Performance prediction method for hydrocarbon recovery processes

• US 20060224369A1
• Filed: 03/16/2004
• Published: 10/05/2006
• Est. Priority Date: 03/26/2003
• Status: Active Grant

• Current Assignee: Exxonmobil Upstream Research Company (Exxon Mobil Corporation)
• Original Assignee: Exxonmobil Upstream Research Company (Exxon Mobil Corporation)
• Inventors: Yang, Shan H, Arbabi, Sepehr, Miertschin, John W., Kudva, Ryan A.
• Granted Patent: US 7,289,942 B2
• Time in Patent Office: Days
• US Class Current: 703/10
• CPC Class Codes: E21B 43/16 Enhanced recovery methods for obtaining hydrocarbons
• CPC Class Codes: E21B 43/20 Displacing by water
• CPC Class Codes: E21B 47/11 using tracers; using radioactivity
• 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
• CPC Class Codes: Y02A 10/40 Controlling or monitoring, e.g. of flood or hurricane; Forecasting, e.g. risk assessment or mapping

Abstract

The invention relates to a method for predicting the performance of large-scale hydrocarbon-bearing reservoir floods. One embodiment of the invention includes a method for predicting performance of a patterned flooding process in a subterranean hydrocarbon-bearing formation, said formation being penetrated by a plurality of injector wells and producer wells, comprising the steps of: determining flow-based pairs of injector to producer wells [FIG. 4, item 78a] (first well pairs) using a geological model [item 76]; developing a connective pore volume distribution curve for each first well pair item [78b]; selecting at least two first well pairs (selected well pairs) that reflect narrow and wide connective pore volume distributions that correspond to high and lower oil recovery levels; developing a 3-D simulation model for each selected well pair, performing a reservoir simulation for each selected well pair for the corresponding flooding process; and generating prototype performance curves for each selected well pair. An alternate embodiment of the invention includes a method for predicting the performance of large-scale hydrocarbon-bearing reservoir floods where injection well location, production well location, a process parameter, or a well processing rate is modified.

Claims

1. A method for predicting performance of a patterned flooding process in a subterranean hydrocarbon-bearing formation, said formation being penetrated by a plurality of injector wells and producer wells, comprising the steps of:

determining flow-based pairs of injector to producer wells (first well pairs) using a geological model;

developing a connective pore volume distribution curve for each first well pair;

selecting at least two first well pairs (selected well pairs) that reflect narrow and wide connective pore volume distributions that correspond to higher and lower oil recovery levels;

developing a 3-D simulation model for each selected well pair;

performing a reservoir simulation for each selected well pair for the corresponding flooding process; and

generating prototype performance curves for each selected well pair.

2. The method of claim 1, wherein said selecting well pairs includes selecting at least three well pairs that reflect narrow, wide and channel connective pore volume distributions that correspond to high, medium, and low oil recovery levels.

3. The method of claim 2, wherein said corresponding flooding process is selected from waterflooding, enhanced oil recovery flooding, and combinations thereof.

4. The method of claim 3, wherein said enhanced oil recovery flooding process is selected from polymer flooding, surfactant flooding, steam flooding, emulsion flooding, and combinations thereof.

5. The method of claim 3, wherein said performing a reservoir simulation includes inputting process parameters selected from injection rate, production rate, WAG ratio, solvent bank size and combinations thereof.

6. The method of claim 2, wherein said 3-D simulation model is a 3-D, multi-phase, element model.

7. The method of claim 2, wherein said geological model is a 3-D full-field geological model.

8. The method of claim 2, wherein said prototype performance curves are selected from oil production curves, injectant production curves and lean gas production curves.

9. The method of claim 2 further comprising the step of expressing the prototype performance curves as dimensionless type-curve correlation equations having correlation parameters.

10. The method of claim 9, wherein said type-curve correlation equations are expressed as oil production versus cumulative injection, lean gas production versus cumulative injection, injectant production versus cumulative injection or combinations thereof.

11. The method of claim 9, further comprising determining a set of type-curve correlation equation multipliers, said type-curve multipliers functioning to adjust said type-curve correlation equations for variations in process parameters.

12. The method of claim 11, wherein at least one of said process parameters is selected from injection rate, VGR, WAG ratio, injectant bank size and combinations thereof.

13. The method of claim 1, wherein said injector wells are hypothetical injector wells, said hypothetical injector wells representing natural drive forces.

14. The method of claim 13, wherein said hypothetical injector wells represent natural water drive or natural gas drive.

15. The method of claim 11 further comprising the steps of:

providing a single-phase, 2-D model of at least a portion of the subterranean formation;

initializing said single-phase, 2-D model for initial pressure and initial oil saturation at the start of the patterned flooding process;

determining flow-based pairs of injector to producer wells (second well pairs) using said single-phase, 2-D model of at least a portion of the hydrocarbon-bearing formation;

determining for each second well pair a second processing rate and a second pore volume;

assigning to each second well pair one set of said type-curve correlation equations, said correlation parameters, and said type-curve multipliers;

calculating cumulative injection for each second well pair using said second processing rate and said second pore volume; and

calculating cumulative fluid production for each said second well pair from said second well pair'"'"'s assigned said type-curve correlation equations, said correlation parameters, and said type-curve multipliers.

16. The method of claim 15, wherein said determining flow-based well pairs includes using a single-phase flow calculation to generate streamlines and determine flow boundaries.

17. The method of claim 15, wherein said assigning to each said second well pair one set of said type-curve correlation equations, said correlation parameters, and said type-curve multipliers includes a method selected from history matching and connected pore volume distribution analysis.

