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{{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
}}
==Weyburn trap model==
A working trap model for Weyburn field is that of a macroporous vuggy packstone reservoir lying downdip from a microporous intercrystalline mudstone seal. How much hydrocarbon column could a trap like this retain, especially since superficially the seal doesn't appear to be a seal at all. Instead, it consists of rocks with appreciable [[porosity]], local oil staining, local log-calculated water saturations less than 100%, and the capability of producing significant amounts of water on DST.
==Total oil column height==
Weyburn and nearby Steelman fields appear to produce from a single, pressure-communicated oil column.<ref name=ch09r24>Hannon, N., 1987, Subsurface water flow patterns in the Canadian sector of the Williston Basin: RMAG 1987 Symposium Guidebook, p. 313–321.</ref> If so, then the total height of this combined column is about [[length::600 ft]] [[depth::(180 m]]). Could rocks of the porous mudstone facies act as a lateral seal for this much oil column? To calculate oil column height, we use the following equation:
:<math>\mbox{h} = \frac{0.670 \times \gamma \cos \theta}{\mbox{R}_{\rm bt}(\rho_{\rm w} - \rho_{\rm h})}</math>
where:
* γ = interfacial tension (dynes/cm)
* θ = contact angle
* R<sub>bt</sub> = breakthrough pore throat size (μ)
* ρ<sub>w</sub> = formation water density (g/cc)
* ρ<sub>h</sub> = hydrocarbon density (g/cc)
==Calculating oil column height at weyburn==
We can calculate the potential oil column height that could be sealed by the porous mud-stone facies using maximum reasonable estimates for the above parameters. Weyburn field oil densities grade from 35°API in the updip portion of the field to 27°API near the base. A representative gravity of 30°API is used for the column as a whole. The formation water is brackish NaCl brine (35,000 ppm).
Other parameters:
* Reservoir temp. = [[temperature::150°F]] ([[temperature::66°C]]) (possibly a low estimate)
* GOR = 100 CFG/BO (18 m<sup>3</sup> gas/m<sup>3</sup> oil) (probably low estimate)
* Reservoir press. = [[pressure::3,000 psi]] (20.7 × 10<sup>3</sup> kPa)
* γ = 35 dynes/cm at STP
* θ = 0° (seal is assumed to be very strongly water wet)
Estimates of in situ values:
* ρ<sub>w</sub> = 1.01 g/cc (from <ref name=ch09r54>Schowalter, T., T., 1979, Mechanics of secondary hydrocarbon [[migration]] and entrapment: AAPG Bulletin, vol. 63, no. 5, p. 723–760.</ref> his Figure 2)
* ρ<sub>h</sub> = 0.85 g/cc (from <ref name=ch09r54 /> his Figure 3)
Therefore:
* (ρ<sub>w</sub> – ρ<sub>h</sub>) = 0.16 (0.12 from approximations in preceding section)
* γ = 27 dynes/cm (from <ref name=ch09r54 /> his Figure 11)
* cos θ = 1 (very strongly water wet)
Therefore:
* γ cos θ = 27 dynes/cm (26 dynes/cm from approximations in preceding section)
Substituting these values into the above equation results in h [[length::( ft]]) = 176/R<sub>bt</sub> (μ). All that is left is to estimate R<sub>bt</sub>.
==Estimating r<sub>bt</sub>==
A generally accepted concept is that oil migrates after filling only the minimum possible percentage of the largest pore throats that is required to establish a continuous, thread-or rope-shaped channel through the rock (e.g., .<ref name=ch09r14>Dembicki, H., Jr., Anderson, M., L., 1989, Secondary migration of oil: experiments supporting efficient movement of separate, buoyant oil phase along limited conduits: AAPG Bulletin, vol. 73, no. 9, p. 1018–1021.</ref><ref name=ch09r8>Catalan, L., Xiaowen, F., Chatzis, I., Dullien, F., A., L., 1992, An experimental study of secondary oil migration: AAPG Bulletin, vol. 76, no. 5, p. 638–650.</ref><ref name=ch09r30>Hirsch, L., M., Thompson, A., H., 1995, Minimum saturations and buoyancy in secondary migration: AAPG Bulletin. vol. 79, no. 5, p. 696–710.</ref> This is the breakthrough or critical nonwetting phase saturation. Clearly, estimating R<sub>bt</sub> or the size of the largest connected pore throats that control hydrocarbon breakthrough is critical to this analysis.
There are at least three ways to estimate R<sub>bt</sub>.
* Measure R<sub>bt</sub> directly on core samples, then correct it to reservoir conditions using methods of the preceding section (e.g., <ref name=ch09r62>Thomas, L., K., Katz, P., L., Tek, M., R., 1968, Threshold pressure phenomena in porous media: SPE Journal, June, p. 174–184.</ref><ref name=ch09r54 />).
