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[[file:BLTN12220fig5.jpg|thumb|400px|Photomicrographs of calcite types and their fluid inclusions in the Feixianguan Formation. (A) Pre-TSR calcite (yellow arrow) with bitumen filling the microfracture in calcite (blue arrows), implying that the calcite formed before the formation of fracture and oil charging, well LJ1, 3470.40 m (11,382.91 ft). (B) Two-phase aqueous fluid inclusions (yellow arrows) present in pre-TSR calcite, well LJ1, 3470.40 m (11,382.91 ft). Note that no petroleum inclusions were found in pre-TSR calcite. (C) Oil-stage TSR calcite (yellow arrow) with bitumen and oil inclusions, well LJ6, 3936.00 m (12,910.08 ft). (D) Two-phase aqueous fluid inclusions (yellow arrow), bitumen, and oil inclusions (red arrows) are commonly present within the calcite, implying that the calcite formed during the time that oil reacted with anhydrite, well LJ6, 3936.00 m (12,910.08 ft). (E) Gas-stage TSR calcite (yellow arrow), with no evidence of bitumen or oil inclusions found in this type of calcite, suggesting that calcite was formed by gas reacting with anhydrite, well D4, 4793.00 m (15,721.04 ft). (F) Two-phase aqueous fluid inclusions (yellow arrows) commonly present in calcite. Note that no petroleum inclusions were found in gas-stage TSR calcite, well D4, 4793.00 m (15,721.04 ft).<ref name=Jiangetal_2014>Jiang, Lei, Richard H. Worden, and Chun Fang Cai, 2014, Thermochemical sulfate reduction and fluid evolution of the Lower Triassic Feixianguan Formation sour gas reservoirs, northeast Sichuan Basin: AAPG Bulletin v. 98, no. 5, 947-973, DOI: [http://archives.datapages.com/data/bulletns/2014/05may/BLTN12220/BLTN12220.html 10.1306/10171312220].</ref>]]

[[file:BLTN12220fig5.jpg|thumb|400px|Photomicrographs of calcite types and their fluid inclusions in the Feixianguan Formation. (A) Pre-TSR calcite (yellow arrow) with bitumen filling the microfracture in calcite (blue arrows), implying that the calcite formed before the formation of fracture and oil charging, well LJ1, 3470.40 m (11,382.91 ft). (B) Two-phase aqueous fluid inclusions (yellow arrows) present in pre-TSR calcite, well LJ1, 3470.40 m (11,382.91 ft). Note that no [[petroleum]] inclusions were found in pre-TSR calcite. (C) Oil-stage TSR calcite (yellow arrow) with bitumen and oil inclusions, well LJ6, 3936.00 m (12,910.08 ft). (D) Two-phase aqueous fluid inclusions (yellow arrow), bitumen, and oil inclusions (red arrows) are commonly present within the calcite, implying that the calcite formed during the time that oil reacted with [[anhydrite]], well LJ6, 3936.00 m (12,910.08 ft). (E) Gas-stage TSR calcite (yellow arrow), with no evidence of bitumen or oil inclusions found in this type of calcite, suggesting that calcite was formed by gas reacting with anhydrite, well D4, 4793.00 m (15,721.04 ft). (F) Two-phase aqueous fluid inclusions (yellow arrows) commonly present in calcite. Note that no petroleum inclusions were found in gas-stage TSR calcite, well D4, 4793.00 m (15,721.04 ft).<ref name=Jiangetal_2014>Jiang, Lei, Richard H. Worden, and Chun Fang Cai, 2014, Thermochemical sulfate reduction and fluid evolution of the Lower Triassic Feixianguan Formation sour gas reservoirs, northeast Sichuan Basin: AAPG Bulletin v. 98, no. 5, 947-973, DOI: [http://archives.datapages.com/data/bulletns/2014/05may/BLTN12220/BLTN12220.html 10.1306/10171312220].</ref>]]

Petrographic analysis of thin sections made from rocks within the productive interval of an oil or gas field provides unique information regarding [[reservoir quality]], reservoir homogeneity, and in some cases, the potential for [[Rock-water reaction: formation damage|formation damage]] that can be caused by completion and/or [[stimulation]] procedures.

