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file:Mth14ch02f04.jpg|{{figure number|4}}Seismic line and cross section A-A' showing left-stepping geometries and cross-sectional lens shape of the Yowlumne fan. The line and section transect the fan from west to east, perpendicular to the direction of sediment transport.
file:Mth14ch02f04.jpg|{{figure number|4}}Seismic line and cross section A-A' showing left-stepping geometries and cross-sectional lens shape of the Yowlumne fan. The line and section transect the fan from west to east, perpendicular to the direction of sediment transport.
file:Mth14ch02f05.jpg|{{figure number|5}} Map with cross sections X-Z and Y-Z showing basinward-stepping geometries exhibited by lobe-shaped sand bodies that make up the Yowlumne Sandstone. Note 660 m (2100 ft) of structural relief between oil-water contacts in the lobes of Units A and B.
file:Mth14ch02f05.jpg|{{figure number|5}} Map with cross sections X-Z and Y-Z showing basinward-stepping geometries exhibited by lobe-shaped sand bodies that make up the Yowlumne Sandstone. Note 660 m (2100 ft) of structural relief between oil-water contacts in the lobes of Units A and B.
file:Mth14ch02f06.jpg|{{figure number|6}} Maps showing fieldwide variations in the average reservoir pressure of the Yowlumne Sandstone. The variations indicate that Units A and B may represent separate compartments that are not in fluid communication with one another.
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Well-log correlations and 3-D seismic data indicate downlap within the fan, with basinward progradation to the north and lateral progradation to the west ([[:file:Mth14ch02f04.jpg|Figure 4]], [[:file:Mth14ch02f05.jpg|Figure 5]]). In other words, lobe-shaped, shale-bounded reservoir layers in Unit B step to the left when facing basinward, in the direction of sediment transport (Jessup and Kamerling;<ref name=Jessupandkamerling_1991>Jessup, D. D., and M. Kamerling, 1991, [http://www.searchanddiscovery.com/abstracts/html/1991/pacific/abstracts/0368b.htm Depositional style of the Yowlumne sands, Yowlumne oil field, southern San Joaquin Basin, California] (abs.): AAPG Bulletin, v. 75, p. 368.</ref> Clark et al.<ref name=Clarketal_1996b>Clark, M. S., J. Melvin, and M. Kamerling, 1996, [http://www.searchanddiscovery.com/abstracts/html/1996/annual/abstracts/0027.htm Growth patterns of a Miocene turbidite complex in an active-margin basin, Yowlumne field, San Joaquin Basin, California] (abs.): AAPG Annual Convention Official Program, San Diego, 1996, v. 5, p. A27.</ref>). Thus, the basal productive layer (sand E) is thickest on the right (east) side of the fan, whereas the top layer (sand A) is thickest on the left (west).
Well-log correlations and 3-D seismic data indicate downlap within the fan, with basinward progradation to the north and lateral progradation to the west ([[:file:Mth14ch02f04.jpg|Figure 4]], [[:file:Mth14ch02f05.jpg|Figure 5]]). In other words, lobe-shaped, shale-bounded reservoir layers in Unit B step to the left when facing basinward, in the direction of sediment transport (Jessup and Kamerling;<ref name=Jessupandkamerling_1991>Jessup, D. D., and M. Kamerling, 1991, [http://www.searchanddiscovery.com/abstracts/html/1991/pacific/abstracts/0368b.htm Depositional style of the Yowlumne sands, Yowlumne oil field, southern San Joaquin Basin, California] (abs.): AAPG Bulletin, v. 75, p. 368.</ref> Clark et al.<ref name=Clarketal_1996b>Clark, M. S., J. Melvin, and M. Kamerling, 1996, [http://www.searchanddiscovery.com/abstracts/html/1996/annual/abstracts/0027.htm Growth patterns of a Miocene turbidite complex in an active-margin basin, Yowlumne field, San Joaquin Basin, California] (abs.): AAPG Annual Convention Official Program, San Diego, 1996, v. 5, p. A27.</ref>). Thus, the basal productive layer (sand E) is thickest on the right (east) side of the fan, whereas the top layer (sand A) is thickest on the left (west).
