Changes

! Characteristics

! Characteristics

|-

|-

| Sandstones

| colspan = 2 align=center | Sandstones

|-

|-

|   Primary intergranular

| Primary intergranular

| Interstitial void space between framework grains

| Interstitial void space between framework grains

|-

|-

|   Dissolution or vug

| Dissolution or vug

| Partial or complete dissolution of framework grains or cement

| Partial or complete dissolution of framework grains or cement

|-

|-

|   Micropores

| Micropores

| Small pores mainly between detrital or authigenic clays; can also occur within grains (e.g., microporous chert)

| Small pores mainly between detrital or authigenic clays; can also occur within grains (e.g., microporous [[chert]])

|-

|-

|   Fracture

| [[Fracture]]

| Breakage due to earth stresses

| Breakage due to earth stresses

|-

|-

| Carbonates

| colspan = 2 align=center | Carbonates

|-

|-

|   Interparticle

| Interparticle

| Pores between particles or grains

| Pores between particles or grains

|-

|-

|   Intraparticle

| Intraparticle

| Pores within individual particles or grains

| Pores within individual particles or grains

|-

|-

|   Intercrystal

| Intercrystal

| Pores between crystals

| Pores between crystals

|-

|-

|   Moldic

| Moldic

| Pores formed by dissolution of an individual grain or crystal in the rock

| Pores formed by dissolution of an individual grain or crystal in the rock

|-

|-

|   Fenestral

| Fenestral

| Primary pores larger than grain-supported interstices

| Primary pores larger than grain-supported interstices

|-

|-

|   Fracture

| [[Fracture]]

| Formed by a planar break in the rock

| Formed by a planar break in the rock

|-

|-

|   Vug

| Vug

| Large pores formed by indiscriminate dissolution of cements and grains

| Large pores formed by indiscriminate dissolution of cements and grains

|}

|}

===Environment of deposition===

===Environment of deposition===

The initial pore network of newly deposited sediments and the quality of shallow buried reservoirs are generally determined by the environment of deposition (see [[Lithofacies and environmental analysis of clastic depositional systems]]). This dictates the grain characteristics, which in turn control porosity and permeability. In clastic rocks, these characteristics include grain size and sorting, sphericity, angularity, packing, and the abundance of matrix materials. The best reservoir quality rocks are well-sorted, have well-rounded grains, and contain no matrix material.

The initial pore network of newly deposited sediments and the quality of shallow buried reservoirs are generally determined by the environment of deposition (see [[Lithofacies and environmental analysis of clastic depositional systems]]). This dictates the grain characteristics, which in turn control porosity and permeability. In clastic rocks, these characteristics include [[grain size]] and [[Core_description#Maturity|sorting]], sphericity, angularity, packing, and the abundance of matrix materials. The best reservoir quality rocks are well-sorted, have well-rounded grains, and contain no matrix material.

Sedimentary structures affect initial reservoir quality by imparting a preferential flow pattern in the reservoir. Planar bedding, laminations, or other stratification features can create stratified planar flow, especially if permeability barriers such as clay partings, finer-grained laminae, or graded beds are present. Slump structures may reduce permeability by creating a tortuous flow path, or may increase permeability (and porosity) by causing a looser grain packing and by producing small faults. Bioturbation typically decreases reservoir quality by mixing adjacent sands and clays, introducing the clay into the interstices among the sand grains.

Sedimentary structures affect initial reservoir quality by imparting a preferential flow pattern in the reservoir. Planar bedding, laminations, or other stratification features can create stratified planar flow, especially if permeability barriers such as clay partings, finer-grained laminae, or graded beds are present. Slump structures may reduce permeability by creating a tortuous flow path, or may increase permeability (and porosity) by causing a looser grain packing and by producing small faults. [[Bioturbation]] typically decreases reservoir quality by mixing adjacent sands and clays, introducing the clay into the interstices among the sand grains.