Petrographic analysis of thin sections made from rocks within the productive interval of an oil or gas field provides unique information regarding [[reservoir quality]], reservoir homogeneity, and in some cases, the potential for [[Rock-water reaction: formation damage|formation damage]] that can be caused by [[Wellcompletion|completion]] and/or [[stimulation]] procedures.

==Sample collection==

==Sample collection==

==Sample preparation==

==Sample preparation==

Once samples have been selected, impregnation and thin sectioning procedures are critical to successful petrographic analysis. Samples are impregnated with low-viscosity epoxy introduced while the samples are under a vacuum. After vacuum impregnation, some laboratories apply pressure via an inert gas to force the epoxy into small pores. The epoxy is stained, usually blue, to facilitate observation of porosity once thin sections have been completed. Epoxy can also be “stained” with fluorescent dye, either during impregnation or after thin sections are completed, to enhance observation of relatively small pores when thin sections are viewed under incident fluorescent light.<ref name=pt05r138>Ruzyla, K., Jezek, D. I., 1987, Staining method for recognition of pore space in thin and polished sections: Journal of Sedimentary Petrology, v. 57, p. 777–778, DOI: 10.1306/212F8C38-2B24-11D7-8648000102C1865D.</ref> Thin sections must be carefully ground to final thickness (usually 30 μm) to avoid fracturing and plucking.

Once samples have been selected, impregnation and thin sectioning procedures are critical to successful petrographic analysis. Samples are impregnated with low-[[viscosity]] epoxy introduced while the samples are under a vacuum. After vacuum impregnation, some laboratories apply pressure via an inert gas to force the epoxy into small pores. The epoxy is stained, usually blue, to facilitate observation of porosity once thin sections have been completed. Epoxy can also be “stained” with fluorescent dye, either during impregnation or after thin sections are completed, to enhance observation of relatively small pores when thin sections are viewed under incident fluorescent light.<ref name=pt05r138>Ruzyla, K., Jezek, D. I., 1987, Staining method for recognition of pore space in thin and polished sections: Journal of Sedimentary Petrology, v. 57, p. 777–778, DOI: 10.1306/212F8C38-2B24-11D7-8648000102C1865D.</ref> Thin sections must be carefully ground to final thickness (usually 30 μm) to avoid fracturing and plucking.

At this stage, samples can be stained for specific minerals if warranted by rock composition and objectives of the petrographic analysis. Common stains are available for [[calcite]], [[dolomite]], [[ferrous carbonate]], [[K-feldspar]], and [[plagioclase]]. Thin sections are then either covered or left uncovered. The conventional practice of gluing cover slips onto thin sections with either Canada balsam or epoxy is decreasing in popularity because many analyses must be performed on uncovered thin sections. Thin sections that are not polished can be “covered” with colorless fingernail polish. If thin sections are to be analyzed by [http://www.geology.wisc.edu/~johnf/g777/CL/Gotze-CL-2002.pdf cathodoluminescence] or [[Wikipedia:Electron microprobe|microprobe]] techniques, they must be polished to yield suitable results.

At this stage, samples can be stained for specific minerals if warranted by rock composition and objectives of the petrographic analysis. Common stains are available for [[calcite]], [[dolomite]], [[ferrous carbonate]], [[K-feldspar]], and [[plagioclase]]. Thin sections are then either covered or left uncovered. The conventional practice of gluing cover slips onto thin sections with either Canada balsam or epoxy is decreasing in popularity because many analyses must be performed on uncovered thin sections. Thin sections that are not polished can be “covered” with colorless fingernail polish. If thin sections are to be analyzed by [http://www.geology.wisc.edu/~johnf/g777/CL/Gotze-CL-2002.pdf cathodoluminescence] or [[Wikipedia:Electron microprobe|microprobe]] techniques, they must be polished to yield suitable results.

