Reservoir quality

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Development Geology Reference Manual
Series Methods in Exploration
Part Geological methods
Chapter Reservoir quality
Author S. P. Grier, D. M. Marschall
Link Web page
Store AAPG Store

The quality of a reservoir is defined by its hydrocarbon storage capacity and deliverability. The hydrocarbon storage capacity is characterized by the effective porosity and the size of the reservoir, whereas the deliverability is a function of the permeability. Effective porosity is the volume percentage of interconnected pores in a rock. The remaining space in the rock is occupied by the framework or matrix of the rock and, if present, nonconnected pore space. Common porosity types in sandstone and carbonate rocks are listed in Table 1 (also see Porosity).

Table 1 Porosity types
Type Characteristics
Primary intergranular Interstitial void space between framework grains
Dissolution or vug Partial or complete dissolution of framework grains or cement
Micropores Small pores mainly between detrital or authigenic clays; can also occur within grains (e.g., microporous chert)
Fracture Breakage due to earth stresses
Interparticle Pores between particles or grains
Intraparticle Pores within individual particles or grains
Intercrystal Pores between crystals
Moldic Pores formed by dissolution of an individual grain or crystal in the rock
Fenestral Primary pores larger than grain-supported interstices
Fracture Formed by a planar break in the rock
Vug Large pores formed by indiscriminate dissolution of cements and grains

The permeability of a rock is a measure of the rock's ability to transmit fluid (see Permeability). Permeability, measured in darcies, is a function of the size, shape, and distribution of the pore channels in the rock, the type and number of fluids present, the fluid flow rate, the length and cross-sectional area of the rock, and the pressure differential across the length of flow.

At least within clastic rocks, there is generally a direct relationship between porosity and permeability (see Geological heterogeneities). The exact relationship varies with formation and rock type; however, increased porosity is typically accompanied by increased permeability.

Controls on reservoir quality

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.

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.


During and following burial, diagenetic events will modify the original pore network of reservoir rocks (see Evaluating diagenetically complex reservoirs). Four main diagenetic mechanisms affect reservoir quality: compaction, cementation, dissolution, and recrystallization. These mechanisms are controlled by the detrital composition of the rock, burial depth, burial time, burial temperature, pore fluids, and pore fluid pressure.


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.[1] 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, the filling of original pore space by cements, may occur early or late in the diagenetic history of a rock.[2][3] Table 2 lists some common cement types. Precipitation of authigenic minerals usually reduces reservoir quality; however, early formation of some authigenic minerals can preserve the original porosity by protecting the rock from later degradation by compaction or cementation.[4]

Table 2 Common cements of sandstones and carbonates
Cement Common Crystal Form
Quartz Syntaxial overgrowth, prismatic
Calcite Fibrous, bladed, granular, blocky, poikilotopic, syntaxial rim
Dolomite Rhombohedral, blocky, granular
Anhydrite Blocky, bladed
Gypsum Blocky, bladed, prismatic
Feldspar Syntaxial overgrowth, prismatic
Siderite Granular, blocky, bladed
Zeolites Platy, bladed, fibrous, prismatic, blocky
Kaolinite Platy
lllite Fibrous
Chlorite Platy
Smectite Crenulate


Dissolution of less chemically stable minerals in sandstones and carbonates can sometimes significantly increase both the rock porosity and the permeability.[5] Dissolution tends to be especially important in carbonates that are buried to shallow depths and sandstones that are deeply buried.


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.

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.


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

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.

Methods of assessing reservoir quality

Numerous methods exist for assessing reservoir quality, ranging in scale from the macroscopic to the microscopic (see Evaluating diagenetically complex reservoirs).

Macroscopic techniques

Modern three-dimensional seismic data[6] can sometimes assist in predicting reservoir quality away from well control. Careful processing of seismic data allows a conversion of the seismic reflection amplitudes to estimates of acoustic impedance. Because lithology, porosity, and fluid saturations affect the acoustic impedance of a rock, a relationship can then be established between the seismic estimates of impedance and the rock properties determined from the logs or in the laboratory. (For information on comparing seismic data to rock properties, see Seismic inversion.)