===Diagenesis===

===Diagenesis===

===Compaction===

===Compaction===

Compaction reduces the porosity and permeability of a rock by causing the following: (1) grain rotation and rearrangement into a tighter packing configuration, (2) plastic deformation of ductile grains that flow into adjacent pores and pore throats, (3) fracturing and crushing of brittle grains, and (4) pressure solution in the form of grain suturing and stylolitization.<ref name=pt06r84>McBride, E. F., 1984, [http://archives.datapages.com/data/bulletns/1984-85/data/pg/0068/0004/0500/0505.htm Compaction in sandstones—influence on reservoir quality]: AAPG Bulletin, v. 68, p. 505.</ref> Rocks that contain mechanically labile grains, such as clay clasts, altered rock fragments, or delicate fossils, are likely to experience a reduction in porosity and permeability as the ductile grains plastically flow into adjacent pore spaces. Brittle grains will fracture, shatter, or in the case of some fossils and porous grains, collapse. A rock that consists of a framework of strong minerals, such as quartz, tends to undergo only minor porosity and permeability reduction during compaction due to grain rotation and rearrangement into a tighter packing configuration.

Compaction reduces the porosity and permeability of a rock by causing the following: (1) grain rotation and rearrangement into a tighter packing configuration, (2) plastic [[deformation]] of [[Ductility|ductile]] grains that flow into adjacent pores and pore throats, (3) [[Fracture|fracturing]] and crushing of [[Brittleness|brittle]] grains, and (4) pressure solution in the form of grain suturing and stylolitization.<ref name=pt06r84>McBride, E. F., 1984, [http://archives.datapages.com/data/bulletns/1984-85/data/pg/0068/0004/0500/0505.htm Compaction in sandstones—influence on reservoir quality]: AAPG Bulletin, v. 68, p. 505.</ref> Rocks that contain mechanically labile grains, such as clay clasts, altered rock fragments, or delicate fossils, are likely to experience a reduction in porosity and permeability as the ductile grains plastically flow into adjacent pore spaces. Brittle grains will fracture, shatter, or in the case of some fossils and porous grains, collapse. A rock that consists of a framework of strong minerals, such as [[quartz]], tends to undergo only minor porosity and permeability reduction during compaction due to grain rotation and rearrangement into a tighter packing configuration.

===Cementation===

===Cementation===

|+ {{table number|2}}Common cements of sandstones and carbonates

|+ {{table number|2}}Common cements of sandstones and carbonates

|-

|-

! Cement

! Cement || Common Crystal Form

! Common Crystal Form

|-

|-

| Quartz

| [[Quartz]] || Syntaxial overgrowth, prismatic

| Syntaxial overgrowth, prismatic

|-

|-

| Calcite

| Calcite || Fibrous, bladed, granular, blocky, poikilotopic, syntaxial rim

| Fibrous, bladed, granular, blocky, poikilotopic, syntaxial rim

|-

|-

| Dolomite

| [[Dolomite]] || Rhombohedral, blocky, granular

| Rhombohedral, blocky, granular

|-

|-

| Anhydrite

| [[Anhydrite]] || Blocky, bladed

| Blocky, bladed

|-

|-

| Gypsum

| [[Gypsum]] || Blocky, bladed, prismatic

| Blocky, bladed, prismatic

|-

|-

| Feldspar

| Feldspar || Syntaxial overgrowth, prismatic

| Syntaxial overgrowth, prismatic

|-

|-

| Siderite

| Siderite || Granular, blocky, bladed

| Granular, blocky, bladed

|-

|-

| Zeolites

| Zeolites || Platy, bladed, fibrous, prismatic, blocky

| Platy, bladed, fibrous, prismatic, blocky

|-

|-

| Kaolinite

| Kaolinite || Platy

| Platy

|-

|-

| lllite

| lllite || Fibrous

| Fibrous

|-

|-

| Chlorite

| Chlorite || Platy

| Platy

|-

|-

| Smectite

| Smectite || Crenulate

| Crenulate

|}

|}

===Recrystallization===

===Recrystallization===

Recrystallization of carbonates and the alteration of grains and cements to clays can have a significant impact on reservoir quality in sandstones and carbonates. Dolomitization of limestones or calcite cement in sandstones typically increases porosity and permeability. Similarly, clay replacement may increase overall porosity of the rock; however, the pores associated with clay minerals tend to be micropores that contain irreducible water. Also, delicate clay flakes may become mobile with flowing pore fluids and migrate to, and clog, pore throats.

Recrystallization of carbonates and the alteration of grains and cements to clays can have a significant impact on reservoir quality in sandstones and carbonates. Dolomitization of limestones or calcite cement in sandstones typically increases porosity and permeability. Similarly, clay replacement may increase overall porosity of the rock; however, the pores associated with clay minerals tend to be micropores that contain [http://petrowiki.org/Glossary%3AIrreducible_water_saturation irreducible water]. Also, delicate clay flakes may become mobile with flowing pore fluids and migrate to, and clog, pore throats.

