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Measuring displacement pressure using mercury injection (view source)
Revision as of 15:32, 31 January 2014
, 15:32, 31 January 2014Initial 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 = Evaluating top and fault seal
| frompg = 10-1
| topg = 10-94
| author = Grant M. Skerlec
| link = http://archives.datapages.com/data/specpubs/beaumont/ch10/ch10.htm
| pdf =
| store = http://store.aapg.org/detail.aspx?id=545
| isbn = 0-89181-602-X
}}
The displacement pressure is routinely inferred by forcing mercury into the pore space of a sample (cores or cuttings) and measuring the percent of mercury saturation vs. increasing pressure.
==Procedure==
This figure shows a typical mercury capillary curve for a sandstone. Mercury is first forced into the largest connected pore throats. Saturation increases with increasing pressure as mercury continues to be forced into progressively smaller pore throats.
[[file:evaluating-top-and-fault-seal_fig10-48.png|thumb|{{figure number|10-48}}After .<ref name=ch10r67>Schowalter, T., T., 1979, Mechanics of secondary hydrocarbon [[migration]] and entrapment: AAPG Bulletin, vol. 63, no. 5, p. 723–760.</ref>]]
==Values of p<sub>d</sub>==
Displacement pressure (P<sub>d</sub>) is defined as the pressure necessary to form a continuous hydrocarbon filament in the pore space of the seal. It is commonly inferred from the injection pressure at 10% saturation<ref name=ch10r67 /> for two reasons:
* Most reservoirs have a pronounced plateau along which saturation rapidly increases. The pressure at 10% or 40% saturation gives a similar P<sub>d</sub>.
* Measured saturations required to create a continuous hydrocarbon filament range from 5–17% with an average of 10%.<ref name=ch10r67 />
Alternatively, some workers define P<sub>d</sub> as the pressure at the first inflection point of capillary curve.<ref name=ch10r42>Katz, A., J., Thompson, A., H., 1986, Quantitative prediction of [[permeability]] in porous rock: Physical Review Bulletin, vol. 34, p. 8179–8181., 10., 1103/PhysRevB., 34., 8179</ref> Figure 10-49 above shows the inferred P<sub>d</sub> at both 10% saturation and at the inflection point.
==Cores, cuttings, and low-permeability rocks==
Samples for mercury injection laboratory analysis can include cores as well as cuttings. Measurements made from cuttings do not yield the same value as those from cores, so they require an empirical correction factor that ranges from 15–250 psi.<ref name=ch10r78>Sneider, R., M., Bolger, G., 1993, Estimating seals from wireline logs of clastic seals and reservoir intervals, in Ebanks, J., Kaldi, J., Vavra, C., eds., Seals and Traps: A Multidisciplinary Approach: AAPG Hedberg Research conference, unpublished abstract.</ref>
Seals with low permeability and small pore throats may require longer equilibration times during mercury injection.<ref name=ch10r87>Vavra, C., L., Kaldi, J., G., Sneider, R., M., 1992, Geological applications of [[capillary pressure]]: a review: AAPG Bulletin, vol. 76, no. 6, p. 840–850.</ref>
==Converting laboratory measurements==
Since laboratory measurements of P<sub>d</sub> are given in the air-mercury system rather than the oil-water or gas-water systems, we must convert from P<sub>dm</sub>, using mercury, to P<sub>dh</sub>, or hydrocarbons:
:<math>\mbox{P}_{\rm dh} = \frac{\gamma_{\rm h}\cos \theta_{\rm h}\mbox{P}_{\rm dm}}{\gamma_{\rm m} \cos \theta_{\rm m}}</math>
Displacement pressures measured in the air-mercury system are then converted to the hydrocarbon–water system at subsurface conditions. To convert, we must know the temperature, pressure, [[wettability]], and coefficient of interfacial tension for the hydrocarbon phase. These parameters are commonly inferred from the composition, gas–oil ratio, and API gravity.<ref name=ch10r67 /><ref name=ch10r87 /> For the air–mercury system, the wettability of mercury is 140° (cos 140 = 0.766). The coefficient of interfacial tension for mercury is 485 dynes/cm.<ref name=ch10r87 />
==See also==
* [[Estimating displacement pressure]]
* [[Estimating Pd from sedimentary facies and well logs]]
* [[Estimating Pd from pore size]]
==References==
{{reflist}}
==External links==
{{search}}
* [http://archives.datapages.com/data/specpubs/beaumont/ch10/ch10.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:Evaluating top and fault seal]]
| 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 = Evaluating top and fault seal
| frompg = 10-1
| topg = 10-94
| author = Grant M. Skerlec
| link = http://archives.datapages.com/data/specpubs/beaumont/ch10/ch10.htm
| pdf =
| store = http://store.aapg.org/detail.aspx?id=545
| isbn = 0-89181-602-X
}}
The displacement pressure is routinely inferred by forcing mercury into the pore space of a sample (cores or cuttings) and measuring the percent of mercury saturation vs. increasing pressure.
