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Major variations in levels of [[reservoir quality]] and degrees of lateral and vertical continuity within oil and gas fields are controlled primarily by depositional factors. However, major inhomogeneities may also be produced by diagenetic alterations. These inhomogeneities in rock properties may transect or reverse trends produced by depositional controls and can significantly influence reservoir properties, including initial fluid saturations, residual saturations, waterflood sweep efficiencies, preferred directions of flow, and reactions to injected fluids. Extreme [[permeability]] stratification or the development of permeability barriers by diagenetic alteration may lead to the need to drill additional infill wells or reposition the locations of such wells, selectively perforate and inject reservoir units, manage zones on an individual basis, and revise decisions regarding suitability for thermal recovery operations.

Major variations in levels of [[reservoir quality]] and degrees of [[lateral]] and vertical continuity within oil and gas fields are controlled primarily by depositional factors. However, major inhomogeneities may also be produced by diagenetic alterations. These inhomogeneities in rock properties may transect or reverse trends produced by depositional controls and can significantly influence reservoir properties, including initial fluid saturations, residual saturations, waterflood sweep efficiencies, preferred directions of flow, and reactions to injected fluids. Extreme [[permeability]] stratification or the development of permeability barriers by diagenetic alteration may lead to the need to drill additional infill wells or reposition the locations of such wells, selectively perforate and inject reservoir units, manage zones on an individual basis, and revise decisions regarding suitability for thermal recovery operations.

A ''diagenetically complex reservoir'' is a reservoir in which the major inhomogeneities affecting fluid distribution and/or productivity are controlled primarily by diagenetic events. Diagenetic inhomogeneities are zones of reduced or enhanced [[porosity]] and/or permeability that are generated by one or a combination of the processes of cementation, compaction, replacement, dissolution, and fracturing. For a reservoir to be considered complex, the diagenetic inhomogeneities must exhibit a complex distribution that is not directly correlated with or controlled by depositional factors.

A ''diagenetically complex reservoir'' is a reservoir in which the major inhomogeneities affecting fluid distribution and/or productivity are controlled primarily by diagenetic events. Diagenetic inhomogeneities are zones of reduced or enhanced [[porosity]] and/or permeability that are generated by one or a combination of the processes of cementation, compaction, replacement, dissolution, and fracturing. For a reservoir to be considered complex, the diagenetic inhomogeneities must exhibit a complex distribution that is not directly correlated with or controlled by depositional factors.

==Diagenetic events that create reservoir heterogeneities==

==Diagenetic events that create reservoir heterogeneities==

[[file:evaluating-diagenetically-complex-reservoirs_fig1.png|thumb|300px|{{figure number|1}}Cross section in the Crane Field, Richland County, Montana, showing extreme irregularities in the development of porous dolomite zones in the Red River Formation below the C-anhydrite.<ref name=pt06r78 />]]

[[file:evaluating-diagenetically-complex-reservoirs_fig1.png|thumb|300px|{{figure number|1}}Cross section in the Crane Field, Richland County, Montana, showing extreme irregularities in the development of porous dolomite zones in the Red River Formation below the C-[[anhydrite]].<ref name=pt06r78 />]]

Diagenetic alterations are defined here as all physical and chemical alterations that affect a sediment subsequent to deposition, including tectonically produced fractures and faults. Diagenetic alterations that have been observed to generate reservoir heterogeneities having a major influence on reservoir rock properties are shown in Table 1. In sandstone reservoirs, carbonate and anhydrite cementation, clay authigenesis, secondary porosity generation, and fracturing are the most commonly reported alterations. In carbonate reservoirs, the diagenetic components most often observed are gypsum/anhydrite cementation, dolomite replacement, secondary porosity generation, and stylolitization. A cross section from Longman<ref name=pt06r78>Longman, M. W., Fertal, T. G., Glennie, J. S., 1983, [http://archives.datapages.com/data/bulletns/1982-83/data/pg/0067/0005/0700/0744.htm Origin and geometry of Red River Dolomite reservoirs, western Williston basin]: AAPG Bulletin, v. 67, p. 744–771.</ref> illustrates the complexity of porosity development in one of the few well-documented examples of a diagenetically complex reservoir ([[:file:evaluating-diagenetically-complex-reservoirs_fig1.png|Figure 1]]).

