Difference between revisions of "Predicting reservoir drive mechanism"

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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
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  | frompg  = 9-1
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  | frompg  = 9-14
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  | topg    = 9-156
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  | topg    = 9-16
 
  | 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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==Predicting drive type==
 
==Predicting drive type==
−
Reservoir analysis includes making cross sections, structural maps, and isopach maps. Analyzing nearby producing fields yields the best set of inferential data. This includes (1) making plots of historical oil, gas, condensate, and water production and pressure decline and (2) making cumulative production maps. When all available information has been assembled, find the drive type that best fits the prospective reservoir system. The table below summarizes typical characteristics of primary drive types.
+
Reservoir analysis includes making [[cross section]]s, structural maps, and isopach maps. Analyzing nearby producing fields yields the best set of inferential data. This includes (1) making plots of historical oil, gas, condensate, and water production and pressure decline and (2) making cumulative production maps. When all available information has been assembled, find the drive type that best fits the prospective reservoir system. The table below summarizes typical characteristics of primary drive types.
  
 
{| class = "wikitable"
 
{| class = "wikitable"
Line 25: Line 25:
 
|-
 
|-
 
| Water
 
| Water
−
| *  Quality of aquifer pore geometry comparable to reservoir pore geometry *  Aquifer volume at least 10 times greater than reservoir volume *  Flat to gradual production and pressure declines *  Gradually to rapidly increasing water production late in life of reservoir *  Early increasing water production from downdip wells *  GOR (gas–oil ratio) relatively constant *  High recovery factor (50% or more)
+
|
−
 
+
*  Quality of aquifer pore geometry comparable to reservoir pore geometry  
 +
*  Aquifer volume at least 10 times greater than reservoir volume  
 +
*  Flat to gradual production and pressure declines  
 +
*  Gradually to rapidly increasing water production late in life of reservoir  
 +
*  Early increasing water production from downdip wells  
 +
*  GOR (gas–oil ratio) relatively constant  
 +
*  High recovery factor (50% or more)
 
|-
 
|-
 
| Gas expansion
 
| Gas expansion
−
| *  Moderate drop in reservoir pressure *  Moderate production decline *  Water-free production (or relatively minor) *  GOR flat for first 50% of production, then increases *  GOR increases rapidly in structurally high wells *  Moderate recovery factor (typically 30%)
+
|
−
 
+
*  Moderate drop in reservoir pressure  
 +
*  Moderate production decline  
 +
*  Water-free production (or relatively minor)  
 +
*  GOR flat for first 50% of production, then increases  
 +
*  GOR increases rapidly in structurally high wells  
 +
*  Moderate recovery factor (typically 30%)
 
|-
 
|-
 
| Solution gas
 
| Solution gas
−
| *  Rapid drop in reservoir pressure early in production history *  Exponential production decline *  Water-free production (or relatively minor) *  Increasing GOR early, decreasing later as gas is exhausted *  Low recovery factor (20% or less)
+
|
−
 
+
*  Rapid drop in reservoir pressure early in production history  
 +
*  Exponential production decline  
 +
*  Water-free production (or relatively minor)  
 +
*  Increasing GOR early, decreasing later as gas is exhausted  
 +
*  Low recovery factor (20% or less)
 
|-
 
|-
 
| Rock drive
 
| Rock drive
−
| *  Unconsolidated reservoir such as sandstone, chalk, or diatomite *  Reservoir in overpressure section *  No decline while reservoir compacts, then rapid production decline
+
|  
−
 
+
*  Unconsolidated reservoir such as sandstone, chalk, or diatomite  
 +
*  Reservoir in overpressure section  
 +
*  No decline while reservoir compacts, then rapid production decline
 
|-
 
|-
−
| Gravity
+
| [[Gravity]]
−
| *  Steeply dipping beds or vertical [[permeability]] greater than horizontal *  Fractured reservoir *  Low-viscosity oil (in general) *  Rapid production decline *  High recovery rate (75% or more), but often with low recovery volume
+
|  
−
 