Wireline logs can be classified into three different groups based on the information they provide: (1) lithology indicators—gamma ray, sonic, density, and neutron logs, (2) porosity logs—sonic, density, and neutron logs, and (3) fluid saturation logs—resistivity logs.[7] (For more on the information that wireline logs can provide, see Standard interpretation.)

In addition to lithology, porosity, and fluid saturations, permeability sometimes can be inferred from log responses or a combination of log responses. The spontaneous potential log is most often used as a qualitative indicator of the permeability of a formation. (For more on wireline log response to reservoir properties, see Quick-look lithology from logs.)

Another macroscopic technique used to determine reservoir quality is drill stem testing (DSTdrill stem test) or formation testing. A drill stem test is generally performed after the well has been conditioned by sealing the zone(s) of interest and allowing the production of fluids (see Drill stem testing). The fluids are tested for hydrocarbon content and the pressures and flow rates are measured. The permeability can be inferred from the pressures measured over time, and the productive capability of the formation is determined from the types of fluid produced and the flow rates.

Mesoscopic techniques

Core analysis measurements performed on representative core samples can more accurately assess reservoir quality[8] 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.[9] 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

Figure 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).

Another microscopic method of assessing reservoir quality is through the use of scanning electron microscopy (SEM) with energy-dispersive X-ray. The SEM allows examination of a reservoir rock at very high magnifications with an excellent depth of field so that the pore network and clay minerals within the pores can be viewed. Energy-dispersive X-ray analysis provides an elemental analysis of the grains, cements, and clays identified by the SEM and is used to aid in determining the mineralogy. Such analysis is extremely important in evaluating the potential for formation damage by introduction of potentially reactive stimulation fluids.

Petrographic image analysis[10] is a relatively new technique that provides porosity and permeability values and capillary pressure curves for sandstone samples that are not suitable for conventional core analysis, such as cuttings, percussion sidewall cores, and unconsolidated core samples. Image analysis measures key two-dimensional geometrical characteristics of the pore network in thin section using a research-grade petrographic microscope coupled with an image analysis system. The system generates a binary image representing porosity and rock material from thin section views of undamaged portions of the sample (Figure 1). From this image, pore area, diameter, perimeter, length, width, and aspect ratio can be analyzed and related to the three-dimensional porosity, permeability, and capillary pressure values that have been measured on conventional core samples.

See also


  1. McBride, E. F., 1984, Compaction in sandstones—influence on reservoir quality: AAPG Bulletin, v. 68, p. 505.
  2. Scholle, P. A., Schluger, P. R., eds., 1979, Aspects of Diagenesis: SEPM Special Publication 26, 443 p.
  3. McDonald, D. A., Surdam, R. C., eds., 1984, Clastic Diagenesis: AAPG Memoir 37, 434 p.
  4. Wilson, M. D., Pittman, E. D., 1977, Authigenic clays in sandstones—recognition and influence on reservoir properties and paleoenvironmental analysis: Journal of Sedimentary Petrology, v. 47, p. 3–31.
  5. Schmidt, V., McDonald, D. A., 1980, Secondary Reservoir Porosity in the Course of Sandstone Diagenesis: AAPG Continuing Education Course Note Series No. 12, 125 p.
  6. Brown, A. R., 1986 Interpretation of three-dimensional seismic data: AAPG Memoir 42, 194 p.
  7. Asquith, G., Gibson, C. 1982, Basic well log analysis for geologists: AAPG Methods in Exploration Series 3, 216 p.
  8. Keelan, D. K., 1972, A critical review of core analysis techniques: Journal of Canadian Petroleum Technology, v. 2, p. 42–55.
  9. Wardlaw, N. C., 1976, Pore geometry of carbonate rocks as revealed by pore casts and capillary pressure: AAPG Bulletin, v. 60, p. 245–257.
  10. Gerard, R. E., C. A. Philipson, F. M. Ballentine, and D. M. Marschall, 1992, Petrographic image analysis—an alternate method for determining petrophysical properties, in I. Palaz and S. Sengupta, eds., Automated Pattern Analysis in Petroleum Exploration: New York, Springer-Verlag, p. 249-263.

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