Diagenetic alterations are defined here as all physical and chemical alterations that affect a sediment subsequent to deposition, including tectonically produced fractures and faults. Diagenetic alterations that have been observed to generate reservoir heterogeneities having a major influence on reservoir rock properties are shown in Table 1. In sandstone reservoirs, carbonate and anhydrite cementation, clay authigenesis, secondary porosity generation, and fracturing are the most commonly reported alterations. In carbonate reservoirs, the diagenetic components most often observed are [[gypsum]]/anhydrite cementation, [[dolomite]] replacement, secondary porosity generation, and stylolitization. A [[cross section]] from Longman<ref name=pt06r78>Longman, M. W., T. G. Fertal, and J. S. Glennie, 1983, [http://archives.datapages.com/data/bulletns/1982-83/data/pg/0067/0005/0700/0744.htm Origin and geometry of Red River Dolomite reservoirs, western Williston basin]: AAPG Bulletin, v. 67, p. 744–771.</ref> illustrates the complexity of porosity development in one of the few well-documented examples of a diagenetically complex reservoir ([[:file:evaluating-diagenetically-complex-reservoirs_fig1.png|Figure 1]]).

{| class = "wikitable"

{| class = "wikitable"

|+ {{table number|1}}Examples of diagenetic alterations that produce major reservoir heterogeneities

|+ {{table number|1}}Examples of diagenetic alterations that produce major reservoir heterogeneities

|-

|-

! Diagenetic Component

! Diagenetic Component || Field || Reference

! Field

! Reference

|-

|-

| Cementation

| colspan=3 | Cementation

 

 

|-

|-

|   Siderite

|   Siderite

| C Unit, Kuparuk Field, Alaska

| C Unit, Kuparuk Field, Alaska

| <ref name=pt06r38>Gaynor, G. C., Scheihing, M. H., 1988, Shelf depositional environments and reservoir characteristics of the Kuparuk River Formation (Lower Cretaceous), Kuparuk field, North Slope, Alaska, in Lomando, A. J., Harris, P. M., eds., Giant oil and gas fields—A core workshop: Society of Economic Paleontologists and Mineralogists Core Workshop 12, p. 333–389.</ref>

| <ref name=pt06r38>Gaynor, G. C., and M. H. Scheihing, 1988, Shelf depositional environments and reservoir characteristics of the Kuparuk River Formation (Lower Cretaceous), Kuparuk field, North Slope, Alaska, in Lomando, A. J., Harris, P. M., eds., Giant oil and gas fields—A core workshop: Society of Economic Paleontologists and Mineralogists Core Workshop 12, p. 333–389.</ref>

|-

|-

|   Dolomite

|   Dolomite

| Oregon basin Field, Wyoming

| Oregon basin Field, Wyoming

| <ref name=pt06r91>Morgan, J. T., Cordiner, F. S., Livingston, A. R., 1977, Tensleep reservoir study, Oregon Basin field, Wyoming— reservoir characteristics: Journal of Petroleum Technology, v. 29, p. 886–896, DOI: [https://www.onepetro.org/journal-paper/SPE-6141-PA 10.2118/6141-PA].</ref>

| <ref name=pt06r91>Morgan, J. T., F. S. Cordiner, and A. R. Livingston, 1977, Tensleep reservoir study, Oregon Basin field, Wyoming— reservoir characteristics: Journal of Petroleum Technology, v. 29, p. 886–896, DOI: [https://www.onepetro.org/journal-paper/SPE-6141-PA 10.2118/6141-PA].</ref>

|-

|-

|   Anhydrite

|   Anhydrite

| Pierce and Black Hollow Fields, Colorado

| Pierce and Black Hollow Fields, Colorado

| <ref name=pt06r76>Levandowski, D. W., Kaley, M. E., Silverman, S. R., Smalley, R. G., 1973, [http://archives.datapages.com/data/bulletns/1971-73/data/pg/0057/0011/2200/2217.htm Cementation in Lyons Sandstone and its role in oil accumulation, Denver basin, Colorado]: AAPG Bulletin, v. 57, p. 2217–2244.</ref>

| <ref name=pt06r76>Levandowski, D. W., M. E. Kaley, S. R. Silverman, and R. G. Smalley, 1973, [http://archives.datapages.com/data/bulletns/1971-73/data/pg/0057/0011/2200/2217.htm Cementation in Lyons Sandstone and its role in oil accumulation, Denver basin, Colorado]: AAPG Bulletin, v. 57, p. 2217–2244.</ref>

