elastic wave velocity of the formation sample at the first frequency and the second elastic wave velocity of the formation sample at the second frequency, wherein the first frequency is lower than the second frequency;
calculate, based on the petrophysical characterization, an average rock matrix density and an average porosity of the formation sample;
determine a first set of calculated elastic wave velocities at the first frequency over a range of candidate rock matrix permeabilities using the average rock matrix density and the average porosity;
determine a second set of calculated elastic wave velocities at the second frequency over a range of candidate fracture permeabilities using the average rock matrix density and the average porosity;
determine a rock matrix permeability based on the first set of calculated elastic wave velocities, the range of candidate rock matrix permeabilities, and the first elastic wave velocity;
determine a fracture permeability based on the second set of calculated elastic wave velocities, the range of candidate fracture permeabilities, and the second elastic wave velocity;
perform a reservoir fluid flow simulation based on at least one of the rock matrix permeability or the fracture permeability;
determine a wellbore path based on the reservoir fluid flow simulation; and

a drilling system configured to drill a wellbore guided by the wellbore path.

7. The system according to claim 6 , wherein each of the average rock matrix density and the average porosity comprises an arithmetic mean, a geometric mean, or a harmonic mean.

8. The system according to claim 6 , wherein:
the first elastic wave velocity comprises a measured P-wave phase velocity;
the first set of calculated elastic wave velocities at the first frequency comprises a first set of calculated P-wave phase velocities; and
the second set of calculated elastic wave velocities at the second frequency comprises a second set of calculated P-wave phase velocities.

9. The system according to claim 6 , wherein the petrophysical characterization of the formation sample comprises at least one of a density of a mineral grain within the formation sample, a volume fraction of the mineral grain, a density of an organic material within the formation sample, a volume fraction of the organic material, a porosity of the formation sample, or a volume fraction of a fracture within the formation sample.

10. A non-transitory computer readable medium storing a set of instructions executable by a computer processor, the set of instructions comprising functionality for:
receiving a petrophysical characterization of a formation sample;
receiving a first elastic wave velocity of the formation sample at a first frequency and a second elastic wave velocity of the formation sample at a second frequency, wherein the first frequency is lower than the second frequency;
calculating, based on the petrophysical characterization, an average rock matrix density and an average porosity of the formation sample;
determining a first set of calculated elastic wave velocities at the first frequency over a range of candidate rock matrix permeabilities using the average rock matrix density and the average porosity;
determining a second set of calculated elastic wave velocities at the second frequency over a range of candidate fracture permeabilities using the average rock matrix density and the average porosity;
determining a rock matrix permeability based on the first set of calculated elastic wave velocities, the range of candidate rock matrix permeabilities, and the first elastic wave velocity;
determining a fracture permeability based on the second set of calculated elastic wave velocities, the range of candidate fracture permeabilities, and the second elastic wave velocity;
performing a reservoir fluid flow simulation based on at least one of the rock matrix permeability or the fracture permeability;
determining a wellbore path based on the reservoir fluid flow simulation, wherein a wellbore guided by the wellbore path is drilled by a drilling system.

11. The non-transitory computer readable medium of claim 10 , wherein:
the first elastic wave velocity comprises a measured P-wave phase velocity;
the first set of calculated elastic wave velocities at the first frequency comprises a first set of calculated P-wave phase velocities; and
the second set of calculated elastic wave velocities at the second frequency comprises a second set of calcula

Assignees

• Aramco Services Co
• Saudi Arabian Oil Co

Inventors

• Liu Chao
• Kazei Vladimir
• Phan Dung T
• Abousleiman Younane N

Classifications

• G01V1/306 Primary

  for determining physical properties of the subsurface, e.g. impedance, porosity or attenuation profiles · CPC title

• E21B49/005

  Testing the nature of borehole walls or the formation by using drilling mud or cutting data · CPC title

• E21B2200/20

  Computer models or simulations, e.g. for reservoirs under production, drill bits · CPC title

• G01N33/241

  for hydrocarbon content · CPC title

• E21B49/088 Primary

  combined with sampling · CPC title