==Petrographic techniques==

==Petrographic techniques==

Basic petrographic analysis is performed in transmitted light using a [http://dictionary.reference.com/browse/polarizing+microscope polarizing microscope]. Certain petrographic problems require the use of a cathodoluminescence (CL) microscope (see [[SEM, XRD, CL, and XF methods]]). CL petrography is used to detect cement stratigraphy and original fabrics in recrystallized [[carbonate]] rocks<ref name=pt05r48>Dorobek, S. L., 1987, [http://archives.datapages.com/data/bulletns/1986-87/data/pg/0071/0005/0450/0492.htm Petrography, geochemistry, and origin of burial diagenetic facies, Siluro-Devonian Helderberg Group (carbonate rocks), central Appalachians]: AAPG Bulletin, v. 71, p. 492–514.</ref> and to distinguish between [http://dictionary.reference.com/browse/detrital detrital] quartz grains and [http://dictionary.reference.com/browse/authigenic authigenic] quartz overgrowths (cement) in sandstones.<ref name=pt05r80>Houseknecht, D. W., 1987, [http://archives.datapages.com/data/bulletns/1986-87/data/pg/0071/0006/0600/0633.htm Assessing the relative importance of compaction processes and cementation to reduction of porosity in sandstones]: AAPG Bulletin, v. 71, p. 633–642.</ref>

Basic petrographic analysis is performed in transmitted light using a [http://dictionary.reference.com/browse/polarizing+microscope polarizing microscope]. Certain petrographic problems require the use of a cathodoluminescence (CL) microscope (see [[SEM, XRD, CL, and XF methods]]). CL petrography is used to detect cement stratigraphy and original fabrics in recrystallized [[carbonate]] rocks<ref name=pt05r48>Dorobek, S. L., 1987, [http://archives.datapages.com/data/bulletns/1986-87/data/pg/0071/0005/0450/0492.htm Petrography, geochemistry, and origin of burial diagenetic facies, Siluro-Devonian Helderberg Group (carbonate rocks), central Appalachians]: AAPG Bulletin, v. 71, p. 492–514.</ref> and to distinguish between [http://dictionary.reference.com/browse/detrital detrital] [[quartz]] grains and [http://dictionary.reference.com/browse/authigenic authigenic] [[quartz]] overgrowths (cement) in sandstones.<ref name=pt05r80>Houseknecht, D. W., 1987, [http://archives.datapages.com/data/bulletns/1986-87/data/pg/0071/0006/0600/0633.htm Assessing the relative importance of compaction processes and cementation to reduction of porosity in sandstones]: AAPG Bulletin, v. 71, p. 633–642.</ref>

Petrographic analysis of thin sections in either transmitted light or CL can involve either qualitative description or quantitative estimation of rock properties, depending upon objectives of the analysis. Quantitative estimation of composition and porosity types by modal analysis (point counting) is recommended for both carbonate and sandstone reservoir rocks. In addition, quantitative estimation of textural parameters ([[grain size]] and [[Core_description#Maturity|sorting]]) is recommended for sandstones.

Petrographic analysis of thin sections in either transmitted light or CL can involve either qualitative description or quantitative estimation of rock properties, depending upon objectives of the analysis. Quantitative estimation of composition and porosity types by modal analysis (point counting) is recommended for both carbonate and sandstone reservoir rocks. In addition, quantitative estimation of textural parameters ([[grain size]] and [[Core_description#Maturity|sorting]]) is recommended for sandstones.

Textures of sandstones can be qualitatively described by using standard images to estimate the [[Grain size|size]], [[Core_description#Maturity|sorting]], sphericity, and roundness of clastic particles. Quantitative textural analysis involves measurement of a certain number of grains (commonly 100 per thin section) so that mean grain size and sorting (standard deviation) can be calculated. Grain size measurements can be performed on a [http://www.gonda.ucla.edu/bri_core/trlight.htm transmitted light microscope] equipped with a graduated ocular lens, or they can be done by placing thin sections in a microfiche reader and measuring grains with a ruler. Whichever instrument is used, a glass slide inscribed with a metric scale must be used to determine a conversion factor for converting raw data to millimeters.

Textures of sandstones can be qualitatively described by using standard images to estimate the [[Grain size|size]], [[Core_description#Maturity|sorting]], sphericity, and roundness of clastic particles. Quantitative textural analysis involves measurement of a certain number of grains (commonly 100 per thin section) so that mean grain size and sorting (standard deviation) can be calculated. Grain size measurements can be performed on a [http://www.gonda.ucla.edu/bri_core/trlight.htm transmitted light microscope] equipped with a graduated ocular lens, or they can be done by placing thin sections in a microfiche reader and measuring grains with a ruler. Whichever instrument is used, a glass slide inscribed with a metric scale must be used to determine a conversion factor for converting raw data to millimeters.