|-

|-

|   Authigenic clays

|   Authigenic clays

| Hankensbuttel-Sud Field, Germany

| Hankensbuttel-Sud Field, Germany

| <ref name=pt06r34>Gaida, K. H., Kessel, D. G., Volz, H., Zimmerle, W. 1987, Geologic parameters of reservoir sandstones as applied to [[enhanced oil recovery]]: SPE Formation Evaluation, v. 2, p. 89–96, DOI: [https://www.onepetro.org/journal-paper/SPE-13570-PA 10.2118/13570-PA].</ref>

| <ref name=pt06r34>Gaida, K. H., D. G. Kessel, H. Volz, H., and W. Zimmerle, 1987, Geologic parameters of reservoir sandstones as applied to [[enhanced oil recovery]]: SPE Formation Evaluation, v. 2, p. 89–96, DOI: [https://www.onepetro.org/journal-paper/SPE-13570-PA 10.2118/13570-PA].</ref>

|-

|-

| Stylolitization and associated cementation

| Stylolitization and associated cementation

| <ref name=pt06r30>Dunnington, H. V., 1967, Aspects of diagenesis and shape change in stylolitic limestone reservoirs: 7th World Petroleum Congress Proceedings, v. 2, p. 339–352.</ref>

| <ref name=pt06r30>Dunnington, H. V., 1967, Aspects of diagenesis and shape change in stylolitic limestone reservoirs: 7th World Petroleum Congress Proceedings, v. 2, p. 339–352.</ref>

|-

|-

| Dissolution

| colspan = 3 | Dissolution

 

 

|-

|-

|   Carbonate

|   Carbonate

| Spindle Field, Colorado

| Spindle Field, Colorado

| <ref name=pt06r102>Porter, K. W., Weimer, R. J., 1982, [http://archives.datapages.com/data/bulletns/1982-83/data/pg/0066/0012/2500/2543.htm Diagenetic sequence related to structural history and petroleum accumulation: Spindle field, Colorado]: AAPG Bulletin, v. 66, p. 2543–2560.</ref>

| <ref name=pt06r102>Porter, K. W., and R. J. Weimer, 1982, [http://archives.datapages.com/data/bulletns/1982-83/data/pg/0066/0012/2500/2543.htm Diagenetic sequence related to structural history and petroleum accumulation: Spindle field, Colorado]: AAPG Bulletin, v. 66, p. 2543–2560.</ref>

|-

|-

|   Anhydrite

|   Anhydrite

===Stage 1. Construction of a regional geological framework===

===Stage 1. Construction of a regional geological framework===

To assist in the understanding of the depositional and diagenetic events that have created and modified the reservoir rocks, analysis of the regional geological framework can be very helpful. Elements of the regional geology most useful for this include regional thickness and lithofacies patterns, the plate tectonic history of the area, the local structural history, the history of exploration and production in the area, the burial history including major erosional and/or nondepositional events, and in particular, the thermal and pressure history of the reservoir.

To assist in the understanding of the depositional and diagenetic events that have created and modified the reservoir rocks, analysis of the regional geological framework can be very helpful. Elements of the regional geology most useful for this include regional thickness and [[lithofacies]] patterns, the plate tectonic history of the area, the local structural history, the history of exploration and production in the area, the burial history including major erosional and/or nondepositional events, and in particular, the thermal and pressure history of the reservoir.

===Stage 2. Construction of a depositional model===

===Stage 2. Construction of a depositional model===

===Step 1. Basic rock description===

===Step 1. Basic rock description===

The geologist first collects data relating to the relative abundance of diagenetic components recognizable at the magnification levels of a binocular microscope or handlens. This evaluation may be conducted simultaneously with the rock description step of depositional model construction. The most useful data are derived from slabbed full diameter cores, but recourse to cuttings and sidewall cores is necessary where such cores are not available. In addition to describing the slabbed core, horizontal core plugs used for core analysis measurements should also be described. Recent advances in the methodology of cuttings analysis involve visual aids such as cuttings comparators, low magnification (20&times;) photographs of cuttings samples, thin section photomicrographs, and scanning electron microscope (SEM) micrographs of rock chips and pore casts. These allow more extensive utilization of these samples for rock characterization.<ref name=pt06r131>Sneider, R. M., King, H. R., Hawkes, H. E., Davis, T. B., 1983, [https://www.onepetro.org/journal-paper/SPE-10072-PA Methods for detection and characterization of reservoir rock, Deep Basin gas area, western Canada]: Journal of Petroleum Technology, Sept., p. 1725–1734.</ref>