===Structural deformation===

===Structural deformation===

Fracturing and brecciation associated with folds, faults, and diapirs generally increase the reservoir quality of well-indurated rocks (see [[Evaluating fractured reservoirs]]). Fracture porosity is typically low, usually providing only about 1% porosity; however, fractures in large reservoirs may hold considerable reserves. Fracture permeability may be as high as tens of darcies and is directional in nature. Conversely, fractures filled by mineralization or with gouge may produce a permeability barrier in the direction perpendicular to the fracture. Brecciation along fracture or fault zones may occur due to shearing or dissolution and collapse. Except where mineralization has occurred in the breccia, brecciation can increase both porosity and permeability considerably. Closely spaced sealing faults can significantly compartmentalize a reservoir.

[[Fracture|Fracturing]] and [[breccia]]tion associated with folds, faults, and [[diapirs]] generally increase the reservoir quality of well-indurated rocks (see [[Evaluating fractured reservoirs]]). [[Fracture]] porosity is typically low, usually providing only about 1% porosity; however, fractures in large reservoirs may hold considerable reserves. Fracture permeability may be as high as tens of darcies and is directional in nature. Conversely, fractures filled by mineralization or with gouge may produce a permeability barrier in the direction perpendicular to the fracture. Brecciation along fracture or fault zones may occur due to shearing or dissolution and collapse. Except where mineralization has occurred in the breccia, brecciation can increase both porosity and permeability considerably. Closely spaced sealing faults can significantly compartmentalize a reservoir.

===[[Wettability]]===

===Wettability===

Wettability in an oil reservoir controls reservoir quality by affecting the amount of water production. When the reservoir rock is oil-wet, water is located in the central portion of the pores and will flow through the pore system with the oil. Conversely, in a water-wet reservoir, the water is restricted to the perimeter of the pores and will not flow through the pore system until much of the oil has been removed. In addition, the irreducible water saturations of oil-wet reservoirs tend to be much lower than those of water-wet reservoirs.

[[Wettability]] in an oil reservoir controls reservoir quality by affecting the amount of water production. When the reservoir rock is oil-wet, water is located in the central portion of the pores and will flow through the pore system with the oil. Conversely, in a water-wet reservoir, the water is restricted to the perimeter of the pores and will not flow through the pore system until much of the oil has been removed. In addition, the irreducible water saturations of oil-wet reservoirs tend to be much lower than those of water-wet reservoirs.

===[[Capillary pressure]]===

===Capillary pressure===

The [[capillary pressure]] of a reservoir affects the magnitude and distribution of water saturation and thus the hydrocarbon volume in a given reservoir area [[Leverett, 1941]]{{citation needed}}. The capillary pressure is a function of the capillary radius, the interfacial tension, and the contact angle between the water and the solid (see [[Capillary pressure]]). In a reservoir, zones with larger pores and pore throats have lower capillary pressure, lower irreducible water saturation, and higher hydrocarbon pore volume.

The [[capillary pressure]] of a reservoir affects the magnitude and distribution of water saturation and thus the hydrocarbon volume in a given reservoir area [[Leverett, 1941]]{{citation needed}}. The capillary pressure is a function of the capillary radius, the interfacial tension, and the contact angle between the water and the solid (see [[Capillary pressure]]). In a reservoir, zones with larger pores and pore throats have lower capillary pressure, lower irreducible water saturation, and higher hydrocarbon pore volume.

===Mesoscopic techniques===

===Mesoscopic techniques===

Core analysis measurements performed on representative core samples can more accurately assess reservoir quality<ref name=pt06r64>Keelan, D. K., 1972, A critical review of core analysis techniques: Journal of Canadian Petroleum Technology, v. 2, p. 42–55.</ref> and heterogeneities. Core analysis porosities are typically determined using one of three techniques: summation of fluids, resaturation, and Boyle's Law. Permeability on core samples is determined using one of two methods: steady-state or unsteady-state. Air (gas) permeability measurements are typically measured using a steady-state technique. The unsteady-state technique monitors pressure changes, flow rates, and fluid changes as a function of time to determine permeability [[Jones, 1982]]{{citation needed}}. The unsteady-state method should be used to determine the air permeability for samples of low permeability to obtain the most accurate values. Liquid permeability measurements can be determined by either the steady-state or the unsteady-state method (see [[Permeability]]).