Once data are converted to millimeters, it is also recommended that the data be converted to the phi scale, where the grain size in phi = –log₂ × grain size in mm. Mean grain size and sorting (standard deviation of grain size measurements) are then calculated. Mean grain size can be expressed in either the millimeter or phi scale, but sorting must be expressed in the phi scale to maintain a sorting index that is useful across a wide range of grain sizes.

Once data are converted to millimeters, it is also recommended that the data be converted to the [[phi scale]], where the grain size in phi = –log₂ × grain size in mm. Mean grain size and sorting (standard deviation of grain size measurements) are then calculated. Mean grain size can be expressed in either the millimeter or phi scale, but sorting must be expressed in the phi scale to maintain a sorting index that is useful across a wide range of grain sizes.

==Sandstone reservoirs==

==Sandstone reservoirs==

===Matrix===

===Matrix===

Clay minerals commonly occur as both matrix and cement in reservoir sandstones.<ref name=pt05r71>Hagoort, J., 1984, Measurement of relative permeability for computer modeling/reservoir simulation: Oil and Gas Journal, Feb. 20, p. 62–68.</ref> [http://dictionary.reference.com/browse/detrital Detrital] matrix can be introduced into sand during or immediately following sedimentation by depositional processes, infiltration, and [[bioturbation]]. It can occur as grain coatings, dispersed matrix, laminae, or discrete grains. [ http://dictionary.reference.com/browse/authigenic Authigenic] clay cements commonly precipitate as grain coatings, pore fillings, and grain replacements. Virtually any clay mineral can occur in any of these modes, with [[kaolinite]], [[chlorite]], [[smectite]], mixed layer illite-smectite, and [[illite]] occurring as common constituents of reservoir sandstones.

Clay minerals commonly occur as both [http://www.britannica.com/EBchecked/topic/369508/matrix matrix] and cement in reservoir sandstones.<ref name=pt05r71>Hagoort, J., 1984, Measurement of relative permeability for computer modeling/reservoir simulation: Oil and Gas Journal, Feb. 20, p. 62–68.</ref> [http://dictionary.reference.com/browse/detrital Detrital] matrix can be introduced into sand during or immediately following sedimentation by depositional processes, infiltration, and [[bioturbation]]. It can occur as grain coatings, dispersed matrix, laminae, or discrete grains. [ http://dictionary.reference.com/browse/authigenic Authigenic] clay cements commonly precipitate as grain coatings, pore fillings, and grain replacements. Virtually any clay mineral can occur in any of these modes, with [[kaolinite]], [[chlorite]], [[smectite]], mixed layer illite-smectite, and [[illite]] occurring as common constituents of reservoir sandstones.

The presence of clay minerals of any origin has both direct and indirect effects on [[reservoir quality]]. Directly, clay minerals commonly result in lowered [[permeability]] because they constrict [[Connectivity and pore throat size|pore throats]] and promote higher [http://petrowiki.org/Glossary%3AIrreducible_water_saturation irreducible water saturation]. Indirectly, clay minerals commonly influence [[Diagenesis|diagenetic]] processes that impact reservoir quality. For example, clay grain coatings in some sandstones have inhibited the nucleation of quartz overgrowths and thereby contributed to porosity preservation. However, clay grain coatings in other sandstones have promoted intergranular [[pressure solution]] and have thereby contributed to porosity destruction.

The presence of clay minerals of any origin has both direct and indirect effects on [[reservoir quality]]. Directly, clay minerals commonly result in lowered [[permeability]] because they constrict [[Connectivity and pore throat size|pore throats]] and promote higher [http://petrowiki.org/Glossary%3AIrreducible_water_saturation irreducible water saturation]. Indirectly, clay minerals commonly influence [[Diagenesis|diagenetic]] processes that impact reservoir quality. For example, clay grain coatings in some sandstones have inhibited the nucleation of quartz overgrowths and thereby contributed to porosity preservation. However, clay grain coatings in other sandstones have promoted intergranular [[pressure solution]] and have thereby contributed to porosity destruction.