The geologist first collects data relating to the relative abundance of diagenetic components recognizable at the magnification levels of a binocular microscope or handlens. This evaluation may be conducted simultaneously with the rock description step of depositional model construction. The most useful data are derived from slabbed full diameter cores, but recourse to cuttings and sidewall cores is necessary where such cores are not available. In addition to describing the slabbed core, horizontal core plugs used for core analysis measurements should also be described. Recent advances in the methodology of cuttings analysis involve visual aids such as cuttings comparators, low magnification (20&times;) photographs of cuttings samples, thin section photomicrographs, and scanning electron microscope (SEM) micrographs of rock chips and pore casts. These allow more extensive utilization of these samples for rock characterization.<ref name=pt06r131>Sneider, R. M., H. R. King, H. E. Hawkes, and T. B. Davis, 1983, [https://www.onepetro.org/journal-paper/SPE-10072-PA Methods for detection and characterization of reservoir rock, Deep Basin gas area, western Canada]: Journal of Petroleum Technology, Sept., p. 1725–1734.</ref>

===Step 2. Quantitative analysis===

===Step 2. Quantitative analysis===

! Application

! Application

|-

|-

| ''' Primary Techniques '''

| colspan = 2 | ''' Primary Techniques '''

 

|-

|-

|   Thin section petrography

|   Thin section petrography

| Mineral types and abundances; pore types and abundances; diagenetic sequence; texture (size, sorting)

| Mineral types and abundances; pore types and abundances; diagenetic sequence; texture ([[Grain size|size]], [[Core_description#Maturity|sorting]])

|-

|-

|   X-ray diffraction

|   X-ray diffraction

| Pore network characteristics; diagenetic sequence

| Pore network characteristics; diagenetic sequence

|-

|-

| ''' Supplementary and Alternative Techniques '''

| colspan = 2 | ''' Supplementary and Alternative Techniques '''

 

|-

|-

|   Fourier transform infrared spectroscopy

|   Fourier transform infrared spectroscopy

| Recognition of subtle or hidden diagenetic features; diagenetic sequence

| Recognition of subtle or hidden diagenetic features; diagenetic sequence

|-

|-

|   Isotope geochemistry

|   Isotope [[geochemistry]]

| Interpretation of paleosalinity and paleotemperatures

| Interpretation of paleosalinity and paleotemperatures

|-

|-

|   Fluorescence microscopy

|   Fluorescence microscopy

| Recognition of depositional and diagenetic components and textures in dolomitized or recrystallized limestones; porosity estimation

| Recognition of depositional and diagenetic components and textures in dolomitized or recrystallized [[limestone]]; porosity estimation

|-

|-

|   Image analysis

|   Image analysis

[[file:evaluating-diagenetically-complex-reservoirs_fig3.png|thumb|300px|{{figure number|3}}[[Porosity]]-permeability semilog crosspiot with samples coded according to grain size, clay content, and dominant agent of cementation.]]

[[file:evaluating-diagenetically-complex-reservoirs_fig3.png|thumb|300px|{{figure number|3}}[[Porosity]]-permeability semilog crosspiot with samples coded according to grain size, clay content, and dominant agent of cementation.]]

Sample sites for petrographic analysis are best selected on the basis of low magnification rock descriptions generated in step 1 and through examination of semilog porosity-permeability cross plots ([[:file:evaluating-diagenetically-complex-reservoirs_fig3.png|Figure 3]]) with values keyed to major categories of size, sorting, matrix content, cement content, or pore type, depending on their relative importance in a particular reservoir. Samples should be selected to span a wide range of porosities and permeabilities for each major type of reservoir rock (for example, sandstones that are dolomite cemented, anhydrite cemented, quartz-overgrowth cemented, or argillaceous).

Sample sites for petrographic analysis are best selected on the basis of low magnification rock descriptions generated in step 1 and through examination of semilog porosity-permeability cross plots ([[:file:evaluating-diagenetically-complex-reservoirs_fig3.png|Figure 3]]) with values keyed to major categories of [[Grain size|size]], [[Core_description#Maturity|sorting]], matrix content, cement content, or pore type, depending on their relative importance in a particular reservoir. Samples should be selected to span a wide range of porosities and permeabilities for each major type of reservoir rock (for example, sandstones that are dolomite cemented, anhydrite cemented, [[quartz]]-overgrowth cemented, or argillaceous).

