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==Definition of porosity terms==

==Definition of porosity terms==

[[file:porosity_fig1.png|thumb|300px|{{figure number|1}}Schematic of a pore system relating mineralogy, water content, and porosity assessment. (Notes: *lf sample is completely disaggregated during measurement. “Varies as a function of height above the free water level.) (After Chatzis et al.<ref name=pt05r33>Chatzis, I., N. R. Morrow, and H. T. Lim, 1983, Magnitude and detailed structure of residual oil saturation: Society Petroleum Engineers Journal, v. 23, p. 311–326., 10., 2118/10681-PA</ref>; modified from Hill et al., 1969.{{citation needed}})]]

[[file:porosity_fig1.png|thumb|300px|{{figure number|1}}Schematic of a pore system relating mineralogy, water content, and porosity assessment. (Notes: *lf sample is completely disaggregated during measurement. “Varies as a function of height above the [[free water level]].) (After Chatzis et al.<ref name=pt05r33>Chatzis, I., N. R. Morrow, and H. T. Lim, 1983, Magnitude and detailed structure of residual oil saturation: Society Petroleum Engineers Journal, v. 23, p. 311–326., 10., 2118/10681-PA</ref>; modified from Hill et al., 1969.{{citation needed}})]]

Discrepancies often exist between laboratory determined porosity values and porosities derived from downhole logs. Some of these discrepancies result from differences inherent in comparing direct measurements of physical properties made on small samples with indirect assessments of averaged properties. Many of these discrepancies, however, can be explained by noting differences in the definition and assessment of porosity ([[:file:porosity_fig1.png|Figure 1]]).

Discrepancies often exist between laboratory determined porosity values and porosities derived from downhole logs. Some of these discrepancies result from differences inherent in comparing direct measurements of physical properties made on small samples with indirect assessments of averaged properties. Many of these discrepancies, however, can be explained by noting differences in the definition and assessment of porosity ([[:file:porosity_fig1.png|Figure 1]]).

===Total porosity===

===Total porosity===

''Total porosity'' includes all void space regardless of whether the pores are interconnected or isolated. There is no practical ''way'' in the laboratory to measure isolated pore volume routinely on rocks. However, it can be determined by disaggregating the samples. If the disaggregated rocks contain smectite, the technique used to dry the samples can affect porosity values and the oven-dried total porosity will be larger than the humidity-dried total porosity (see Effective porosity below). Total porosity from a density log would equate with the disaggregated oven-dried total porosity from [[Overview of routine core analysis|cores]]. The [[Basic open hole tools#Compensated neutron|neutron log]], however, would enlarge the definition to include structural hydroxyl chemistry.

''Total porosity'' includes all void space regardless of whether the pores are interconnected or isolated. There is no practical ''way'' in the laboratory to measure isolated pore volume routinely on rocks. However, it can be determined by disaggregating the samples. If the disaggregated rocks contain smectite, the technique used to dry the samples can affect porosity values and the oven-dried total porosity will be larger than the humidity-dried total porosity (see Effective porosity below). Total porosity from a [[density log]] would equate with the disaggregated oven-dried total porosity from [[Overview of routine core analysis|cores]]. The [[Basic open hole tools#Compensated neutron|neutron log]], however, would enlarge the definition to include structural hydroxyl chemistry.

===Effective porosity===

===Effective porosity===

===Carbonate pore systems===

===Carbonate pore systems===

In comparison to clastic pore systems, pore types in carbonate rocks are more varied (see [[Carbonate reservoir models: facies, diagenesis, and flow characterization]]). Three basic pore groups can be recognized:<ref name=pt05r34>Choquette, P. W., Pray, L. C., 1970, [http://archives.datapages.com/data/bulletns/1968-70/data/pg/0054/0002/0200/0207.htm Geological nomenclature and classification of porosity in sedimentary carbonates]: AAPG Bulletin, v. 54, p. 207–250.</ref> fabric selective, not fabric selective, and fabric selective or not (Table 1 and [[:file:porosity_fig3.png|Figure 3]]). Seven porosity types (interparticle, intraparticle, intercrystal, moldic, fenestral, [[fracture]], and vugs) are common and volumetrically important.