+
*  Steeply dipping beds or vertical [[permeability]] greater than horizontal  
 +
*  Fractured reservoir  
 +
*  Low-[[viscosity]] oil (in general)  
 +
*  Rapid production decline  
 +
*  High recovery rate (75% or more), but often with low recovery volume
 
|}
 
|}
  
 
==Production history characteristics for drives==
 
==Production history characteristics for drives==
−
The graphs below show oil reservoir production history characteristics for water, gas expansion, and gas solution drives. To predict reservoir drive type, if possible, plot the production history of nearby fields with analogous reservoir systems and compare with these graphs.
 
  
−
[[file:predicting-reservoir-system-quality-and-performance_fig9-8.png|thumb|{{figure number|9-8}}Modified. Copyright: Levorsen, 1954; courtesy W.H. Freeman and Co.]]
+
[[file:predicting-reservoir-system-quality-and-performance_fig9-8.png|thumb|300px|{{figure number|1}}Oil reservoir production history characteristics for water, gas expansion, and gas solution drives. Modified. Copyright: Levorsen;<ref name=Levorsen_1954>Levorsen, A. I., 1954, Geology of Petroleum: San Francisco, W. H. Freeman, 703 p.</ref> courtesy W.H. Freeman and Co.]]
 +
 
 +
[[:file:predicting-reservoir-system-quality-and-performance_fig9-8.png|Figure 1]] shows oil reservoir production history characteristics for water, gas expansion, and gas solution drives. To predict reservoir drive type, if possible, plot the production history of nearby fields with analogous reservoir systems and compare with these graphs.
  
 
==Recoveries of oil vs. gas reservoirs==
 
==Recoveries of oil vs. gas reservoirs==
−
The table below shows typical recovery rates for oil vs. gas reservoir systems for different reservoir drive mechanisms with mega and macro port type systems (John Farina, personal communication, 1998; .<ref name=ch09r21>Garb, F., A., Smith, G., L., 1987, Estimation of oil and gas reserves, in Bradley, H., B., ed., Petroleum Engineering Handbook: SPE, p. 40-1–40-32.</ref> Recoveries would be lower for meso to micro port systems. Use this table to project the recoveries for your prospects.
+
The table below shows typical recovery rates for oil vs. gas reservoir systems for different reservoir drive mechanisms with mega and macro port type systems.<ref>Farina, J. personal communication, 1998</ref><ref name=ch09r21>Garb, F. A., and G. L. Smith, 1987, Estimation of oil and gas reserves, in H. B. Bradley, ed., Petroleum Engineering Handbook: SPE, p. 40-1–40-32.</ref> Recoveries would be lower for meso to micro port systems. Use this table to project the recoveries for your prospects.
  
 
{| class = "wikitable"
 
{| class = "wikitable"
 
|-
 
|-
−
! Reservoir drive mechanism
+
! rowspan=2 | Reservoir drive mechanism || colspan=2 | Percent ultimate recovery
−
! Percent ultimate recovery
+
|-
−
! Gas
+
! Gas || Oil
−
! Oil
 
