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  | part    = Predicting the occurrence of oil and gas traps
 
  | part    = Predicting the occurrence of oil and gas traps
 
  | chapter = Predicting reservoir system quality and performance
 
  | chapter = Predicting reservoir system quality and performance
  | frompg  = 9-1
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  | frompg  = 9-29
  | topg    = 9-156
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  | topg    = 9-33
 
  | author  = Dan J. Hartmann, Edward A. Beaumont
 
  | author  = Dan J. Hartmann, Edward A. Beaumont
 
  | link    = http://archives.datapages.com/data/specpubs/beaumont/ch09/ch09.htm
 
  | link    = http://archives.datapages.com/data/specpubs/beaumont/ch09/ch09.htm
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[[file:predicting-reservoir-system-quality-and-performance_fig9-16.png|300px|thumb|{{figure number|1}}SEM microphotographs.]]
 
[[file:predicting-reservoir-system-quality-and-performance_fig9-16.png|300px|thumb|{{figure number|1}}SEM microphotographs.]]
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Using K<sub>a</sub> and Φ data separately to characterize reservoir rock quality is misleading. Consider the rocks shown in the SEM microphotographs in [[:file:predicting-reservoir-system-quality-and-performance_fig9-16.png|Figure 1]]. Flow unit 1 is a mesoporous, sucrosic dolomite. Its average Φ is 30% and average K<sub>a</sub> is 10 md. Flow unit 2 is a macroporous, oolitic limestone. Its average Φ is 10% and average K<sub>a</sub> is 10 md.
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Using K<sub>a</sub> and Φ data separately to characterize reservoir rock quality is misleading. Consider the rocks shown in the SEM microphotographs in [[:file:predicting-reservoir-system-quality-and-performance_fig9-16.png|Figure 1]]. Flow unit 1 is a [[Wikipedia:Mesoporous material|mesoporous]], sucrosic [[dolomite]]. Its average Φ is 30% and average K<sub>a</sub> is 10 md. Flow unit 2 is a macroporous, oolitic [[limestone]]. Its average Φ is 10% and average K<sub>a</sub> is 10 md.
    
Initially, we might think that flow unit 1 is higher quality because it has three times more porosity and the same permeability as flow unit 2. However, in terms of fluid flow efficiency and storage, as shown by the K<sub>a</sub>/Φ ratio or r<sub>35</sub>, flow unit 2 is actually the better rock.
 
Initially, we might think that flow unit 1 is higher quality because it has three times more porosity and the same permeability as flow unit 2. However, in terms of fluid flow efficiency and storage, as shown by the K<sub>a</sub>/Φ ratio or r<sub>35</sub>, flow unit 2 is actually the better rock.
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==K<sub>a</sub>/Φ plot==
 
==K<sub>a</sub>/Φ plot==
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[[file:Oiloil-and-oilsource-rock-correlations fig9-17.png|300px|thumb|{{figure number|2}}Contour plot.]]
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[[file:Oiloil-and-oilsource-rock-correlations fig8-17.png|300px|thumb|{{figure number|2}}Contour plot.]]
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On the plot in [[:file:Oiloil-and-oilsource-rock-correlations fig8-17.png|Figure 2]], the contours represent a constant K<sub>a</sub>/Φ ratio and divide the plot into areas of similar pore types. Data points that plot along a constant ratio have similar flow quality across a large range of porosity and/or permeability. The clusters of points on the plot  in [[:file:Oiloil-and-oilsource-rock-correlations fig9-17.png|Figure 2]] represent hypothetical K<sub>a</sub>/Φ values for flow units 1 and 2 presented in [[:file:predicting-reservoir-system-quality-and-performance_fig9-16.png|Figure 1]]. The position of the clusters relative to the K<sub>a</sub>/Φ contours indicates flow unit 2 has higher quality in terms of K<sub>a</sub>/Φ ratio than flow unit 1.
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On the plot in [[:file:Oiloil-and-oilsource-rock-correlations fig8-17.png|Figure 2]], the contours represent a constant K<sub>a</sub>/Φ ratio and divide the plot into areas of similar pore types. Data points that plot along a constant ratio have similar flow quality across a large range of porosity and/or permeability. The clusters of points on the plot  in [[:file:Oiloil-and-oilsource-rock-correlations fig8-17.png|Figure 2]] represent hypothetical K<sub>a</sub>/Φ values for flow units 1 and 2 presented in [[:file:predicting-reservoir-system-quality-and-performance_fig9-16.png|Figure 1]]. The position of the clusters relative to the K<sub>a</sub>/Φ contours indicates flow unit 2 has higher quality in terms of K<sub>a</sub>/Φ ratio than flow unit 1.
    
==What is r<sub>35</sub>?==
 
==What is r<sub>35</sub>?==
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Pittman<ref name=ch09r46 /> speculates, “Perhaps Winland found the best correlation to be r<sub>35</sub> because that is where the average modal pore aperture occurs and where the pore network is developed to the point of serving as an effective pore system that dominates flow.” The capillary pressure curve and pore throat size histogram in [[:file:predicting-reservoir-system-quality-and-performance_fig9-18.png|Figure 3]] illustrate Pittman's point.
 
Pittman<ref name=ch09r46 /> speculates, “Perhaps Winland found the best correlation to be r<sub>35</sub> because that is where the average modal pore aperture occurs and where the pore network is developed to the point of serving as an effective pore system that dominates flow.” The capillary pressure curve and pore throat size histogram in [[:file:predicting-reservoir-system-quality-and-performance_fig9-18.png|Figure 3]] illustrate Pittman's point.
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==The winland r<sub>35</sub> equation==
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==The Winland r<sub>35</sub> equation==
 
Winland<ref name=ch09r70>Winland, H., D., 1972, Oil accumulation in response to pore size changes, Weyburn field, Saskatchewan: Amoco Production Company Report F72-G-25, 20 p. (unpublished).</ref><ref name=ch09r71>Winland, H., D., 1976, Evaluation of gas slippage and pore aperture size in carbonate and sandstone reservoirs: Amoco Production Company Report F76-G-5, 25 p. (unpublished).</ref> developed the following equation to calculate r<sub>35</sub> for samples with intergranular or intercrystalline porosity:
 
Winland<ref name=ch09r70>Winland, H., D., 1972, Oil accumulation in response to pore size changes, Weyburn field, Saskatchewan: Amoco Production Company Report F72-G-25, 20 p. (unpublished).</ref><ref name=ch09r71>Winland, H., D., 1976, Evaluation of gas slippage and pore aperture size in carbonate and sandstone reservoirs: Amoco Production Company Report F76-G-5, 25 p. (unpublished).</ref> developed the following equation to calculate r<sub>35</sub> for samples with intergranular or intercrystalline porosity:
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[[Category:Predicting the occurrence of oil and gas traps]]  
 
[[Category:Predicting the occurrence of oil and gas traps]]  
 
[[Category:Predicting reservoir system quality and performance]]
 
[[Category:Predicting reservoir system quality and performance]]
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[[Category:Treatise Handbook 3]]

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