18. The method of claim 15, wherein said calculating cumulative fluid production includes calculating oil production, lean gas production, injectant production, or combinations thereof.

19. The method of claim 17, further including calculating the total production from a first production well by summing cumulative fluid production for each said second well pair connected to said first production well and comparing said calculated total production from said first production well with actual field data for said first production well and matching said calculated total production from said first production well to said actual field data using a semi-automated history match method.

20. The method of claim 15, wherein at least one of injection well location, production well location, a process parameter, or a well processing rate is modified, the method further comprising the steps of:

estimating a second oil saturation in the single phase, 2-D model grid cells based on a tracer simulation representative of the formation before said modification;

making said modification;

re-determining flow-based pairs of injector to producer wells (third well pairs) using the single phase, 2-D model of at least a portion of the hydrocarbon-bearing formation and re-calculating for each third well pair a third processing rate and third pore volume;

re-assigning one set of said type-curve correlation equations, said correlation parameters and said type-curve multipliers to each said third well pairs;

calculating a new starting point on said type-curve correlation equations using said initial oil saturation and said second oil saturation; and

using said third processing rate, said third pore volume, said type-curve correlation equations, said correlation parameters, and said type-curve multipliers to predict fluid production for each said third well pair for predetermined time intervals.

21. The method of claim 20, wherein said tracer simulation includes:

initializing a tracer at the start of the patterned flooding process;

determining a tracer concentration gradient in said single phase, 2-D model grid cells;

determining tracer production for each said second well pair before said modification;

determining oil production for each said second well pair before said modification;

determining the ratio of said oil production to said tracer production for each said second well pair before said modification; and

determining said oil saturation before said modification in said single phase, 2-D model grid cells by multiplying said ratio by said tracer concentration gradient in said single phase, 2-D model grid cells for each of said second well pairs.

22. The method of claim 20, wherein said calculating a new starting point on said type-curve correlation equations includes:

calculating hypothetical oil production for each said third well pair;

extrapolating cumulative injection based on said assigned type-curve correlation equations, said correlation parameters, and said type-curve multipliers; and

using said cumulative injection as said starting point on said type-curve correlation equations.

23. A method for predicting performance of a patterned flooding process in a subterranean hydrocarbon-bearing formation, said formation being penetrated by a plurality of injector wells and producer wells, comprising the steps of:

generating type-curve correlation equations for two or more well types;

providing a single-phase, 2-D model of at least a portion of the subterranean formation;

initializing said single-phase, 2-D model for initial pressure and initial oil saturation at the start of the patterned flooding process;

determining flow-based pairs of injector to producer wells (second well pairs) using said single-phase, 2-D model of at least a portion of the hydrocarbon-bearing formation;

determining for each second well pair a second processing rate and second pore volume;

assigning to each second well pair one set of said type-curve correlation equations;

calculating second cumulative injection for each second well pair using said second well pair'"'"'s second processing rate and second pore volume;

calculating second cumulative fluid production for each said second well pair from said second well pair'"'"'s assigned type-curve correlation equations;

estimating a second oil saturation in the single phase, 2-D model grid cells based on a tracer simulation representative of the formation before a modification;

modifying injection well location, production well location, a process parameter, or a well processing rate;

re-determining flow-based pairs of injector to producer wells (third well pairs) using said single phase, 2-D model of at least a portion of the hydrocarbon-bearing formation and re-calculating for each said third well pair a third processing rate and third pore volume;

calculating a new starting point on said type-curve correlation equations using said initial oil saturation and said second oil saturation; and

using said third processing rate, said third pore volume, and said type-curve correlation equations to predict fluid production for each said third well pair for predetermined time intervals.

24. The method of claim 23, wherein said generating type-curve correlation equations includes generating at least three sets of type-curve correlation equations for three well types that reflect narrow, wide and channel connective pore volume distributions that correspond to high, medium, and low oil recovery levels.

25. The method of claim 24, wherein said type-curve correlation equations are dimensionless and include type-curve correlation parameters.

26. The method of claim 25, wherein said type-curve correlation equations are expressed as oil production versus cumulative injection, lean gas production versus cumulative injection, injectant production versus cumulative injection or combinations thereof.

27. The method of claim 25, further comprising determining a set of type-curve correlation equation multipliers, said type-curve multipliers functioning to adjust said type-curve correlation equations for variations in process parameters.

28. The method of claim 27, wherein at least one of said process parameters is selected from injection rate, VGR, WAG ratio, injectant bank size and combinations thereof.

29. The method of claim 27, wherein said determining flow-based well pairs includes using a single-phase flow calculation to generate streamlines and determine flow boundaries.

30. The method of claim 27, wherein said calculating second cumulative fluid production includes calculating oil production, lean gas production, injectant production, or combinations thereof.

31. The method of claim 27, wherein said tracer simulation includes:

initializing a tracer at the start of the patterned flooding process;

determining a tracer concentration gradient in said single phase, 2-D model grid cells;

determining tracer production for each said second well pair before said modification;

determining oil production for each said second well pair before said modification;

determining the ratio of said oil production to said tracer production for each said second well pair before said modification; and

determining said oil saturation before said modification in said single phase, 2-D model grid cells by multiplying said ratio by said tracer concentration gradient in said single phase, 2-D model grid cells for each of said second well pairs.

32. The method of claim 25, wherein said calculating a new starting point on said type-curve correlation equations includes:

calculating hypothetical oil production for each said third well pair;

extrapolating cumulative injection based on said assigned type-curve correlation equations, said correlation parameters, and said type-curve multipliers; and

using said cumulative injection as said starting point on said type-curve correlation equations.