 
|-
 
|-
−
| Strong water
+
| Strong water || 30–40 || 45–60
−
| 30–40
 
−
| 45–60
 
 
|-
 
|-
−
| Partial water
+
| Partial water || 40–50 || 30–45
−
| 40–50
 
−
| 30–45
 
 
|-
 
|-
−
| Gas expansion
+
| Gas expansion || 50–70 || 20–30
−
| 50–70
 
−
| 20–30
 
 
|-
 
|-
−
| Solution gas
+
| Solution gas || N/A || 15–25
−
| N/A
 
−
| 15–25
 
 
|-
 
|-
−
| Rock
+
| Rock || 60–80 || 10–60
−
| 60–80
 
−
| 10–60
 
 
|-
 
|-
−
| Gravity drainage
+
| [[Gravity]] drainage || N/A || 50–70
−
| N/A
 
−
| 50–70
 
 
|}
 
|}
  
 
==Recoveries for sandstone vs. carbonate reservoirs==
 
==Recoveries for sandstone vs. carbonate reservoirs==
−
The American Petroleum Institute conducted a study to determine recovery amounts and efficiencies for water vs. solution gas drives for sandstone and carbonate reservoirs, summarized in the table below (Arps, 1967). Use the table to project recoveries for your prospects.
+
The American Petroleum Institute conducted a study to determine recovery amounts and efficiencies for water vs. solution gas drives for sandstone and carbonate reservoirs, summarized in the table below.<ref name=Arps=1964>Arps, J. J., 1964, [http://archives.datapages.com/data/bulletns/1961-64/data/pg/0048/0002/0150/0157.htm Engineering concepts useful in oil finding]: AAPG Bulletin, v. 48, no. 2, p. 943-961.</ref> Use the table to project recoveries for your prospects.
  
−
{| class = "wikitable"
+
{| class = "wikitable sortable"
 +
|-
 +
! rowspan=2 | Drive
 +
! rowspan=2 | Units
 +
! colspan=3 | Sandstone
 +
! colspan=3 | Carbonate
 
|-
 
|-
−
! Drive
 
−
! Units
 
−
! Sandstone
 
−
! Carbonate
 
 
! Min.
 
! Min.
 
! Ave.
 
! Ave.
Line 101: Line 111:
 
! Max.
 
! Max.
 
|-
 
|-
−
| Water
+
| rowspan=3 | Water
 
| bbl/acre-ft
 
| bbl/acre-ft
 
| 155
 
| 155
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| 1,422
 
| 1,422
 
|-
 
|-
−
| m<sup>3</sup> /h-m
+
| m<sup>3</sup>/h-m
 
| 199
 
| 199
 
| 735
 
| 735
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| 1,831
 
| 1,831
 
|-
 
|-
−
| % <xref ref-type="table-fn" rid="ch09tblfn1"> * </xref>
+
| % STOOIP
 
| 28
 
| 28
 
| 51
 
| 51
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| 80
 
| 80
 
|-
 
|-
−
| Solution gas
+
| rowspan=3 | Solution gas
 
| bbl/acre-ft
 
| bbl/acre-ft
 
| 47
 
| 47
Line 135: Line 145:
 
| 187
 
| 187
 
|-
 
|-
−
| m<sup>3</sup> /h-m
+
| m<sup>3</sup>/h-m
 
| 60
 
| 60
 
| 198
 
| 198
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| 241
 
| 241
 
|-
 
|-
−
| % <xref ref-type="table-fn" rid="ch09tblfn1"> * </xref>
+
| % STOOIP
 
| 9
 
| 9
 
| 21
 
| 21
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==See also==
 
==See also==
−
* [[Reservoir system basics]]
+
* [[Reservoir system]]
−
* [[What is a reservoir system?]]
 
 
* [[Analyzing a reservoir system]]
 
* [[Analyzing a reservoir system]]
 
* [[Defining flow units and containers]]
 
* [[Defining flow units and containers]]
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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:Pages with bad references]]
 
[[Category:Predicting reservoir system quality and performance]] [[Category:Pages with bad references]]
 +
[[Category:Treatise Handbook 3]]

Latest revision as of 13:51, 4 April 2022

Exploring for Oil and Gas Traps
Series Treatise in Petroleum Geology
Part Predicting the occurrence of oil and gas traps
Chapter Predicting reservoir system quality and performance
Author Dan J. Hartmann, Edward A. Beaumont
Link Web page
Store AAPG Store

One can predict drive type by analyzing (1) the reservoir system of a prospect and (2) the production history characteristics of similar nearby reservoirs.

