Methods for analyzing natural gas flow in subterranean reservoirs

Patent metadata

Field	Value
Publication number	US-10591399-B2
Application number	US-201615212680-A
Country	US
Kind code	B2
Filing date	Jul 18, 2016
Priority date	Jul 17, 2015
Publication date	Mar 17, 2020
Grant date	Mar 17, 2020

Abstract

The present invention relates to methods for analyzing and modeling natural gas flow in subterranean shale reservoirs. In preferred embodiments, methodologies and techniques for determining and modeling natural gas flow in shale formations using methodologies and techniques capable of determining natural gas properties related to dual-continuum flow, permeability and pressure within a subterranean shale reservoir. In some embodiments, the natural gas properties are determined by subjecting a subterranean shale reservoir sample to pulse-decay analysis. In certain embodiments, the methodologies and techniques described herein may be used in various reservoirs exhibiting macroporosity and/or microporosity, such as fractured reservoirs and carbonate reservoirs composed of reservoir fluids.

First claim

What is claimed is:

1. A method of determining a flow characteristic of a subterranean reservoir formation for the purpose of predicting production capabilities, the method comprising the steps of:
obtaining a reservoir sample from the subterranean reservoir formation;
creating a plurality of pressure pulses across the reservoir sample;
obtaining from the reservoir sample dual-continuum test data, where the dual-continuum test data comprises late-time stage pressure data;
determining a mass transfer coefficient from the dual-continuum test data, wherein the mass transfer coefficient indicates a mass flow rate between two continua of the subterranean reservoir formation divided by a gas pressure difference between the two continua per unit bulk volume of the subterranean reservoir formation; and
determining the flow characteristic from the mass transfer coefficient.

2. The method of claim 1 , where the subterranean formation is selected from the group consisting of limestone, sandstone, and shale.

3. The method of claim 1 , where the dual-continuum test data is obtained from a dual-continuum test system.

4. The method of claim 1 , where the step of obtaining from the reservoir sample the dual-continuum test data further comprises the steps of:
placing the reservoir sample in a sample holder, where the reservoir sample is fluidly connected to an upstream gas reservoir and a downstream gas reservoir, where the sample holder is configured to apply a hydrostatic confining stress to reservoir sample;
filling the upstream gas reservoir, the downstream gas reservoir, and the reservoir sample with a gas to a gas pressure;
closing an upstream valve, where closing the upstream valve isolates upstream gas reservoir from both the downstream gas reservoir and the reservoir sample;
closing a downstream valve, where closing the downstream valve isolates downstream gas reservoir from both the upstream gas reservoir and the sample holder;
increasing the pressure in the upstream gas reservoir to a test pressure;
increasing the pressure in the downstream gas reservoir to the test pressure;
opening the upstream valve generally at the same time the downstream valve is opened such that a plurality pressure pulse is created from the upstream gas reservoir and the downstream gas reservoir; and
measuring the pressure data in the upstream gas reservoir and the downstream gas reservoir.

5. The method of claim 1 , wherein the flow characteristic is dual-continuum flow.

6. The method of claim 1 , wherein the flow characteristic is a function of an immobile continuum and a mobile continuum in the reservoir sample.

7. The method of claim 4 , where the gas pressure in the upstream gas reservoir, the downstream gas reservoir, and the reservoir sample is between 1000 psi and 10,000 psi.

8. The method of claim 4 , where the gas is selected from the group consisting of carbon dioxide, helium, nitrogen, and argon.

9. A system to measure dual-continuum test data, the system comprising:
a sample holder, the sample holder configured to secure a reservoir sample;
an upstream gas reservoir fluidly connected to the sample and a downstream gas reservoir;
a downstream gas reservoir fluidly connected to the sample and the upstream gas reservoir;
an upstream valve, the upstream valve configured to isolate the upstream gas reservoir from both the sample and the downstream gas reservoir; and
a downstream valve, the downstream valve configured to isolate the downstream gas reservoir from both the sample and the upstream gas reservoir,
wherein a mass transfer coefficient is determined from the dual-continuum test data, the mass transfer coefficient indicating a mass flow rate between two continua of the reservoir formation divided by a gas pressure difference between the two continua per unit bulk volume of the reservoir formation.

10. A method of determining a flow characteristic of a subterranean reservoir formation for the purpose of predicting production capabilities, the method comprising the steps of:
obtaining dual-continuum test data, where the dual-continuum test data represents the subterranean reservoir formation;
determining a mass transfer coefficient from the dual-continuum test data, wherein the mass transfer coefficient indicates a mass flow rate between two continua of the subterranean reservoir formation divided by a gas pressure difference between the two continua per unit bulk volume of the subterranean reservoir formation; and
determining the flow characteristic from the mass transfer coefficient.

11. The method of claim 10 , where the subterranean formation is selected from the group consisting of limestone, sandstone, and shale.

12. The method of claim 10 , where the dual-continuum test data is obtained from a dual-continuum test system.

13. The method of claim 10 , wherein the flow characteristic is dual-continuum flow.

14. The method of claim 10 , wherein the flow characteristic is a function of an immobile continuum and a mobile continuum in the reservoir sample.

Assignees

• Aramco Services Co
• Saudi Arabian Oil Co

Inventors

• Liu Hui-Hai
• Lai Bitao
• Chen Jinhong
• Georgi Daniel T

Classifications

• E21B49/02

  by mechanically taking samples of the soil · CPC title

• G01N15/0826 Primary

  and measuring fluid flow rate, i.e. permeation rate or pressure change · CPC title