1,705
edits
Changes
Jump to navigation
Jump to search
Initial import
{{publication
| image = exploring-for-oil-and-gas-traps.png
| width = 120px
| series = Treatise in Petroleum Geology
| title = Exploring for Oil and Gas Traps
| part = Predicting the occurrence of oil and gas traps
| chapter = Predicting reservoir system quality and performance
| frompg = 9-1
| topg = 9-156
| author = Dan J. Hartmann, Edward A. Beaumont
| link = http://archives.datapages.com/data/specpubs/beaumont/ch09/ch09.htm
| pdf =
| store = http://store.aapg.org/detail.aspx?id=545
| isbn = 0-89181-602-X
}}
Absolute [[permeability]] (K<sub>a</sub>) is the property of a rock that characterizes the flow of fluid through its interconnected pores. It is a measure of the fluid conductivity of a rock. The permeability of a flow unit in a reservoir is not an absolute value but is a relative value that varies with water saturation (''see'' “Relative [[Permeability]] and Pore Type” following). Understanding the methodology for permeability measurements is important for understanding how to assess reservoir rock quality or to compare the quality of one flow unit to another.
==Horizontal and vertical k<sub>a</sub>==
Horizontal K<sub>a</sub> (i.e., parallel to bedding) is generally greater than vertical K<sub>a</sub> (i.e., normal to bedding) because of vertical changes in sorting and because of bedding laminations. High vertical K<sub>a</sub> generally results from fracturing or even burrowing that cuts across bedding. Most K<sub>a</sub> calculations are made from measurements of horizontal plugs.
==Steady-state permeability equation==
[[Permeability]] is not measured; it is calculated. The steady-state equation for calculating permeability (using an integrated form of Darcy's law) is
:<math>\mbox{K}_{\rm a} = \frac{2000 \mbox{ P}_{\rm atm}\mbox{QL}\mu}{\mbox{A}(\mbox{P}_{1} - \mbox{P}_{2})}</math>
where:
* K<sub>a</sub> = permeability to air, md
* P<sub>atm</sub> = atmospheric pressure, atm
* A = cross-sectional area of the plug face, cm<sup>2</sup>
* Q = flow, cm<sup>3</sup>/sec
* L = length, cm
* P<sub>1</sub> = pressure at input end, atm
* P<sub>2</sub> = pressure at output end, atm
* μ = air viscosity, cp
The following diagram of a plug illustrates some of these variables.
[[file:predicting-reservoir-system-quality-and-performance_fig9-24.png|thumb|{{figure number|9-24}}See text for explanation.]]
==Limitations of darcy's equation==
Why do two reservoirs with similar K<sub>a</sub> but different porosities yield different performances? The standard conversion of air flow through a rock to K<sub>a</sub> is accomplished using the Darcy relationship. Since the cross-sectional area (A) is of the plug face and not of the pores exposed on the surface of the plug, this equation cannot adjust for the ratio of number vs. size of pore throats exposed at the end of the plug.
==Example==
In the photos below, flow unit 1 is a sucrosic dolomite. On a face of a plug of flow unit 1, a very large number of very small pore throats (capillaries) occur, resulting in a measurable flow (Q). That Q, at a measured cross-sectional area A of the plug, yields a K<sub>a</sub> of approximately 20 md.
The sample from flow unit 2 with the same A has fewer, larger pore throats (capillaries) exposed in the face of the plug. If the Q for flow unit 2 is slightly lower than flow unit 1, then the K<sub>a</sub> will be lower (by using the same A).
Flow unit 1 has a [[porosity]] of 30%, and flow unit 2 has a porosity of 10%. The variance in porosity becomes the indicator of the contrast in pore throat size when converted to port size. For flow unit 1, the port size is approximately 1.1μ; for flow unit 2, port size is approximately 3μ.
[[file:predicting-reservoir-system-quality-and-performance_fig9-25.png|thumb|{{figure number|9-25}}See text for explanation.]]
