Reservoir souring forecasting

Patent metadata

Field	Value
Publication number	US-10635762-B2
Application number	US-201615331350-A
Country	US
Kind code	B2
Filing date	Oct 21, 2016
Priority date	Oct 22, 2015
Publication date	Apr 28, 2020
Grant date	Apr 28, 2020

Abstract

A method for modeling reservoir souring using object-oriented numerical solutions separate from reservoir topography is described. Specifically, flow physics are separated into one or more objects, along with one or more H 2 S generation mechanisms, for modeling on time and spatial scales separate from field scale modeling.

First claim

The invention claimed is:

1. A simulation method of a hydrocarbon field development configuration, comprising:
a) providing a computer having one or more parallel graphics processing unit (GPU);
b) providing historical data for a hydrocarbon field;
c) inputting, into said GPU, the network topography, field layout, fluid description, and reservoir characteristics of one or more field configurations to create a field model of said hydrocarbon field;
d) utilizing object-oriented software, on said GPU, for dividing fluid flow physics models of a reservior field configuration the flow physics and H 2 S generation mechanisms of one or more fluids for said one or more field configurations into a plurality of individual basic elements of appropriate units for individual calculation so that the behavior of each individual basic element can be analyzed separately, wherein at least one of said basic elements incorporates said historical data;
e) defining one or more time scales and/or one or more spatial levels for simulating one or more individual basic elements;
f) simulating H 2 S generation and transport and fluid flow for at least one field model and one or more individual basic elements over said time scales and/or spatial level; and,
g) displaying the results of said simulating step.

2. The method of claim 1 , further comprising h) comparing simulation results for one or more field configurations; i) selecting the configuration with the lowest H 2 S generation; and j) creating and implementing a final field development plan to maximize hydrocarbon recovery from said hydrocarbon field.

3. The method of claim 1 , where said individual basic elements contain network parameters such as location, connectivity, size, boundary conditions, fluid dynamics, thermodynamics, chemical reactions, heat transfer rates, or combinations thereof.

4. The method of claim 1 , where said H 2 S generation mechanisms are biological reactions of sulfate reducing bacteria (SRB), natural scavenging reactions, thermal reactions, interaction between H 2 S and hydrocarbons, reactions between H 2 S and water injection, reactions between H 2 S and production equipment, and/or a combination thereof.

5. The method of claim 1 , wherein said reservoir characterization data includes initial conditions & composition, geometry, flow area, column, porosity, bulk density, permeability, imbibition and drainage relative permeabilities, skill friction, Sorw, capillary pressures, reactive substrates descriptions or a combination thereof.

6. The method of claim 1 , wherein at least one individual basic element is a hierarchical object incorporating elements from another individual basic element.

7. The method of claim 1 , wherein at least one individual basic element is a hierarchical object incorporating elements from another individual basic element and wherein said hierarchical object is a Reservoir Element.

8. The method of claim 1 , wherein said spatial levels are pore, core and field levels.

9. The method of claim 1 , wherein said fluid injections comprise seawater injections, freshwater injections, waste water injections, produced water re-injection, brine water injection, and mixtures thereof.

10. The method of claim 1 , further comprising inputting a second network topography and a second field layout for a second reservoir field configuration.

11. A non-transitory machine-readable storage medium, which when executed by at least one processor of a computer, perform the method of claim 1 .

12. A computer-implemented method of modeling souring within a reservoir, said computer having at least one parallel graphics processing unit (GPU), comprising:
a) dividing a reservoir topology into a finite number of grid cells that forms a grid of the reservoir;
b) defining interaction regions contained within adjacent grid cells in the grid;
c) inputting, onto said GPU, a description of a field layout for said reservoir topology, and historical data for said reservoir;
d) utilizing object-oriented software, on said GPU, for dividing the flow physics and H 2 S generation mechanisms for one or more fluids injections for each of said interaction regions into a plurality of individual basic elements of appropriate units for individual calculation so that the behavior of each individual basic element can be analyzed separately;
e) defining one or more time scales and/or one or more spatial scales;
f) performing, using the computer, H 2 S generation and transport forecast operations for said fluid injection for each interaction region for said time scales and said spatial scales using a plurality of said individual basic elements and said field layout and said historical data; and
g) outputting the model of souring.

13. The method of claim 12 , further comprising h) comparing simulation results for one or more field configurations; i) selecting the configuration with the lowest H 2 S generation; and j) creating and implementing a final field development plan to maximize hydrocarbon production from said reservoir.

14. The method of claim 12 , where said individual basic elements contain network parameters such as location, connectivity, size, boundary conditions, fluid dynamics, thermodynamics, chemical reactions, heat transfer rates, or combinations thereof.

15. The method of claim 12 , where said H 2 S generation mechanisms are biological reactions of sulfate reducing bacteria (SRB), natural scavenging reactions, thermal reactions, interaction between H 2 S and hydrocarbons, reactions between H 2 S and water injection, reactions between H 2 S and production equipment, and/or a combination thereof.

16. The method of claim 12 , wherein said reservoir characterization data includes initial conditions & composition, geometry, flow area, column, porosity, bulk density, permeability, imbibition and drainage relative permeabilities, skill friction, Sorw, capillary pressures, reactive substrates descriptions or a combination thereof.

17. The method of claim 12 , wherein at least one individual basic element is a hierarchical object incorporating elements from another individual basic element.

18. The method of claim 12 , wherein at least one individual basic element is a hierarchical object incorporating elements from another individual basic element and wherein said hierarchical object is a Reservoir Element.

19. The method of claim 12 , wherein said spatial levels are pore, core and field levels.

20. The method of claim 12 , wherein said fluid injections comprise seawater injections, freshwater injections, waste water injections, produced water re-injection, brine water injection, and mixtures thereof.

21. The method of claim 12 , further comprising inputting a second network topography and a second field layout for a second reservoir field configuration.

22. A non-transitory machine-readable storage medium, which when executed by at least one processor of a computer, performs one or more steps of the method of claim 12 .

23. A method for forecasting reservoir souring for a field development configuration, comprising:
a) providing a computer having at least one parallel graphics processing unit (GPU) and a graphical user interface (GUI) display;
b) inputting, on said GPU, the network topography, field layout, historical reservoir data and the fluid flow physics of a reservoir field configuration, wherein said fluid is freshwater, seawater and/or a combination thereof;
c) modeling said flow physics to form at least

Assignees

• Conocophillips Co

Inventors

• Jenneman Gary E
• Burger Edward
• Kolade Babajide

Classifications

• E21B43/20 Primary

  Displacing by water · CPC title

• E21B49/008

  by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor (measuring pressure E21B47/06) · CPC title

• G06F2111/10

  Numerical modelling · CPC title

• G01N33/241

  for hydrocarbon content · CPC title

• E21B43/24

  using heat, e.g. steam injection · CPC title