In comparison to clastic pore systems, pore types in carbonate rocks are more varied (see [[Carbonate reservoir models: facies, diagenesis, and flow characterization]]). Three basic pore groups can be recognized:<ref name=pt05r34>Choquette, P. W., and L. C. Pray, 1970, [http://archives.datapages.com/data/bulletns/1968-70/data/pg/0054/0002/0200/0207.htm Geological nomenclature and classification of porosity in sedimentary carbonates]: AAPG Bulletin, v. 54, p. 207–250.</ref> fabric selective, not fabric selective, and fabric selective or not (Table 1 and [[:file:porosity_fig3.png|Figure 3]]). Seven porosity types (interparticle, intraparticle, intercrystal, moldic, fenestral, [[fracture]], and vugs) are common and volumetrically important.

{| class = "wikitable"

{| class = "wikitable"

Primary porosity in clastic and some carbonate rocks (such as oolites) is a function of [[grain size]], packing, shape, [[Core_description#Maturity|sorting]], and amount of intergranular matrix and cement.<ref name=pt05r124>Pettijohn, F. J., 1975, Sedimentary rocks, 3rd ed.: New York, Harper and Row, p. 628.</ref> In theory, porosity is independent of grain size. Changes in grain size, however, affect grain shape and sorting. Because these variables directly affect porosity, changes in grain size indirectly affect porosity.

Primary porosity in clastic and some carbonate rocks (such as oolites) is a function of [[grain size]], packing, shape, [[Core_description#Maturity|sorting]], and amount of intergranular matrix and cement.<ref name=pt05r124>Pettijohn, F. J., 1975, Sedimentary rocks, 3rd ed.: New York, Harper and Row, p. 628.</ref> In theory, porosity is independent of grain size. Changes in grain size, however, affect grain shape and sorting. Because these variables directly affect porosity, changes in grain size indirectly affect porosity.

The theoretical effects of grain size and packing on porosity were investigated by Graton and Fraser<ref name=pt05r69>Graton, L. C., Fraser, H. J., 1935, Systematic packing of spheres with particular reference to porosity and [[permeability]]: Journal of Geology, v. 43, p. 785–909, DOI: [http://www.jstor.org/discover/10.2307/30058420 10.1086/jg.1935.43.issue-8].</ref> who computed the porosity of various packing arrangements of uniform spheres. The theoretical maximum porosity for a cubic packed rock, regardless of the value assigned to grain radius, is 47.6%. Porosity values for other packing arrangements ([[:file:porosity_fig4.png|Figure 4]]) can be calculated.

The theoretical effects of grain size and packing on porosity were investigated by Graton and Fraser<ref name=pt05r69>Graton, L. C., and H. J. Fraser, 1935, Systematic packing of spheres with particular reference to porosity and [[permeability]]: Journal of Geology, v. 43, p. 785–909, DOI: [http://www.jstor.org/discover/10.2307/30058420 10.1086/jg.1935.43.issue-8].</ref> who computed the porosity of various packing arrangements of uniform spheres. The theoretical maximum porosity for a cubic packed rock, regardless of the value assigned to grain radius, is 47.6%. Porosity values for other packing arrangements ([[:file:porosity_fig4.png|Figure 4]]) can be calculated.