Variations in reservoir pressures and injection of radioactive tracers indicate weak compartmentalization of the reservoir, which results in separate permeability pathways along which fluids flow at different rates (Metz and Whitworth, their figure 9;<ref name=Metzandwhitworth_1984>Metz,</ref> Berg and Royo<ref name=Bergandroyo_1990>Berg,</ref>). Most likely, these pathways represent different flow units that, for the most part, are in pressure communication over geologic time. Consequently, these compartments, which correlate to the shale-bounded, lobe-shaped reservoir layers already discussed, develop the same [[oil-water contact]] over thousands of years yet acquire slightly different pressures as the field is rapidly produced over tens of years.
Variations in reservoir pressures and injection of radioactive tracers indicate weak compartmentalization of the reservoir, which results in separate permeability pathways along which fluids flow at different rates (Metz and Whitworth, their figure 9;<ref name=Metzandwhitworth_1984 /> Berg and Royo<ref name=Bergandroyo_1990>Berg, R. R., and G. R. Royo, 1990, Channel-fill turbidite reservoir, Yowlumne field, California, ''in'' J. H. Barwin, J. G. MacPherson, and J. R. Studlick, eds., Sandstone petroleum reservoirs: Casebooks in earth science: New York, Springer-Verlag, p. 467-487.</ref>). Most likely, these pathways represent different flow units that, for the most part, are in pressure communication over geologic time. Consequently, these compartments, which correlate to the shale-bounded, lobe-shaped reservoir layers already discussed, develop the same oil-water contact over thousands of years yet acquire slightly different pressures as the field is rapidly produced over tens of years.
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file:Mth14ch02f07.jpg|{{figure number|7}}Gross-sandstone isopach map of the Yowlumne sandstone showing separate depocenter thicks in Units A and B. The different depocenters indicate that the units may represent separate depositional accumulations, an interpretation consistent with Units A and B representing separate compartments with different oil-water contacts.
file:Mth14ch02f08.jpg|{{figure number|8}}Star plots of peak-height ratios from gas-liquid chromatograms of two representative oils in the field. These plots are consistent with plots of another six oils from the field that were also analyzed in the study, and they indicate that oils in Unit B are compositionally distinct from those in Unit A. Because variations at the D, K, M, N, and P axes are significant enough to indicate that oils in Units A and B are not in fluid communication with each other, Units A and B appear to represent separate reservoir compartments (Suhas Talukdar, Core Laboratories, Inc., written communication, 1998).
file:Mth14ch02f09.jpg|{{figure number|9}}Permeability profile from a 30-ft cored interval in the Yowlumne 91X-3 horizontal well revealing greater permeabilities in Bouma A layers relative to Bouma B and C layers, and slumped intervals. These variations result in the creation of reservoir permeability pathways that parallel bedding.
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Several observations demonstrate that compartmentalization in the field also exists on larger scales.
* The reservoir in Yowlumne Unit A has, over time, consistently exhibited reservoir pressures that differ from those in the same interval in Unit B ([[:file:Mth14ch02f06.jpg|Figure 6]]).
* Gross sandstone isopach maps indicate separate northern (Unit B) and southern (Unit A) depocenters (loci of thickening), which appear to represent different depositional accumulations ([[:file:Mth14ch02f07.jpg|Figure 7]]).
* Because sandstones in Unit B have more quartz, less clay, and higher original porosity than the equivalent sandstones in Unit A, different depositional histories are indicated (Whelan<ref name=Whelan_1984>Whelan, H. T. M., 1984, Geostatistical estimation of the spatial distributions of porosity and percent clay in a Miocene Stevens turbidite reservoir: Yowlumne field, California: Master's thesis, Stanford University, Stanford, California, 126 p.</ref>).
* The oil-water contact in Unit B is 660 m (2180 ft) structurally lower than the contact in Unit A ([[:file:Mth14ch02f05.jpg|Figure 5]]).
* Although a few studies interpret a single oil-water contact steeply tilted to 5° (480ft/mi, 90.9 m/km), a large density difference of 0.154 g/cc between the oils (32° API) and formation waters (TDS [total dissolved solids] of 22,000 ppm) is more consistent with a lower-gradient oil-water contact. More likely, the large density contrast results in buoyant oils unlikely to support a contact tilted more than 1° (100 ft/mi, 18.9 m/km), even in the presence of a strong water drive.
* Comparisons of oil analyses from different parts of the field indicate that Units A and B are not in fluid communication ([[:file:Mth14ch02f08.jpg|Figure 8]]).