Use of plug ends from homogeneous horizontal core analysis plugs for thin section, XRD, or SEM sample preparation allows for the development of quantitative relationships between data from these analyses and data from core analysis measurements. Plugs containing significant inhomogeneities, such as laminae of distinctly different grain size or degrees of cementation, should be avoided or else erroneous variance in the data set will tend to blur what otherwise might be easily recognizable clear-cut relationships.

Use of plug ends from homogeneous horizontal core analysis plugs for thin section, XRD, or SEM sample preparation allows for the development of quantitative relationships between data from these analyses and data from core analysis measurements. Plugs containing significant inhomogeneities, such as laminae of distinctly different grain size or degrees of cementation, should be avoided or else erroneous variance in the data set will tend to blur what otherwise might be easily recognizable clear-cut relationships.

Zones having obviously low or high permeability as a result of their grain size, sorting, clay content, cement content, or extent of dissolution or fracturing, but which were not represented in the original suite of core plugs, should be sampled to evaluate their influence on flow properties. It is also important to assess the degree of vertical permeability across small scale potential permeability barriers such as stylolites, cemented zones, and healed fractures. If full diameter core analysis was conducted, a representative portion of each segment can be selected for analysis, and the porosity-permeability measurements for the whole segment can be assumed to apply to the portion sampled. Alternatively, core analysis and rock descriptive work can be conducted on plugs cut in selected segments of the full diameter core.

Zones having obviously low or high permeability as a result of their grain size, sorting, clay content, cement content, or extent of dissolution or fracturing, but which were not represented in the original suite of core plugs, should be sampled to evaluate their influence on flow properties. It is also important to assess the degree of vertical permeability across small scale potential permeability barriers such as stylolites, cemented zones, and healed fractures. If full diameter core analysis was conducted, a representative portion of each segment can be selected for analysis, and the porosity-permeability measurements for the whole segment can be assumed to apply to the portion sampled. Alternatively, core analysis and rock descriptive work can be conducted on plugs cut in selected segments of the full diameter core.

Petrographic analysis should be designed to generate quantitative data. Decisions as to which components should be measured separately in this analysis are based on several criteria. Generally, components that are relatively abundant (>10%) and whose abundance varies significantly in the interval being investigated should be measured separately. Porosity-permeability crossplots on which samples are plotted according to lithological data obtained from binocular microscope analysis may reveal relationships indicating the relative importance of certain components (Figure 3). Components that are finely crystalline, particularly diagenetic clays, may exert a major effect on permeability, even where their abundances are relatively low (3–5%).

Petrographic analysis should be designed to generate quantitative data. Decisions as to which components should be measured separately in this analysis are based on several criteria. Generally, components that are relatively abundant (>10%) and whose abundance varies significantly in the interval being investigated should be measured separately. Porosity-permeability crossplots on which samples are plotted according to lithological data obtained from binocular microscope analysis may reveal relationships indicating the relative importance of certain components ([[:file:evaluating-diagenetically-complex-reservoirs_fig3.png|Figure 3]]). Components that are finely crystalline, particularly diagenetic clays, may exert a major effect on permeability, even where their abundances are relatively low (3–5%).

Quantitative point count analysis is preferable to semiquantitative visual estimation. If such analyses are not feasible, use should be made of visual comparators. If microcrystalline components having sizes

Quantitative point count analysis is preferable to semiquantitative visual estimation. If such analyses are not feasible, use should be made of visual comparators. If microcrystalline components having sizes

===Step 4. Diagenetic profile construction===

===Step 4. Diagenetic profile construction===

Once the lithological data for all wells involved in the study have been gathered, vertical profiles of diagenetic component abundance should be prepared. Only components having a significant effect on reservoir quality should be profiled. In some instances, components measured separately but having similar overall effects on reservoir properties can be combined to form one profile.