==Carbonate reservoirs==

==Carbonate reservoirs==

<gallery mode=packed heights=200px widths=200px>

<gallery mode=packed heights=200px widths=200px>

thin-section-analysis_fig2.png|{{figure number|2}}Carbonate classification schemes of (a) Folk<ref name=pt05r56 /> and (b) Dunham,<ref name=pt05r50 /> both based on textures observed in hand specimen or thin section. In Folk's scheme, the black pattern represents lime mud matrix, the lined pattern represents sparry calcite cement, and the white objects represent various carbonate grains.

thin-section-analysis_fig2.png|{{figure number|2}}Carbonate classification schemes of (a) Folk<ref name=pt05r56 /> and (b) Dunham,<ref name=pt05r50 /> both based on textures observed in hand specimen or thin section. In Folk's scheme, the black pattern represents lime mud [http://www.britannica.com/EBchecked/topic/369508/matrix matrix], the lined pattern represents sparry calcite cement, and the white objects represent various carbonate grains.

Porosity_fig3.png|{{figure number|3}}

Porosity_fig3.png|{{figure number|3}}Idealized carbonate porosity system showing three basic porosity groups: fabric selective, not fabric selective, and fabric selective or not. (After Choquette and Pray.<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>

</gallery>

</gallery>

Diagenetic history of carbonate reservoir rocks is important to reconstruct because it influences the volume, size, shape, and distribution of pores. Diagenesis may involve porosity-reducing cementation, porosity-enhancing dissolution, and recrystallization, which may result in either reduction or enhancement of porosity. An important goal of carbonate petrography is to establish the sequence of such events, or paragenesis, of the reservoir. Careful reconstruction of reservoir paragenesis can provide a perspective of the porosity system at the time of hydrocarbon [[accumulation]], thereby enhancing the geologist's understanding of how reserves may be distributed relative to diagenetic facies.

Diagenetic history of carbonate reservoir rocks is important to reconstruct because it influences the volume, size, shape, and distribution of pores. Diagenesis may involve porosity-reducing cementation, porosity-enhancing dissolution, and recrystallization, which may result in either reduction or enhancement of porosity. An important goal of carbonate petrography is to establish the sequence of such events, or paragenesis, of the reservoir. Careful reconstruction of reservoir paragenesis can provide a perspective of the porosity system at the time of hydrocarbon [[accumulation]], thereby enhancing the geologist's understanding of how reserves may be distributed relative to diagenetic facies.

Documentation of the porosity system within a carbonate reservoir provides a clear understanding of the origin and three dimensional distribution of [[Pore system fundamentals|pores]]. This information is typically collected by classifying individual pores into discrete categories<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> and by evaluating the degree to which the various pore types are interconnected. (For more on carbonate porosity types, see [[Porosity#Carbonate pore systems|Table 1]] and [[:file:porosity_fig3.png|Figure 3]].)

Documentation of the porosity system within a carbonate reservoir provides a clear understanding of the origin and three dimensional distribution of [[Pore system fundamentals|pores]]. This information is typically collected by classifying individual pores into discrete categories<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> and by evaluating the degree to which the various pore types are interconnected. (For more on carbonate porosity types, see Table 1 and [[:file:porosity_fig3.png|Figure 3]].)

 

This analysis results in a conceptualization of the three-dimensional pathways that hydrocarbons must follow from their original location in the virgin reservoir to the wellbore. Knowing, for example, that porosity in a particular reservoir is selective to a specific depositional facies would allow a geologist to plan enhanced recovery by siting injection and withdrawal locations on the basis of facies distribution. In contrast, knowing that porosity is mostly not fabric selective (e.g., a combination of [[fracture]] and vuggy) would likely result in a very different plan for siting injection and withdrawal locations. Documentation of the porosity system also provides information that is fundamental to planning optimum reservoir stimulation procedures.

This analysis results in a conceptualization of the three-dimensional pathways that hydrocarbons must follow from their original location in the virgin reservoir to the wellbore. Knowing, for example, that porosity in a particular reservoir is selective to a specific depositional facies would allow a geologist to plan enhanced recovery by siting injection and withdrawal locations on the basis of facies distribution. In contrast, knowing that porosity is mostly not fabric selective (e.g., a combination of [[fracture]] and vuggy) would likely result in a very different plan for siting injection and withdrawal locations. Documentation of the porosity system also provides information that is fundamental to planning optimum reservoir stimulation procedures.

[[Category:Laboratory methods]]

[[Category:Laboratory methods]]