* Estimate the breakthrough pressure from the shape of a [[capillary pressure]] curve.<ref name=ch09r32>Katz, A., Thompson, A., H., 1987, Prediction of rock electrical conductivity from mercury injection measurements: Journal of Geophysical Research, vol. 92, p. 599–607., 10., 1029/JB092iB01p00599</ref>
* Use the Winland method<ref name=ch09r46>Pittman, E., D., 1992, Relationship of porosity to [[permeability]] to various parameters derived from mercury injection–capillary pressure curves for sandstone: AAPG Bulletin, vol. 76, no. 2, p. 191–198.</ref> to derive a measure of pore throat size in the seal.
==Winland approach to estimate r<sub>bt</sub>==
The Winland approach is perhaps the simplest method for obtaining R<sub>bt</sub> because it uses readily available core analyses. The method relates a core sample's porosity and permeability to the pore throat size indicated at a given nonwetting-phase saturation. Once breakthrough saturation is estimated, the Winland method yields pore throat sizes representative of that mode of pore throats, or R<sub>bt</sub>.
==Choosing a breakthrough saturation==
The difficulty is knowing the breakthrough saturation for a formation without lab data from samples from that formation. There are conflicting opinions about how to estimate breakthrough saturation:
* Thomas et al.<ref name=ch09r62 />), Schowalter<ref name=ch09r54 />), and general industry opinions suggest oil or gas migration through plug-size samples occurs at nonwetting phase saturations of about 10% (4-17%), i.e., that the largest 10th percentile of pore throats controls breakthrough.
* Catalan et al.<ref name=ch09r8 />) observed breakthrough saturations of 4-20% in pack experiments. Relative permeability analysis of core plugs shows the first nonwetting phase flow occurs at approximately the same saturations for most rocks.
* Other workers (Alan Byrnes, personal communication, 1995) have observed breakthrough in plug samples at highly variable saturations—sometimes more than 50%.
It would seem best to calculate R<sub>bt</sub> for different reasonable breakthrough saturations to test the sensitivity of the solution.
==Winland's r<sub>10</sub>==
Breakthrough saturation of 10% is reasonable to use for most rocks. Using a statistical analysis similar to that of Winland, Franklin<ref name=ch09r12>Coalson, E., B., Goolsby, S., M., Franklin, M., H., 1994, Subtle seals and fluid-flow barriers in carbonate rocks, in Dolson, J., C., Hendricks, M., L., Wescott, W., A., eds., Unconformity Related Hydrocarbons in Sedimentary Sequences: RMAG Guidebook for Petroleum Exploration and Exploitation in Clastic and Carbonate Sediments, p. 45–58.</ref> developed the following formula for R<sub>bt</sub> at 10% nonwetting phase saturation (also called ''r''<sub>10</sub>):
:<math>\log \mbox{R}_{\rm tt} = 0.353 + 0.427 \log \mbox{K}_{\rm a} - 0.184 \log \phi</math>
where:
* Ka = air permeability, md
* φ = porosity, % (not decimals)
Most of the cores in the porous mudstone facies found updip from the productive area have porosities of about 10% and permeabilities of about 0.1 md (or less), based on routine core analyses from the 1960s. Unfortunately, the core permeabilities are too high, given (1) the tendency to “high-grade” core plugs in better rock and (2) the fact that the parameters used on these samples could not measure values bt = 0.4μ for these rocks, consistent with petrographic data. If r<sub>35</sub> is a better approximation of R<sub>bt</sub>, then Winland's equation yields R<sub>bt</sub> = 0.1μ.
==Weyburn oil column height==
If R<sub>bt</sub> = r<sub>10</sub> = 0.4μ and h = 113 ft/R<sub>bt</sub>, then the estimated oil column is [[length::283 ft]] [[depth::(86 m]]). If R<sub>bt</sub> = r<sub>35</sub> = 0.1μ, then h = [[length::892 ft]] [[depth::(272 m]]).
==Using estimated oil or gas column heights==
Hannon<ref name=ch09r24 />) calculated only [[length::100 ft]] [[depth::(30 m]]) of [[seal capacity]] for this field. His calculations assumed a breakthrough pressure of 10-15 psi (69-103 kPa), based on “a multitude of capillary pressure curves” that he did not document. Yet we can estimate several reasonable breakthrough pressures from any given capillary pressure curve, depending on the assumed nonwetting phase saturation.