Once the lithological data for all wells involved in the study have been gathered, vertical profiles of diagenetic component abundance should be prepared. Only components having a significant effect on reservoir quality should be profiled. In some instances, components measured separately but having similar overall effects on reservoir properties can be combined to form one profile.

| Migrating fluids are preferentially concentrated in highly permeable units or, under evaporitic conditions, in relatively fine units where capillary properties favor their retention

| Migrating fluids are preferentially concentrated in highly permeable units or, under evaporitic conditions, in relatively fine units where capillary properties favor their retention

|-

|-

| Dissolution occurs in close proximity to major or minor unconformities

| Dissolution occurs in close proximity to major or minor [[Unconformity|unconformities]]

| Invasion of fresh meteoric waters favors extensive dissolution and/or mineral alterations (e.g., kaolinitization of precursor clays or micas)

| Invasion of fresh meteoric waters favors extensive dissolution and/or mineral alterations (e.g., kaolinitization of precursor clays or micas)

|-

|-

| Dissolution occurs at crest of anticline or at updip pinchout of a reservoir unit

| Dissolution occurs at crest of anticline or at updip pinchout of a reservoir unit

| CO₂ and/or organic acids generated during thermal maturation of organics seek structural or stratigraphic highs and generate acidic conditions

| CO₂ and/or organic acids generated during [[thermal maturation]] of organics seek structural or stratigraphic highs and generate acidic conditions

|-

|-

| Increased cementation occurs below oil-water or gas-water contacts

| Increased cementation occurs below oil-water or gas-water contacts

|}

|}

The basic correlation techniques in common use include marker and sequence analysis and, where continuity is very limited, slice techniques.<ref name=pt06r18>Cant, D. J., 1984, Subsurface facies analysis, in Walker, R. G., ed., Facies Models: Geoscience Canada, Reprint Series 1, p. 297–319.</ref> Correlation of diagenetic zones is most accurate when the origins and timings of the diagenetic events creating the components of interest are well understood, the sample and well spacing are relatively small, the diagenetic zones are relatively thick, and the sequence of zones is unique.

The basic correlation techniques in common use include marker and sequence analysis and, where continuity is very limited, slice techniques.<ref name=pt06r18>Cant, D. J., 1984, Subsurface facies analysis, in R. G. Walker, ed., Facies Models: Geoscience Canada, Reprint Series 1, p. 297–319.</ref> Correlation of diagenetic zones is most accurate when the origins and timings of the diagenetic events creating the components of interest are well understood, the sample and well spacing are relatively small, the diagenetic zones are relatively thick, and the sequence of zones is unique.

The distribution of reservoir fluids or pressures at the time of discovery of the reservoir, or at subsequent intervals during field development, may indicate the presence of continuous permeability barriers and thus may help to confirm the extent of some diagenetic zones. When the basic correlation techniques prove unsatisfactory or inadequate due to a high degree of complexity or low degree of confidence, the geologist may need to resort to special engineering techniques such as pulse testing <ref name=Pierce_1977>Pierce, A. E., 1977, [https://www.onepetro.org/journal-paper/SPE-6196-PA Case history: Waterflood performance predicted by pulse testing], Journal of Petroleum Technology, v. 29, p. 914-918.</ref> or tracer studies <ref name=Wagner_1977>Wagner, O. R., 1977, [https://www.onepetro.org/journal-paper/SPE-6046-PA The use of tracers in diagnosing interwell reservoir heterogeneities: Field results], Journal of Petroleum Technology, v. 29, p. 1410-1416.</ref> (Table 4), or to probabilistic modeling <ref name=Hewett and Behrens_1988>Hewett, T. A., and R. A. Behrens, 1988, [https://www.onepetro.org/journal-paper/SPE-18326-PA Conditional simulation of reservoir heterogeneity with fractals], 63rd Annual SPE Technical Conference Proceedings, p. 645-660, SPE #18326.</ref> (see [[Integrated computer methods]]).

The distribution of reservoir fluids or pressures at the time of discovery of the reservoir, or at subsequent intervals during field development, may indicate the presence of continuous permeability barriers and thus may help to confirm the extent of some diagenetic zones. When the basic correlation techniques prove unsatisfactory or inadequate due to a high degree of complexity or low degree of confidence, the geologist may need to resort to special engineering techniques such as pulse testing <ref name=Pierce_1977>Pierce, A. E., 1977, [https://www.onepetro.org/journal-paper/SPE-6196-PA Case history: Waterflood performance predicted by pulse testing], Journal of Petroleum Technology, v. 29, p. 914-918.</ref> or tracer studies <ref name=Wagner_1977>Wagner, O. R., 1977, [https://www.onepetro.org/journal-paper/SPE-6046-PA The use of tracers in diagnosing interwell reservoir heterogeneities: Field results], Journal of Petroleum Technology, v. 29, p. 1410-1416.</ref> (Table 4), or to probabilistic modeling <ref name=Hewett and Behrens_1988>Hewett, T. A., and R. A. Behrens, 1988, [https://www.onepetro.org/journal-paper/SPE-18326-PA Conditional simulation of reservoir heterogeneity with fractals], 63rd Annual SPE Technical Conference Proceedings, p. 645-660, SPE #18326.</ref> (see [[Integrated computer methods]]).

|}

|}

Preparation of contour maps for pertinent diagenetic components may assist in the evaluation of zone continuity (see [[Subsurface maps]]). However, the merging of data from more than one diagenetic zone may lead to misinterpretations of the degree of continuity present. Contour maps should always be interpreted in combination with detailed correlation cross sections. Preparation of three-dimensional “spectragrams” may be helpful in visual correlation studies.