The effects of grain shape on primary porosity were investigated by Fraser<ref name=pt05r59>Fraser, H. J., 1935, Experimental study of porosity and permeability of clastic sediments: Journal of Geology, v. 43, p. 910–1010, DOI: [http://www.jstor.org/discover/10.2307/30058422?uid=3739848&uid=2&uid=4&uid=3739256&sid=21103791335533 10.1086/jg.1935.43.issue-8].</ref> and Beard and Weyl.<ref name=pt05r23>Beard, D. C., Weyl, P. K., 1973, [http://archives.datapages.com/data/bulletns/1971-73/data/pg/0057/0002/0300/0349.htm Influence of texture on porosity and permeability of unconsolidated sand]: AAPG Bulletin, v. 57, p. 349–369.</ref> In general, porosity decreases as sphericity increases due to tighter packing arrangements associated with spherical grains. Numerous studies<ref name=pt05r59 /><ref name=pt05r136>Rogers, J. J., Head, W., 1961, [http://jsedres.geoscienceworld.org/content/31/3/467.abstract Relationship between porosity, median size and sorting coefficients of synthetic sands]: Journal of Sedimentary Petrology, v. 31, p. 467–470.</ref><ref name=pt05r23 /><ref name=pt05r131>Pryor, W. A., 1973, [http://archives.datapages.com/data/bulletns/1971-73/data/pg/0057/0001/0150/0162.htm Permeability-porosity patterns and variations in some Holocene sand bodies]: AAPG Bulletin, v. 57, n. 1, p. 162–189.</ref> indicate that porosity generally increases with [[Core_description#Maturity|sorting]]. Gaither<ref name=pt05r62>Gaither, A., 1953, A study of porosity and grain relationships in experimental sands: Journal of Sedimentary Petrology, v. 23, p. 180–195, DOI: [http://jsedres.geoscienceworld.org/content/23/3/180.abstract 10.1306/D4269602-2B26-11D7-8648000102C1865D].</ref> showed that when two grain sizes are mixed, porosity is reduced until both grain sizes are present in approximately equal amounts.

The effects of grain shape on primary porosity were investigated by Fraser<ref name=pt05r59>Fraser, H. J., 1935, Experimental study of porosity and permeability of clastic sediments: Journal of Geology, v. 43, p. 910–1010, DOI: [http://www.jstor.org/discover/10.2307/30058422?uid=3739848&uid=2&uid=4&uid=3739256&sid=21103791335533 10.1086/jg.1935.43.issue-8].</ref> and Beard and Weyl.<ref name=pt05r23>Beard, D. C., and P. K. Weyl, 1973, [http://archives.datapages.com/data/bulletns/1971-73/data/pg/0057/0002/0300/0349.htm Influence of texture on porosity and permeability of unconsolidated sand]: AAPG Bulletin, v. 57, p. 349–369.</ref> In general, porosity decreases as sphericity increases due to tighter packing arrangements associated with spherical grains. Numerous studies<ref name=pt05r59 /><ref name=pt05r136>Rogers, J. J., and W. Head, 1961, [http://jsedres.geoscienceworld.org/content/31/3/467.abstract Relationship between porosity, median size and sorting coefficients of synthetic sands]: Journal of Sedimentary Petrology, v. 31, p. 467–470.</ref><ref name=pt05r23 /><ref name=pt05r131>Pryor, W. A., 1973, [http://archives.datapages.com/data/bulletns/1971-73/data/pg/0057/0001/0150/0162.htm Permeability-porosity patterns and variations in some Holocene sand bodies]: AAPG Bulletin, v. 57, n. 1, p. 162–189.</ref> indicate that porosity generally increases with [[Core_description#Maturity|sorting]]. Gaither<ref name=pt05r62>Gaither, A., 1953, A study of porosity and grain relationships in experimental sands: Journal of Sedimentary Petrology, v. 23, p. 180–195, DOI: [http://jsedres.geoscienceworld.org/content/23/3/180.abstract 10.1306/D4269602-2B26-11D7-8648000102C1865D].</ref> showed that when two grain sizes are mixed, porosity is reduced until both grain sizes are present in approximately equal amounts.

==Laboratory determination of porosity==

==Laboratory determination of porosity==

===Sample preparation===

===Sample preparation===

Most porosity analysis techniques require removal of soluble hydrocarbons before sample analysis. Factors influencing sample cleaning include the types of hydrocarbon present, the presence of salts precipitated from pore waters, rock mineralogy, degree of cementation, and time constraints. Different solvents and cleaning techniques can be used to remove hydrocarbons from rocks. Toluene is generally an effective solvent for most liquid hydrocarbons. If hydrocarbons cannot be removed with toluene, toluene/methanol (azeotrope), chloroform/methanol (azeotrope), methylene chloride or carbon disulfide may be used. Methanol is used to remove salts formed from the evaporation of saline pore waters. Rocks containing gypsum and smectite require special low temperature cleaning techniques to minimize removal of structural and bound water.<ref name=pt05r89>Keelan, D. K., 1971, A critical review of core analysis techniques: 22nd Annual Technical Meeting of the Petroleum Society of the Canadian Institute of Mining, Calgary, Banff, Alberta, June 2–5, Paper No. 7612, p. 1–13.</ref>

