Changes

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 pore throats and promote higher irreducible water saturation. Indirectly, clay minerals commonly influence 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 pore throats and promote higher irreducible water saturation. Indirectly, clay minerals commonly influence 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.

Clay minerals commonly pose potential formation damage problems. Fines migration can occur regardless of clay mineral composition. Clay swelling in response to certain completion or stimulation fluids locally occurs if smectites or mixed layer clays are present. The presence of iron-bearing clays may cause precipitation of iron hydroxide, which commonly damages permeability, as a by-product of acid stimulation if proper chelating agents are not used. (For more on formation damage, see the chapter on “Rock-Water Reactions: Formation Damage” in Part 5.)

Clay minerals commonly pose potential formation damage problems. Fines migration can occur regardless of clay mineral composition. Clay swelling in response to certain completion or stimulation fluids locally occurs if smectites or mixed layer clays are present. The presence of iron-bearing clays may cause precipitation of iron hydroxide, which commonly damages permeability, as a by-product of acid stimulation if proper chelating agents are not used. (For more on formation damage, see the chapter on “Rock-Water Reactions: Formation Damage” in Part 5.)

===[[Porosity]]===

===[[Porosity]]===

During point counting, porosity is typically categorized into one of four categories: (1) primary intergranular porosity, (2) microporosity associated with clay minerals or other very fine mineral constituents, (3) dissolution porosity, and (4) fracture porosity<ref name=pt05r127>Pittman, E. D., 1979, Porosity, diagenesis, and productive capability of sandstone reservoirs, in Scholle, P. A., Schluger, P. R., eds., Aspects of Diagenesis: Society Economic Paleontologists and Mineralogists Special Publication 26, p. 159–173.</ref>. Proportions of the first three porosity types can be conveniently displayed on a ternary diagram (Figure 1), which summarizes relative reservoir quality and some of the positive and negative attributes commonly associated with the three porosity types. (For more details on porosity types, see the chapter on “Porosity” in Part 5.)

During point counting, porosity is typically categorized into one of four categories: (1) primary intergranular porosity, (2) microporosity associated with clay minerals or other very fine mineral constituents, (3) dissolution porosity, and (4) fracture porosity<ref name=pt05r127>Pittman, E. D., 1979, Porosity, diagenesis, and productive capability of sandstone reservoirs, in Scholle, P. A., Schluger, P. R., eds., Aspects of Diagenesis: Society Economic Paleontologists and Mineralogists Special Publication 26, p. 159–173.</ref>. Proportions of the first three porosity types can be conveniently displayed on a ternary diagram ([[:file:thin-section-analysis_fig1.png|Figure 1]]), which summarizes relative reservoir quality and some of the positive and negative attributes commonly associated with the three porosity types. (For more details on porosity types, see [[Porosity]])

[[file:thin-section-analysis_fig1.png|thumb|{{figure number|1}}Ternary diagram of nonfracture porosity types in sandstones summarizing the influence of porosity type on reservoir quality. (Modified after <ref name=pt05r127 />.)]]

[[file:thin-section-analysis_fig2.png|thumb|{{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.]]

==Carbonate reservoirs==

==Carbonate reservoirs==

Petrographic analysis of carbonate reservoirs provides description of depositional facies, reconstruction of diagenetic history, and documentation of the porosity system.

Petrographic analysis of carbonate reservoirs provides description of depositional facies, reconstruction of diagenetic history, and documentation of the porosity system.

Depositional facies of reservoir rocks can be inferred on a microscale if diagenesis has not obliterated original carbonate textures. Petrographers recognize a spectrum of original textures that range from mostly carbonate mud (low energy environments) through mostly sand-sized or larger carbonate grains (high energy environments). In fact, this spectrum of textures is the basis for the two most commonly used carbonate classifications, those of Folk<ref name=pt05r56>Folk, R. L., 1959, Practical petrographic classification of limestones: AAPG Bulletin, v. 43, p. 1–38.</ref> and Dunham<ref name=pt05r50>Dunham, R. J., 1962, Classification of carbonate rocks according to depositional texture, in Ham, W. E., ed., Classification of Carbonate Rocks: AAPG Memoir 1, p. 108–121.</ref>, summarized in Figure 2. In certain instances, variation in reservoir quality (porosity and permeability) can be explained on the basis of textural variation related to distribution of depositional facies within the carbonate reservoir.

Depositional facies of reservoir rocks can be inferred on a microscale if diagenesis has not obliterated original carbonate textures. Petrographers recognize a spectrum of original textures that range from mostly carbonate mud (low energy environments) through mostly sand-sized or larger carbonate grains (high energy environments). In fact, this spectrum of textures is the basis for the two most commonly used carbonate classifications, those of Folk<ref name=pt05r56>Folk, R. L., 1959, Practical petrographic classification of limestones: AAPG Bulletin, v. 43, p. 1–38.</ref> and Dunham<ref name=pt05r50>Dunham, R. J., 1962, Classification of carbonate rocks according to depositional texture, in Ham, W. E., ed., Classification of Carbonate Rocks: AAPG Memoir 1, p. 108–121.</ref>, summarized in [[:file:thin-section-analysis_fig2.png|Figure 2]]. In certain instances, variation in reservoir quality (porosity and permeability) can be explained on the basis of textural variation related to distribution of depositional facies within the carbonate reservoir.

 

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.