==See also==
* [[Evaluation of trap type]]
* [[Weyburn field location and trap problem]]
* [[Middle lithofacies and distribution]]
* [[Midale porosity, pore geometries, and petrophysics]]
* [[Effect of pore geometry on Sw in midale rocks]]
* [[Seal capacity and trap type]]
==References==
{{reflist}}
==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
}}
==Weyburn trap model==
A working trap model for Weyburn field is that of a macroporous vuggy packstone reservoir lying downdip from a microporous intercrystalline mudstone seal. How much hydrocarbon column could a trap like this retain, especially since superficially the seal doesn't appear to be a seal at all. Instead, it consists of rocks with appreciable [[porosity]], local oil staining, local log-calculated water saturations less than 100%, and the capability of producing significant amounts of water on DST.
==Total oil column height==
Weyburn and nearby Steelman fields appear to produce from a single, pressure-communicated oil column.<ref name=ch09r24>Hannon, N., 1987, Subsurface water flow patterns in the Canadian sector of the Williston Basin: RMAG 1987 Symposium Guidebook, p. 313–321.</ref> If so, then the total height of this combined column is about [[length::600 ft]] [[depth::(180 m]]). Could rocks of the porous mudstone facies act as a lateral seal for this much oil column? To calculate oil column height, we use the following equation:
:<math>\mbox{h} = \frac{0.670 \times \gamma \cos \theta}{\mbox{R}_{\rm bt}(\rho_{\rm w} - \rho_{\rm h})}</math>
where:
* γ = interfacial tension (dynes/cm)
* θ = contact angle
* R<sub>bt</sub> = breakthrough pore throat size (μ)
* ρ<sub>w</sub> = formation water density (g/cc)
* ρ<sub>h</sub> = hydrocarbon density (g/cc)
==Calculating oil column height at weyburn==
We can calculate the potential oil column height that could be sealed by the porous mud-stone facies using maximum reasonable estimates for the above parameters. Weyburn field oil densities grade from 35°API in the updip portion of the field to 27°API near the base. A representative gravity of 30°API is used for the column as a whole. The formation water is brackish NaCl brine (35,000 ppm).
Other parameters:
* Reservoir temp. = [[temperature::150°F]] ([[temperature::66°C]]) (possibly a low estimate)
* GOR = 100 CFG/BO (18 m<sup>3</sup> gas/m<sup>3</sup> oil) (probably low estimate)
* Reservoir press. = [[pressure::3,000 psi]] (20.7 × 10<sup>3</sup> kPa)
* γ = 35 dynes/cm at STP
* θ = 0° (seal is assumed to be very strongly water wet)
Estimates of in situ values:
* ρ<sub>w</sub> = 1.01 g/cc (from <ref name=ch09r54>Schowalter, T., T., 1979, Mechanics of secondary hydrocarbon [[migration]] and entrapment: AAPG Bulletin, vol. 63, no. 5, p. 723–760.</ref> his Figure 2)
* ρ<sub>h</sub> = 0.85 g/cc (from <ref name=ch09r54 /> his Figure 3)
Therefore:
* (ρ<sub>w</sub> – ρ<sub>h</sub>) = 0.16 (0.12 from approximations in preceding section)
* γ = 27 dynes/cm (from <ref name=ch09r54 /> his Figure 11)
* cos θ = 1 (very strongly water wet)
Therefore:
* γ cos θ = 27 dynes/cm (26 dynes/cm from approximations in preceding section)
Substituting these values into the above equation results in h [[length::( ft]]) = 176/R<sub>bt</sub> (μ). All that is left is to estimate R<sub>bt</sub>.
==Estimating r<sub>bt</sub>==
A generally accepted concept is that oil migrates after filling only the minimum possible percentage of the largest pore throats that is required to establish a continuous, thread-or rope-shaped channel through the rock (e.g., .<ref name=ch09r14>Dembicki, H., Jr., Anderson, M., L., 1989, Secondary migration of oil: experiments supporting efficient movement of separate, buoyant oil phase along limited conduits: AAPG Bulletin, vol. 73, no. 9, p. 1018–1021.</ref><ref name=ch09r8>Catalan, L., Xiaowen, F., Chatzis, I., Dullien, F., A., L., 1992, An experimental study of secondary oil migration: AAPG Bulletin, vol. 76, no. 5, p. 638–650.</ref><ref name=ch09r30>Hirsch, L., M., Thompson, A., H., 1995, Minimum saturations and buoyancy in secondary migration: AAPG Bulletin. vol. 79, no. 5, p. 696–710.</ref> This is the breakthrough or critical nonwetting phase saturation. Clearly, estimating R<sub>bt</sub> or the size of the largest connected pore throats that control hydrocarbon breakthrough is critical to this analysis.
There are at least three ways to estimate R<sub>bt</sub>.
* Measure R<sub>bt</sub> directly on core samples, then correct it to reservoir conditions using methods of the preceding section (e.g., <ref name=ch09r62>Thomas, L., K., Katz, P., L., Tek, M., R., 1968, Threshold pressure phenomena in porous media: SPE Journal, June, p. 174–184.</ref><ref name=ch09r54 />).