[[Overview of routine core analysis|Core analysis]] measurements performed on representative core samples can more accurately assess reservoir quality<ref name=pt06r64>Keelan, D. K., 1972, A critical review of core analysis techniques: Journal of Canadian Petroleum Technology, v. 2, p. 42–55.</ref> and heterogeneities. Core analysis porosities are typically determined using one of three techniques: summation of fluids, resaturation, and Boyle's Law. Permeability on core samples is determined using one of two methods: steady-state or unsteady-state. Air (gas) permeability measurements are typically measured using a steady-state technique. The unsteady-state technique monitors pressure changes, flow rates, and fluid changes as a function of time to determine permeability [[Jones, 1982]]{{citation needed}}. The unsteady-state method should be used to determine the air permeability for samples of low permeability to obtain the most accurate values. Liquid permeability measurements can be determined by either the steady-state or the unsteady-state method (see [[Permeability]]).

Capillary pressure can also be measured in the laboratory on core samples.<ref name=pt06r149>Wardlaw, N. C., 1976, [http://archives.datapages.com/data/bulletns/1974-76/data/pg/0060/0002/0200/0245.htm Pore geometry of carbonate rocks as revealed by pore casts and capillary pressure]: AAPG Bulletin, v. 60, p. 245–257.</ref> Various techniques are used to determine fluid saturations in the sample at various pressures so that a saturation profile at different pressures is created, which characterizes the irreducible water saturation and hydrocarbon pore volume of the rock.

Capillary pressure can also be measured in the laboratory on core samples.<ref name=pt06r149>Wardlaw, N. C., 1976, [http://archives.datapages.com/data/bulletns/1974-76/data/pg/0060/0002/0200/0245.htm Pore geometry of carbonate rocks as revealed by pore casts and capillary pressure]: AAPG Bulletin, v. 60, p. 245–257.</ref> Various techniques are used to determine fluid saturations in the sample at various pressures so that a saturation profile at different pressures is created, which characterizes the irreducible water saturation and hydrocarbon pore volume of the rock.

===Microscopic techniques===

===Microscopic techniques===

[[file:reservoir-quality_fig1.png|thumb|{{figure number|1}}Binary petrographic image of sandstone. Dark areas are pores and light areas are grains or cement.]]

[[file:reservoir-quality_fig1.png|300px|thumb|{{figure number|1}}Binary petrographic image of sandstone. Dark areas are pores and light areas are grains or cement.]]

Microscopic techniques used to assess reservoir quality include [[thin section analysis]], petrographic image analysis, scanning electron microscopy, and X-ray diffraction (see [[SEM, XRD, CL, and XF methods]]). Through thin section analysis, the pore types and distribution, the extent of reservoir enhancement or degradation by diagenesis, and the influence of depositional textures on reservoir quality can be determined (see [[Thin section analysis]]).

Microscopic techniques used to assess reservoir quality include [[thin section analysis]], petrographic image analysis, scanning electron microscopy, and X-ray diffraction (see [[SEM, XRD, CL, and XF methods]]). Through thin section analysis, the pore types and distribution, the extent of reservoir enhancement or degradation by diagenesis, and the influence of depositional textures on reservoir quality can be determined (see [[Thin section analysis]]).

* [[Introduction to geological methods]]

* [[Introduction to geological methods]]

* [[Lithofacies and environmental analysis of clastic depositional systems]]

* [[Lithofacies and environmental analysis of clastic depositional systems]]

* [[Flow units for reservoir characterization]]

* [[Flow units for reservoir characterization]]

* [[Geological cross sections]]

* [[Geological cross sections]]

* [[Evaluating structurally complex reservoirs]]

* [[Evaluating structurally complex reservoirs]]

* [[Conversion of well log data to subsurface stratigraphic and structural information]]

* [[Conversion of well log data to subsurface stratigraphic and structural information]]

* [[Evaluating tight gas reservoirs]]

* [[Evaluating tight gas reservoirs]]

* [[Carbonate reservoir models: facies, diagenesis, and flow characterization]]

* [[Carbonate reservoir models: facies, diagenesis, and flow characterization]]

* [[Fluid contacts]]

* [[Fluid contacts]]

* [[Evaluating stratigraphically complex fields]]

* [[Evaluating stratigraphically complex fields]]

* [[Evaluating diagenetically complex reservoirs]]

* [[Evaluating diagenetically complex reservoirs]]

==References==

==References==

[[Category:Geological methods]]

[[Category:Geological methods]]