Most porosity analysis techniques require removal of soluble hydrocarbons before sample analysis. Factors influencing sample cleaning include the types of hydrocarbon present, the presence of salts precipitated from pore waters, rock [[mineralogy]], degree of cementation, and time constraints. Different solvents and cleaning techniques can be used to remove hydrocarbons from rocks. Toluene is generally an effective solvent for most liquid hydrocarbons. If hydrocarbons cannot be removed with toluene, toluene/methanol (azeotrope), chloroform/methanol (azeotrope), methylene chloride or carbon disulfide may be used. Methanol is used to remove salts formed from the evaporation of saline pore waters. Rocks containing [[gypsum]] and smectite require special low temperature cleaning techniques to minimize removal of structural and bound water.<ref name=pt05r89>Keelan, D. K., 1971, A critical review of core analysis techniques: 22nd Annual Technical Meeting of the Petroleum Society of the Canadian Institute of Mining, Calgary, Banff, Alberta, June 2–5, Paper No. 7612, p. 1–13.</ref>

Laboratory determination of porosity generally requires dry samples. Most clay-free samples can be dried in an oven ([[temperature::115&deg;C]]). If clay minerals, especially smectite, are present, humidity drying (45% relative humidity, [[temperature::63&deg;C]]) is required to prevent removal of clay-bound water.

Laboratory determination of porosity generally requires dry samples. Most clay-free samples can be dried in an oven ([[temperature::115&deg;C]]). If clay minerals, especially smectite, are present, humidity drying (45% relative humidity, [[temperature::63&deg;C]]) is required to prevent removal of clay-bound water.

===Other techniques===

===Other techniques===

Another technique available for the determination of porosity in addition to those mentioned here is point counting pore space occupied by blue epoxy in thin sections (see [[Thin section analysis]]). Also, significant progress has been made recently in the development of petrographic image analysis (PIA) as a technique for porosity determination.<ref name=pt05r52>Ehrlich, R., Kennedy, S. K., Crabtree, S. J., Crabtree, R. C., 1984, [http://jsedres.geoscienceworld.org/content/54/4/1365.abstract Petrographic image analysis, 1. Analysis of reservoir pore complexes]: Journal of Sedimentary Petrology, v. 54, n. 4, p. 1365–1378.</ref><ref name=pt05r66>Gerard, R. E., Philipson, C. A., Bellentine, F. M., Marshall, D. H., 1991, Petrographic image analysis, in Polaz, I., Sengupta, S. K., eds., Automated Pattern Analysis in Petroleum Exploration: New York, Springer-Verlag.</ref> In this process, pore space is delineated from mineralogy using photographic imaging techniques. Taking images from several locations on a thin section allows one to compensate for a three-dimensional parameter from two dimensions.

Another technique available for the determination of porosity in addition to those mentioned here is point counting pore space occupied by blue epoxy in thin sections (see [[Thin section analysis]]). Also, significant progress has been made recently in the development of petrographic image analysis (PIA) as a technique for porosity determination.<ref name=pt05r52>Ehrlich, R., S. K. Kennedy, S. J. Crabtree, and R. C. Crabtree, 1984, [http://jsedres.geoscienceworld.org/content/54/4/1365.abstract Petrographic image analysis, 1. Analysis of reservoir pore complexes]: Journal of Sedimentary Petrology, v. 54, n. 4, p. 1365–1378.</ref><ref name=pt05r66>Gerard, R. E., C. A. Philipson, F. M. Bellentine, and D. H. Marshall, 1991, Petrographic image analysis, in Polaz, I., Sengupta, S. K., eds., Automated Pattern Analysis in Petroleum Exploration: New York, Springer-Verlag.</ref> In this process, pore space is delineated from mineralogy using photographic imaging techniques. Taking images from several locations on a thin section allows one to compensate for a three-dimensional parameter from two dimensions.