Predicting drive type[edit]

Reservoir analysis includes making cross sections, structural maps, and isopach maps. Analyzing nearby producing fields yields the best set of inferential data. This includes (1) making plots of historical oil, gas, condensate, and water production and pressure decline and (2) making cumulative production maps. When all available information has been assembled, find the drive type that best fits the prospective reservoir system. The table below summarizes typical characteristics of primary drive types.

Drive Characteristics
Water
  • Quality of aquifer pore geometry comparable to reservoir pore geometry
  • Aquifer volume at least 10 times greater than reservoir volume
  • Flat to gradual production and pressure declines
  • Gradually to rapidly increasing water production late in life of reservoir
  • Early increasing water production from downdip wells
  • GOR (gas–oil ratio) relatively constant
  • High recovery factor (50% or more)
Gas expansion
  • Moderate drop in reservoir pressure
  • Moderate production decline
  • Water-free production (or relatively minor)
  • GOR flat for first 50% of production, then increases
  • GOR increases rapidly in structurally high wells
  • Moderate recovery factor (typically 30%)
Solution gas
  • Rapid drop in reservoir pressure early in production history
  • Exponential production decline
  • Water-free production (or relatively minor)
  • Increasing GOR early, decreasing later as gas is exhausted
  • Low recovery factor (20% or less)
Rock drive
  • Unconsolidated reservoir such as sandstone, chalk, or diatomite
  • Reservoir in overpressure section
  • No decline while reservoir compacts, then rapid production decline
Gravity
  • Steeply dipping beds or vertical permeability greater than horizontal
  • Fractured reservoir
  • Low-viscosity oil (in general)
  • Rapid production decline
  • High recovery rate (75% or more), but often with low recovery volume

Production history characteristics for drives[edit]

Figure 1 Oil reservoir production history characteristics for water, gas expansion, and gas solution drives. Modified. Copyright: Levorsen;[1] courtesy W.H. Freeman and Co.

Figure 1 shows oil reservoir production history characteristics for water, gas expansion, and gas solution drives. To predict reservoir drive type, if possible, plot the production history of nearby fields with analogous reservoir systems and compare with these graphs.

Recoveries of oil vs. gas reservoirs[edit]

The table below shows typical recovery rates for oil vs. gas reservoir systems for different reservoir drive mechanisms with mega and macro port type systems.[2][3] Recoveries would be lower for meso to micro port systems. Use this table to project the recoveries for your prospects.

Reservoir drive mechanism Percent ultimate recovery
Gas Oil
Strong water 30–40 45–60
Partial water 40–50 30–45
Gas expansion 50–70 20–30
Solution gas N/A 15–25
Rock 60–80 10–60
Gravity drainage N/A 50–70

Recoveries for sandstone vs. carbonate reservoirs[edit]

The American Petroleum Institute conducted a study to determine recovery amounts and efficiencies for water vs. solution gas drives for sandstone and carbonate reservoirs, summarized in the table below.[4] Use the table to project recoveries for your prospects.

Drive Units Sandstone Carbonate
Min. Ave. Max. Min. Ave. Max.
Water bbl/acre-ft 155 571 1,641 6 172 1,422
m3/h-m 199 735 2,113 8 221 1,831
% STOOIP 28 51 87 6 44 80
Solution gas bbl/acre-ft 47 154 534 20 88 187
m3/h-m 60 198 688 26 113 241
% STOOIP 9 21 46 15 18 21

See also[edit]

References[edit]

  1. ↑ Levorsen, A. I., 1954, Geology of Petroleum: San Francisco, W. H. Freeman, 703 p.
  2. ↑ Farina, J. personal communication, 1998
  3. ↑ Garb, F. A., and G. L. Smith, 1987, Estimation of oil and gas reserves, in H. B. Bradley, ed., Petroleum Engineering Handbook: SPE, p. 40-1–40-32.
  4. ↑ Arps, J. J., 1964, Engineering concepts useful in oil finding: AAPG Bulletin, v. 48, no. 2, p. 943-961.

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