* Estimate the breakthrough pressure from the shape of a [[capillary pressure]] curve.<ref name=ch09r32>Katz, A., Thompson, A., H., 1987, Prediction of rock electrical conductivity from mercury injection measurements: Journal of Geophysical Research, vol. 92, p. 599–607., 10., 1029/JB092iB01p00599</ref>
* Use the Winland method<ref name=ch09r46>Pittman, E., D., 1992, Relationship of porosity to [[permeability]] to various parameters derived from mercury injection–capillary pressure curves for sandstone: AAPG Bulletin, vol. 76, no. 2, p. 191–198.</ref> to derive a measure of pore throat size in the seal.
==Winland approach to estimate r<sub>bt</sub>==
The Winland approach is perhaps the simplest method for obtaining R<sub>bt</sub> because it uses readily available core analyses. The method relates a core sample's porosity and permeability to the pore throat size indicated at a given nonwetting-phase saturation. Once breakthrough saturation is estimated, the Winland method yields pore throat sizes representative of that mode of pore throats, or R<sub>bt</sub>.
==Choosing a breakthrough saturation==
The difficulty is knowing the breakthrough saturation for a formation without lab data from samples from that formation. There are conflicting opinions about how to estimate breakthrough saturation:
* Thomas et al.<ref name=ch09r62 />), Schowalter<ref name=ch09r54 />), and general industry opinions suggest oil or gas migration through plug-size samples occurs at nonwetting phase saturations of about 10% (4-17%), i.e., that the largest 10th percentile of pore throats controls breakthrough.
* Catalan et al.<ref name=ch09r8 />) observed breakthrough saturations of 4-20% in pack experiments. Relative permeability analysis of core plugs shows the first nonwetting phase flow occurs at approximately the same saturations for most rocks.
* Other workers (Alan Byrnes, personal communication, 1995) have observed breakthrough in plug samples at highly variable saturations—sometimes more than 50%.
It would seem best to calculate R<sub>bt</sub> for different reasonable breakthrough saturations to test the sensitivity of the solution.
==Winland's r<sub>10</sub>==
Breakthrough saturation of 10% is reasonable to use for most rocks. Using a statistical analysis similar to that of Winland, Franklin<ref name=ch09r12>Coalson, E., B., Goolsby, S., M., Franklin, M., H., 1994, Subtle seals and fluid-flow barriers in carbonate rocks, in Dolson, J., C., Hendricks, M., L., Wescott, W., A., eds., Unconformity Related Hydrocarbons in Sedimentary Sequences: RMAG Guidebook for Petroleum Exploration and Exploitation in Clastic and Carbonate Sediments, p. 45–58.</ref> developed the following formula for R<sub>bt</sub> at 10% nonwetting phase saturation (also called ''r''<sub>10</sub>):
:<math>\log \mbox{R}_{\rm tt} = 0.353 + 0.427 \log \mbox{K}_{\rm a} - 0.184 \log \phi</math>
where:
* Ka = air permeability, md
* φ = porosity, % (not decimals)
Most of the cores in the porous mudstone facies found updip from the productive area have porosities of about 10% and permeabilities of about 0.1 md (or less), based on routine core analyses from the 1960s. Unfortunately, the core permeabilities are too high, given (1) the tendency to “high-grade” core plugs in better rock and (2) the fact that the parameters used on these samples could not measure values bt = 0.4μ for these rocks, consistent with petrographic data. If r<sub>35</sub> is a better approximation of R<sub>bt</sub>, then Winland's equation yields R<sub>bt</sub> = 0.1μ.
==Weyburn oil column height==
If R<sub>bt</sub> = r<sub>10</sub> = 0.4μ and h = 113 ft/R<sub>bt</sub>, then the estimated oil column is [[length::283 ft]] [[depth::(86 m]]). If R<sub>bt</sub> = r<sub>35</sub> = 0.1μ, then h = [[length::892 ft]] [[depth::(272 m]]).
==Using estimated oil or gas column heights==
Hannon<ref name=ch09r24 />) calculated only [[length::100 ft]] [[depth::(30 m]]) of [[seal capacity]] for this field. His calculations assumed a breakthrough pressure of 10-15 psi (69-103 kPa), based on “a multitude of capillary pressure curves” that he did not document. Yet we can estimate several reasonable breakthrough pressures from any given capillary pressure curve, depending on the assumed nonwetting phase saturation.
==See also==
* [[Evaluation of trap type]]
* [[Weyburn field location and trap problem]]
* [[Middle lithofacies and distribution]]
* [[Midale porosity, pore geometries, and petrophysics]]
* [[Effect of pore geometry on Sw in midale rocks]]
* [[Seal capacity and trap type]]
==References==
{{reflist}}
==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]]