==See also==
* [[Pore–fluid interaction]]
* [[Hydrocarbon expulsion, migration, and accumulation]]
* [[Characterizing rock quality]]
* [[Pc curves and saturation profiles]]
* [[Converting Pc curves to buoyancy, height, and pore throat radius]]
* [[Relative permeability and pore type]]
==External links==
{{search}}
* [http://archives.datapages.com/data/specpubs/beaumont/ch09/ch09.htm Original content in Datapages]
* [http://store.aapg.org/detail.aspx?id=545 Find the book in the AAPG Store]
[[Category:Predicting the occurrence of oil and gas traps]]
[[Category:Predicting reservoir system quality and performance]]
| image = exploring-for-oil-and-gas-traps.png
| width = 120px
| series = Treatise in Petroleum Geology
| title = Exploring for Oil and Gas Traps
| part = Predicting the occurrence of oil and gas traps
| chapter = Predicting reservoir system quality and performance
| frompg = 9-1
| topg = 9-156
| author = Dan J. Hartmann, Edward A. Beaumont
| link = http://archives.datapages.com/data/specpubs/beaumont/ch09/ch09.htm
| pdf =
| store = http://store.aapg.org/detail.aspx?id=545
| isbn = 0-89181-602-X
}}
Absolute [[permeability]] (K<sub>a</sub>) is the property of a rock that characterizes the flow of fluid through its interconnected pores. It is a measure of the fluid conductivity of a rock. The permeability of a flow unit in a reservoir is not an absolute value but is a relative value that varies with water saturation (''see'' “Relative [[Permeability]] and Pore Type” following). Understanding the methodology for permeability measurements is important for understanding how to assess reservoir rock quality or to compare the quality of one flow unit to another.
==Horizontal and vertical k<sub>a</sub>==
Horizontal K<sub>a</sub> (i.e., parallel to bedding) is generally greater than vertical K<sub>a</sub> (i.e., normal to bedding) because of vertical changes in sorting and because of bedding laminations. High vertical K<sub>a</sub> generally results from fracturing or even burrowing that cuts across bedding. Most K<sub>a</sub> calculations are made from measurements of horizontal plugs.
==Steady-state permeability equation==
[[Permeability]] is not measured; it is calculated. The steady-state equation for calculating permeability (using an integrated form of Darcy's law) is
:<math>\mbox{K}_{\rm a} = \frac{2000 \mbox{ P}_{\rm atm}\mbox{QL}\mu}{\mbox{A}(\mbox{P}_{1} - \mbox{P}_{2})}</math>
where:
* K<sub>a</sub> = permeability to air, md
* P<sub>atm</sub> = atmospheric pressure, atm
* A = cross-sectional area of the plug face, cm<sup>2</sup>
* Q = flow, cm<sup>3</sup>/sec
* L = length, cm
* P<sub>1</sub> = pressure at input end, atm
* P<sub>2</sub> = pressure at output end, atm
* μ = air viscosity, cp
The following diagram of a plug illustrates some of these variables.
[[file:predicting-reservoir-system-quality-and-performance_fig9-24.png|thumb|{{figure number|9-24}}See text for explanation.]]
==Limitations of darcy's equation==
Why do two reservoirs with similar K<sub>a</sub> but different porosities yield different performances? The standard conversion of air flow through a rock to K<sub>a</sub> is accomplished using the Darcy relationship. Since the cross-sectional area (A) is of the plug face and not of the pores exposed on the surface of the plug, this equation cannot adjust for the ratio of number vs. size of pore throats exposed at the end of the plug.
==Example==
In the photos below, flow unit 1 is a sucrosic dolomite. On a face of a plug of flow unit 1, a very large number of very small pore throats (capillaries) occur, resulting in a measurable flow (Q). That Q, at a measured cross-sectional area A of the plug, yields a K<sub>a</sub> of approximately 20 md.
The sample from flow unit 2 with the same A has fewer, larger pore throats (capillaries) exposed in the face of the plug. If the Q for flow unit 2 is slightly lower than flow unit 1, then the K<sub>a</sub> will be lower (by using the same A).
Flow unit 1 has a [[porosity]] of 30%, and flow unit 2 has a porosity of 10%. The variance in porosity becomes the indicator of the contrast in pore throat size when converted to port size. For flow unit 1, the port size is approximately 1.1μ; for flow unit 2, port size is approximately 3μ.
[[file:predicting-reservoir-system-quality-and-performance_fig9-25.png|thumb|{{figure number|9-25}}See text for explanation.]]
==See also==
* [[Pore–fluid interaction]]
* [[Hydrocarbon expulsion, migration, and accumulation]]
* [[Characterizing rock quality]]
* [[Pc curves and saturation profiles]]
* [[Converting Pc curves to buoyancy, height, and pore throat radius]]
* [[Relative permeability and pore type]]
==External links==
{{search}}
* [http://archives.datapages.com/data/specpubs/beaumont/ch09/ch09.htm Original content in Datapages]
* [http://store.aapg.org/detail.aspx?id=545 Find the book in the AAPG Store]
[[Category:Predicting the occurrence of oil and gas traps]]
[[Category:Predicting reservoir system quality and performance]]