Preparation of [[contour]] maps for pertinent diagenetic components may assist in the evaluation of zone continuity (see [[Subsurface maps]]). However, the merging of data from more than one diagenetic zone may lead to misinterpretations of the degree of continuity present. Contour maps should always be interpreted in combination with detailed correlation [[cross section]]s. Preparation of three-dimensional “spectragrams” may be helpful in visual correlation studies.

===Stage 4. Preparation of an integrated geological model===

===Stage 4. Preparation of an integrated geological model===

Following generation of the separate depositional and diagenetic models, data from these models must be merged to form an integrated geological model. To do this, the geologist must examine the two independent models and extract those factors that constitute the major controls on porosity, permeability, and hydrocarbon saturation. It may be useful to perform statistical analysis on the data using techniques such as correlation coefficient calculations, univariate regression, and cluster analysis, or multivariate techniques such as discriminant analysis and stepwise regression (see [[Integrated computer methods]]).

Following generation of the separate depositional and diagenetic models, data from these models must be merged to form an integrated geological model. To do this, the geologist must examine the two independent models and extract those factors that constitute the major controls on porosity, permeability, and hydrocarbon saturation. It may be useful to perform statistical analysis on the data using techniques such as [[Correlation and regression analysis|correlation coefficient]] calculations, [[Correlation and regression analysis|univariate regression]], and cluster analysis, or multivariate techniques such as discriminant analysis and stepwise regression (see [[Integrated computer methods]]).

In some fields, it may be necessary to prepare separate structural and formation fluid models in addition to depositional and diagenetic models (Figure 2). In most reservoirs, however, structural and formation fluid factors are not the major controls on fluid flow behavior, and the heterogeneities observed can be incorporated into the diagenetic model.

In some fields, it may be necessary to prepare separate structural and formation fluid models in addition to depositional and diagenetic models (Figure 2). In most reservoirs, however, structural and formation fluid factors are not the major controls on fluid flow behavior, and the heterogeneities observed can be incorporated into the diagenetic model.

Zonation may be facilitated by establishing criteria by which major categories of reservoir rock types present can be distinguished. Semilog crossplots of porosity and permeability keyed to texture, matrix content, and diagenetic component content are very useful. Through examination of these plots, the geologist can quickly separate samples into natural groupings ([[:file:evaluating-diagenetically-complex-reservoirs_fig3.png|Figure 3]]). Because permeability directly reflects fluid flow capacity, it is the major parameter used to designate reservoir rock categories. Because porosity is commonly a major control on permeability, it generally exhibits a positive correlation with that variable. Attempts to create hierarchies of permeability heterogeneity based strictly on depositional criteria<ref name=Lewis_1988>Lewis, J. J. M., 1988, [https://www.onepetro.org/conference-paper/SPE-18153-MS Outcrop-derived quantitative models of permeability heterogeneity for genetically different sand bodies]: 63rd Annual SPE Technical Conference Proceedings, p.449-463, SPE #18153</ref>  should be avoided in reservoirs where diagenetic alterations are major controls on permeability heterogeneity. If natural groupings are not present, it may be necessary to set arbitrary group boundaries, such as porosity or permeability cutoffs.

Zonation may be facilitated by establishing criteria by which major categories of reservoir rock types present can be distinguished. Semilog crossplots of porosity and permeability keyed to texture, matrix content, and diagenetic component content are very useful. Through examination of these plots, the geologist can quickly separate samples into natural groupings ([[:file:evaluating-diagenetically-complex-reservoirs_fig3.png|Figure 3]]). Because permeability directly reflects fluid flow capacity, it is the major parameter used to designate reservoir rock categories. Because porosity is commonly a major control on permeability, it generally exhibits a positive correlation with that variable. Attempts to create hierarchies of permeability heterogeneity based strictly on depositional criteria<ref name=Lewis_1988>Lewis, J. J. M., 1988, [https://www.onepetro.org/conference-paper/SPE-18153-MS Outcrop-derived quantitative models of permeability heterogeneity for genetically different sand bodies]: 63rd Annual SPE Technical Conference Proceedings, p.449-463, SPE #18153</ref>  should be avoided in reservoirs where diagenetic alterations are major controls on permeability heterogeneity. If natural groupings are not present, it may be necessary to set arbitrary group boundaries, such as porosity or permeability cutoffs.