Both X-ray computerized tomography (CT) and nuclear magnetic resonance (NMR) have applications to determining porosity. This is outside the scope of this discussion but is comprehensively covered in the literature (e.g., Vinegar,<ref name=pt05r159>Vinegar, H. J., 1986, X-ray, CT, and NMR imaging of rocks: Journal of Petroleum Technology, v. 38, p. 257–259, DOI: [https://www.onepetro.org/journal-paper/SPE-15277-PA 10.2118/15277-PA].</ref> and Wellington and Vinegar<ref name=pt05r167>Wellington, S. L., Vinegar, H. J., 1987, X-ray computerized tomography: Journal of Petroleum Technology, v. 39, n. 8, p. 885–898, DOI: [https://www.onepetro.org/journal-paper/SPE-16983-PA 10.2118/16983-PA].</ref>).

Both X-ray computerized tomography (CT) and nuclear magnetic resonance (NMR) have applications to determining porosity. This is outside the scope of this discussion but is comprehensively covered in the literature (e.g., Vinegar,<ref name=pt05r159>Vinegar, H. J., 1986, X-ray, CT, and NMR imaging of rocks: Journal of Petroleum Technology, v. 38, p. 257–259, DOI: [https://www.onepetro.org/journal-paper/SPE-15277-PA 10.2118/15277-PA].</ref> and Wellington and Vinegar<ref name=pt05r167>Wellington, S. L., and H. J. Vinegar, 1987, X-ray computerized tomography: Journal of Petroleum Technology, v. 39, n. 8, p. 885–898, DOI: [https://www.onepetro.org/journal-paper/SPE-16983-PA 10.2118/16983-PA].</ref>).

===Effects of confining pressure on porosity===

===Effects of confining pressure on porosity===

Porosity decreases with increasing net overburden pressure ([[Geostatic and lithostatic pressure|lithostatic pressure]] minus [http://www.glossary.oilfield.slb.com/en/Terms/p/pore_pressure.aspx pore pressure]), and in clastic rocks, stress sensitivity generally increases with increasing clay and decreasing cement content.<ref name=pt05r8>Amaefule, J. O., Keelan, D. K., Kersey, D. G., Marschall, D. M., 1988, Reservoir description—a practical synergistic engineering and geological approach based on analysis of core data: 63rd SPE Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Houston, TX, October 2–5, SPE 18167.</ref> Because porosity is stress dependent, laboratory measurements should be made at stress conditions whenever possible. These measurements are done with specially designed Boyle's law (pore volume) porosimeters, similar to that shown in [[:file:porosity_fig5.png|Figure 5]], which apply hydrostatic stress to the sample. In the reservoir, however, the resolved stress component is uniaxial. Uniaxial stress is less than hydrostatic stress, and consequently, the hydrostatic strain measured in the laboratory should be converted to an equivalent reservoir (uniaxial) strain.

Porosity decreases with increasing net overburden pressure ([[Geostatic and lithostatic pressure|lithostatic pressure]] minus [http://www.glossary.oilfield.slb.com/en/Terms/p/pore_pressure.aspx pore pressure]), and in clastic rocks, stress sensitivity generally increases with increasing clay and decreasing cement content.<ref name=pt05r8>Amaefule, J. O., D. K. Keelan, D. G. Kersey, and D. M. Marschall, 1988, Reservoir description—a practical synergistic engineering and geological approach based on analysis of core data: 63rd SPE Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Houston, TX, October 2–5, SPE 18167.</ref> Because porosity is stress dependent, laboratory measurements should be made at stress conditions whenever possible. These measurements are done with specially designed Boyle's law (pore volume) porosimeters, similar to that shown in [[:file:porosity_fig5.png|Figure 5]], which apply hydrostatic stress to the sample. In the reservoir, however, the resolved stress component is uniaxial. Uniaxial stress is less than hydrostatic stress, and consequently, the hydrostatic strain measured in the laboratory should be converted to an equivalent reservoir (uniaxial) strain.

==See also==

==See also==

[[Category:Laboratory methods]]

[[Category:Laboratory methods]]