==Procedure==
This figure shows a typical mercury capillary curve for a sandstone. Mercury is first forced into the largest connected pore throats. Saturation increases with increasing pressure as mercury continues to be forced into progressively smaller pore throats.
[[file:evaluating-top-and-fault-seal_fig10-48.png|thumb|{{figure number|10-48}}After .<ref name=ch10r67>Schowalter, T., T., 1979, Mechanics of secondary hydrocarbon [[migration]] and entrapment: AAPG Bulletin, vol. 63, no. 5, p. 723–760.</ref>]]
==Values of p<sub>d</sub>==
Displacement pressure (P<sub>d</sub>) is defined as the pressure necessary to form a continuous hydrocarbon filament in the pore space of the seal. It is commonly inferred from the injection pressure at 10% saturation<ref name=ch10r67 /> for two reasons:
* Most reservoirs have a pronounced plateau along which saturation rapidly increases. The pressure at 10% or 40% saturation gives a similar P<sub>d</sub>.
* Measured saturations required to create a continuous hydrocarbon filament range from 5–17% with an average of 10%.<ref name=ch10r67 />
Alternatively, some workers define P<sub>d</sub> as the pressure at the first inflection point of capillary curve.<ref name=ch10r42>Katz, A., J., Thompson, A., H., 1986, Quantitative prediction of [[permeability]] in porous rock: Physical Review Bulletin, vol. 34, p. 8179–8181., 10., 1103/PhysRevB., 34., 8179</ref> Figure 10-49 above shows the inferred P<sub>d</sub> at both 10% saturation and at the inflection point.
==Cores, cuttings, and low-permeability rocks==
Samples for mercury injection laboratory analysis can include cores as well as cuttings. Measurements made from cuttings do not yield the same value as those from cores, so they require an empirical correction factor that ranges from 15–250 psi.<ref name=ch10r78>Sneider, R., M., Bolger, G., 1993, Estimating seals from wireline logs of clastic seals and reservoir intervals, in Ebanks, J., Kaldi, J., Vavra, C., eds., Seals and Traps: A Multidisciplinary Approach: AAPG Hedberg Research conference, unpublished abstract.</ref>
Seals with low permeability and small pore throats may require longer equilibration times during mercury injection.<ref name=ch10r87>Vavra, C., L., Kaldi, J., G., Sneider, R., M., 1992, Geological applications of [[capillary pressure]]: a review: AAPG Bulletin, vol. 76, no. 6, p. 840–850.</ref>
==Converting laboratory measurements==
Since laboratory measurements of P<sub>d</sub> are given in the air-mercury system rather than the oil-water or gas-water systems, we must convert from P<sub>dm</sub>, using mercury, to P<sub>dh</sub>, or hydrocarbons:
:<math>\mbox{P}_{\rm dh} = \frac{\gamma_{\rm h}\cos \theta_{\rm h}\mbox{P}_{\rm dm}}{\gamma_{\rm m} \cos \theta_{\rm m}}</math>
Displacement pressures measured in the air-mercury system are then converted to the hydrocarbon–water system at subsurface conditions. To convert, we must know the temperature, pressure, [[wettability]], and coefficient of interfacial tension for the hydrocarbon phase. These parameters are commonly inferred from the composition, gas–oil ratio, and API gravity.<ref name=ch10r67 /><ref name=ch10r87 /> For the air–mercury system, the wettability of mercury is 140° (cos 140 = 0.766). The coefficient of interfacial tension for mercury is 485 dynes/cm.<ref name=ch10r87 />
==See also==
* [[Estimating displacement pressure]]
* [[Estimating Pd from sedimentary facies and well logs]]
* [[Estimating Pd from pore size]]
==References==
{{reflist}}
==External links==
{{search}}
* [http://archives.datapages.com/data/specpubs/beaumont/ch10/ch10.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:Evaluating top and fault seal]]