Estimation of the lateral distribution of zones is then guided by relationships developed in the integrated geological model and documented in the form of maps and cross sections.

Estimation of the lateral distribution of zones is then guided by relationships developed in the integrated geological model and documented in the form of maps and [[cross section]]s.

===Stage 6. Applications studies===

===Stage 6. Applications studies===

Depending on the objectives of the study being conducted, the geologist needs to generate additional maps, cross sections, fence diagrams, or simulation models. For the purposes of reserve estimation, net pay maps are needed (see [[Effective pay determination]]). If the major controls on net pay distribution are diagenetic in nature, contouring of net pay maps should be guided by trends present on contour maps of major diagenetic components. Average porosity maps should also be “guided” in this same fashion. Where simulation of fluid flow behavior is the object of the study, the geologist must assist in the preparation of a three-dimensional simulation model.

Depending on the objectives of the study being conducted, the geologist needs to generate additional maps, [[cross section]]s, fence diagrams, or simulation models. For the purposes of reserve estimation, net pay maps are needed (see [[Effective pay determination]]). If the major controls on net pay distribution are diagenetic in nature, [[contour]]ing of net pay maps should be guided by trends present on contour maps of major diagenetic components. Average porosity maps should also be “guided” in this same fashion. Where simulation of fluid flow behavior is the object of the study, the geologist must assist in the preparation of a three-dimensional simulation model.

===Stage 7. Model testing and revision===

===Stage 7. Model testing and revision===

Where economics dictate, it may be necessary to test the accuracy of the models developed. This can include testing by history matching of pressures, production rates, and GOR values for segments of the model or full scale testing of the complete model<ref name=pt06r155>Weber, K. J., Klootwijk, P. H., Knoieczek, J., van der Vlugt, W. R., 1978, Simulation of water injection in a barrier-bar- type, oil-rim reservoir in Nigeria: Journal of Petroleum Technology, v. 30, p. 1555–1565, DOI: [https://www.onepetro.org/journal-paper/SPE-6702-PA 10.2118/6702-PA].</ref> (see [[Product histories]] and [[Conducting a reservoir simulation study: an overview]]). Testing can also involve drilling additional wells, conducting special engineering tests (pulse or tracer), and collecting geological data on additional samples. Revisions may also be required as additional wells, particularly infill wells, are drilled in the field.

Where [[economics]] dictate, it may be necessary to test the accuracy of the models developed. This can include testing by history matching of pressures, production rates, and GOR values for segments of the model or full scale testing of the complete model<ref name=pt06r155>Weber, K. J., P. H. Klootwijk, J. Knoieczek, and W. R. van der Vlugt, 1978, Simulation of water injection in a barrier-bar- type, oil-rim reservoir in Nigeria: Journal of Petroleum Technology, v. 30, p. 1555–1565, DOI: [https://www.onepetro.org/journal-paper/SPE-6702-PA 10.2118/6702-PA].</ref> (see [[Product histories]] and [[Conducting a reservoir simulation study: an overview]]). Testing can also involve drilling additional wells, conducting special engineering tests (pulse or tracer), and collecting geological data on additional samples. Revisions may also be required as additional wells, particularly infill wells, are drilled in the field.

==See also==

==See also==

* [[Introduction to geological methods]]

* [[Introduction to geological methods]]

* [[Flow units for reservoir characterization]]

* [[Flow units for reservoir characterization]]

* [[Effective pay determination]]

* [[Effective pay determination]]

* [[Multivariate data analysis]]

* [[Cross section]]

* [[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]]

* [[Reservoir quality]]

* [[Reservoir quality]]

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

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

* [[Evaluating fractured reservoirs]]

* [[Evaluating fractured reservoirs]]

* [[Evaluating stratigraphically complex fields]]

* [[Evaluating stratigraphically complex fields]]

* [[Statistics overview]]

* [[Carbonate diagenesis]]

==References==

==References==

[[Category:Geological methods]]

[[Category:Geological methods]]