Geologic controls on permeability
Permeability measurements
Six hundred and sixty seven (667) permeability measurements were completed on four cores using a pressure decay permeameter. With this instrument, measurements are made over a mm size area of core, so that the permeability of thin beds can be accurately measured. This is unlike core plug measurements, which, in thin interbeds, actually only average the permeability over several laminae (Weber, 1987). By taking many permeability measurements with the pressure decay permeameter over short core intervals, a 'continuous' permeability profile can be established. For this study, permeability measurements were made at 2" intervals along the Macii Ross and Eckhardt cores and at 6" intervals along the Vern Marshall, Moser and Sotexco cores. The following are ranges and average values of sand content (visual estimate) and permeability for the six facies:
Relation of sedimentary facies to permeability
Figure 6a illustrates the typical vertical patterns of gamma-ray response, percent sand, facies, and permeability for the Macii Ross core. The above table shows direct relations among the sand content of the six facies and their permeability. Increasing sand content is directly proportional to permeability, indicating a primary facies control on permeability. Sandiest Facies 5 (generally upper shoreface) exhibits the highest permeabilities. Permeability of these sandstones rarely exceeds 5md and is normally <2md. However even in lower shoreface strata, thin storm sandstone beds (mainly Facies 4) may exhibit permeabilities on the order of 1md. Over 500 pressure decay permeameter measurements of similar Terry Sandstone facies in the Latham Bar Trend, about 5 miles to the northeast of Hambert-Aristocrat field, also revealed a strong facies control on permeability (Al-Raisi et al., 1996).
Relation of diagenesis to reservoir quality
Permeability (and porosity) also have been affected by secondary diagenetic processes. Petrographic and scanning electron microscope (including back-scatter imaging) analyses were conducted on samples from three of the cores. The sandstones are generally fine-grained (avg. grain size is 0.1-0.15mm), well sorted, and feldspathic, with 10->30% calcite cement. Carbonate clasts, glauconite and fossil fragments are present as minor framework constituents. Thin section porosities vary up to 20% according to the amount of calcite cement and mud matrix. Quartz overgrowths also are common in those sandstones which are not carbonate-cemented. Pressure solution of quartz occurs both as grain-to-grain contacts and along discontinuous stylolites.
The majority of porosity is microporosity, with pores on the order of a few microns in diameter. Even in sandstones with 10% core plug porosities, little or no porosity is visible in thin section. According to Pittman (1988), half of the pore volume in the Terry Sandstone in nearby Spindle Field is microporosity associated mainly with ductile deformation of lithic fragments.
Structural controls
The distribution of normalized GOR's for individual wells exhibits a clear relation to compartmentalized fault blocks (Figs. 3 and 4). Based upon the values provided earlier for OGIP, OOIP and gas and oil recovered as of 1993, recovery efficiencies for gas and oil are 41% and 6-14%, respectively. These low recoveries are proably due at least in part to the high degree of structural complexity and sealing faults in the area.
Within the Denver Basin, a common observation has been the anomalous distribution of oil and gas wells producing within a given formation (i.e. an oil well might occur structurally higher than an adjacent gas well in close proximity). These anomalies, expressed by GOR's for individual wells, are a result of the complexity of faulting, and sealing-fault bounded compartments (Fig. 4).
The complex structural compartmentalization identified in Hambert-Aristocrat field may have resulted in some additional oil and/or gas in untapped parts of compartments. There may be opportunities to tap these sandstones by targeted infill, or horizontal drilling.
Stratigraphic controls
The primary facies control on matrix permeability, discussed above, undoubtedly has a big effect on production. Well perforations and production are confined solely to the blocky/thinning-upward, upper shoreface deposits (Facies 5), which are the most permeable. Since upper shoreface deposits sit upon a major unconformity (Figs. 9 and 10), regional mapping of this unconformity might lead to identification of additional pay sandstones.
There are two additional potential types of pay sandstones within the Terry Sandstone that have not generally been tested. The first type is the thin, lower shoreface sandstone beds and laminae which exhibit permeabilities on the order of 1md; they may be 'missed pay' because they appear on well logs as low resistivity-low contrast intervals (Slatt and Huffman, 1995) (Fig. 6a). The second type is the thicker sandstones that occur at the tops of lower shoreface/offshore, thickening/cleaning - upward strata (Fig. 7). These sandstones have not been perforated or cored, so permeabilities are unknown; however the fact that permeability varies proportionally with sandiness in the Terry Sandstone suggests the upper, sandiest parts of these strata in the eastern part of the area might exhibit good permeabilities.
Transgressive shales are laterally continuous toward the east (Figs. 9 and 10), and thus have the potential to be significant vertical barriers or baffles to fluid flow. These shales, which form the base of each parasequence (except parasequences A and B), provide vertical stratigraphic compartmentalization of sandstone bodies (when not faulted) at right angles to the predominant horizontal structural trend of compartmentalization.
