Changes

==Tools and methods==

==Tools and methods==

The extremely low permeability of tight gas reservoirs severely restricts the ability of gas to migrate appreciable distances. Consequently, the most important geological characteristic of this type of reservoir is the nature and distribution of [[porosity]] and permeability (Table 1). The most common reason for the minimal permeabilities is the occlusion of interstitial pore throats by detrital or authigenic clays or cement (see [[Rock-Water interactions: formation damage]]). Thus, a proper geological evaluation of tight gas reservoirs requires a multidisciplinary approach to assess the depositional and diagenetic controls on [[reservoir quality]] and heterogeneity.

The extremely low permeability of tight gas reservoirs severely restricts the ability of gas to migrate appreciable distances. Consequently, the most important geological characteristic of this type of reservoir is the nature and distribution of [[porosity]] and permeability (Table 1). The most common reason for the minimal permeabilities is the occlusion of interstitial pore throats by detrital or authigenic clays or cement (see [[Rock-Water interactions: formation damage]]). Thus, a proper geological evaluation of tight gas reservoirs requires a multidisciplinary approach to assess the depositional and diagenetic controls on [[reservoir quality]] and heterogeneity.

===Facies determinations===

===Facies determinations===

Since most tight gas reservoirs in North America are of detrital origin (shale, siltstone, and sandstone), primary processes of deposition, inferred from the examination of sedimentary characteristics in core, can have a strong impact on preserved porosity and permeability trends. An example of a sedimentological description and environmental interpretation of cored facies from a tight gas reservoir is shown in [[:file:evaluating-tight-gas-reservoirs_fig1.png|Figure 1]].

Since most tight gas reservoirs in North America are of detrital origin (shale, siltstone, and sandstone), primary processes of deposition, inferred from the examination of sedimentary characteristics in core, can have a strong impact on preserved porosity and permeability trends. An example of a sedimentological description and environmental interpretation of cored facies from a tight gas reservoir is shown in [[:file:evaluating-tight-gas-reservoirs_fig1.png|Figure 1]].

===Core to log correlations===

===Core to log correlations===

Documenting characteristic log signatures for reservoir facies can provide a valuable tool for constructing regional cross sections, determining facies relationships, and extrapolating reservoir geometries in areas of minimal or nonexistent core control (see [[Quick-look lithology from logs]]). Commonly, the gamma ray log provides the most distinctive log signature for individual facies (Figure 1). For low permeability gas reservoirs, crossover of the compensated neutron-formation density logs is the most reliable well log for indicating gas-saturated and porous intervals and for determining which intervals in the reservoir should be perforated and/or stimulated by hydraulic fracturing.

 

Documenting characteristic log signatures for reservoir facies can provide a valuable tool for constructing regional cross sections, determining facies relationships, and extrapolating reservoir geometries in areas of minimal or nonexistent core control (see [[Quick-look lithology from logs]]). Commonly, the gamma ray log provides the most distinctive log signature for individual facies ([[:file:evaluating-tight-gas-reservoirs_fig1.png|Figure 1]]). For low permeability gas reservoirs, crossover of the compensated neutron-formation density logs is the most reliable well log for indicating gas-saturated and porous intervals and for determining which intervals in the reservoir should be perforated and/or stimulated by hydraulic fracturing.

===Stratigraphic cross sections===

===Stratigraphic cross sections===

Lateral variability in facies relationships, and thus reservoir continuity and heterogeneity, are best determined from the construction of stratigraphic cross sections (see [[Geological cross sections]]). An example of a cross section through part of a tight gas reservoir is shown in Figure 2. Facies interpretations are based on [[core description]]s and extrapolation of log signatures for each cored facies to adjacent uncored wells. Distributary channel sandstones form the reservoirs, and bay, marsh, and crevasse splay mudstones form the seal. The lack of production in the two wells to the east is attributed to the pinching out of these mudstone facies and substantiates its importance as a stratigraphic seal. Note the laterally discontinuous nature of individual reservoir sandstone beds as depicted in the cross section.

Lateral variability in facies relationships, and thus reservoir continuity and heterogeneity, are best determined from the construction of stratigraphic cross sections (see [[Geological cross sections]]). An example of a cross section through part of a tight gas reservoir is shown in [[:file:evaluating-tight-gas-reservoirs_fig2.png|Figure 2]]. Facies interpretations are based on [[core description]]s and extrapolation of log signatures for each cored facies to adjacent uncored wells. Distributary channel sandstones form the reservoirs, and bay, marsh, and crevasse splay mudstones form the seal. The lack of production in the two wells to the east is attributed to the pinching out of these mudstone facies and substantiates its importance as a stratigraphic seal. Note the laterally discontinuous nature of individual reservoir sandstone beds as depicted in the cross section.

 

===Petrophysical properties of reservoir facies===

===Petrophysical properties of reservoir facies===

Average core analysis values for porosity, permeability, oil, gas, and water saturation should be determined for each facies recognized to identify those facies of greater and lesser reservoir quality (Figure 3a). In gas-bearing sandstones, very low values of porosity and permeability are acceptable and expected. While the average air permeability values rarely exceed 1.0 md (millidarcy) for tight gas reservoirs, a significant difference in permeability values often occurs between facies (Figure 3b).

[[file:evaluating-tight-gas-reservoirs_fig3.png|left|thumb|{{figure number|3}}Histograms showing (a) average porosity values and (b) average permeability values for cored tight gas reservoir facies. (From <ref name=pt06r93 />.)]]

[[file:evaluating-tight-gas-reservoirs_fig3.png|thumb|{{figure number|3}}Histograms showing (a) average porosity values and (b) average permeability values for cored tight gas reservoir facies. (From <ref name=pt06r93 />.)]]

Average core analysis values for porosity, permeability, oil, gas, and water saturation should be determined for each facies recognized to identify those facies of greater and lesser reservoir quality ([[:file:evaluating-tight-gas-reservoirs_fig3.png|Figure 3a]]). In gas-bearing sandstones, very low values of porosity and permeability are acceptable and expected. While the average air permeability values rarely exceed 1.0 md (millidarcy) for tight gas reservoirs, a significant difference in permeability values often occurs between facies ([[:file:evaluating-tight-gas-reservoirs_fig3.png|Figure 3b]]).

Anomalously high values from core analysis measurements may also identify zones of fracture porosity and permeability in tight gas reservoirs (see [[Evaluating fractured reservoirs]]). However, one must be careful in interpreting such results because erroneously high measurements can also be produced by bypassing or artificial fracturing of core samples during analysis. Checks should be made to ensure that a sufficient number of samples have been analyzed for each facies or unit and that permeability and porosity values correspond to observed lithologies in core.

Anomalously high values from core analysis measurements may also identify zones of fracture porosity and permeability in tight gas reservoirs (see [[Evaluating fractured reservoirs]]). However, one must be careful in interpreting such results because erroneously high measurements can also be produced by bypassing or artificial fracturing of core samples during analysis. Checks should be made to ensure that a sufficient number of samples have been analyzed for each facies or unit and that permeability and porosity values correspond to observed lithologies in core.