Abstract The upper Miocene Stevens Sandstone is a prolific oil producer in the San Joaquin Basin of California. Stevens production is mainly from deep water sandstones which were most commonly deposited by turbidite flows. Although the Stevens has produced for forty years, a resurgence of activity by Tenneco, Gulf, Texaco, and Arco, as well as many independents, has greatly increased the reserves in the Stevens in recent years. Production from the Stevens interval is primarily from turbidite sandstones deposited as part of submarine fan complexes in fan channels and fan lobes and from sands deposited in topographically lower areas on the sea floor. Fractured siliceous shales of the Stevens interval also contribute to production. These shales, also of deep water origin, are laterally-equivalent or slightly younger than the Stevens sandstones. These shales were deposited on the fringes of the fan, on the basin plain, or as drapes on bathymetrically-high areas of the sea floor. Along the eastern margin of the basin where deposition occurred on a relatively-undeformed homoclinal surface, patterns of turbidite sedimentation and facies associations generally conform to the Mutti and Ricci Lucchi or other submarine fan models. However, in the central and western portions of the basin, fan models seem to be inappropriate. Observed relationships between Facies Associations, sandbody geometries and submarine fan subenvironments often appear anomalous when facies interpreted from cores are compared with relationships described by some currently popular fan models. Such anomalous relationships were observed in cores from several fields producing from the Stevens Sandstone. To explain these inconsistencies, an “on-lap” model and a “confinement” model are proposed for some of the observed depositional patterns of the Upper Miocene Stevens Sandstones in the San Joaquin Basin. Cores from Paloma, North Coles Levee, Rio Viejo and Tule Elk Fields demonstrate the generally thin bedded nature of Stevens tur-bidites deposited in the western portion of the basin. Fining and thinning upward cycles, as well as coarsening and thickening upward cycles, are observed in the cores. Upward variation in the frequency of interbedded shales within the overall sandstone cycles is demonstrated to be the major cuase of apparent “fining” or “coarsening” upward as observed on logs. Complete and incomplete Bouma sequences and relatively thin massive-appearing to graded sandstones are observed in the cores. Amalgamation of sandstones is common. At Tule Elk Field a significant thickness of trough-cross-bedded sandstones show the effect of deep water traction type currents, a phenomena that has rarely been documented. Superimposed on the facies analyses are the effects of basin bottom topography. An “on-lap” model is defined to describe turbi-dite deposits which lap onto and stack vertically against contemporaneously rising anticlinal structures. Internally these sand-bodies exhibit distinct sedimentation cycles and facies associations characteristic of fan progradation. Externally these sandbodies pinch out crestward, may or may not be lobate- or fan-shaped, and tend to be abnormally thick. The Paloma Field is an example of sediments that fit the “on-lap” model. A “confinement” model is defined to describe deposits of turbidity flows which are confined to bathymetric lows between adjacent (en echelon) anticlines. These deposits, which accumulated in synclinal lows, tend to have an external channel-like morphology but do not necessarily exhibit facies associations commonly ascribed to channels in fan models. Deep-water sediments from Yowlumne Field, Tule Elk Field, and some of the production Elk Hills Field are best explained by the “confinement” model.

Abstract The deepest onshore horizontal well in California is the ARCO-DOE 91X-3, which was drilled at Yowlumne field in the San Joaquin Basin, California, to exploit the thinning, distal margin of a fan-shaped, layered turbidite complex. Yowlumne is a giant oil field that has produced more than 17.2 million m 3 (108 million bbl) of oil from the Stevens Sandstone, a clastic facies of the Miocene Monterey Shale source rock. Most Yowlumne production is from the Yowlumne Sandstone, a layered, fan-shaped, prograding Stevens turbidite complex deposited in a slope-basin setting. Well-log, seismic, and pressure data indicate seven depositional lobes with both left-stepping and basinward-stepping geometries. To facilitate cost-effective exploitation of remaining field reserves, a 3-D model of the reservoir architecture was constructed from log-derived petrophysical data, constrained by core analyses. This model indicates concentration of channel and lobe facies along the axis and west (left) margin of the Yowlumne fan to result in average net/gross sandstone ratios of 80%, porosity (Ø) of 16%, and liquid permeability (K liquid ) of 10–20 md. By contrast, more abundant levee and distal margin facies along the east margin result in shale-bounded reservoir layers with higher clay contents and lower net/gross sandstone ratio (65%), porosity (12%), and permeability (2 md). Thus, the distal fan margin is not an attractive place to drill for oil. However, modeling indicates that most remaining field reserves exist along the east fan margin. Although a waterflood during the last 20 years will enable recovery of 45% of original oil in place along the fan axis, about 480,000 m 3 (3 million bbl) of oil trapped at the thinning fan margins will be abandoned with the current well distribution. The ARCO 91X3 was a Department of Energy-funded well to test economic recovery of this bypassed oil by utilizing a high-angle deviated well with three hydraulic fracture stimulations to provide connectivity between reservoir layers, thereby providing the same productive capacity as three vertical wells. The well was drilled along strike to a measured depth of 4360 m (14,300 ft) to tangentially penetrate at angles up to 85° as much as 600 m (2000 ft) of the distal margin of the Yowlumne fan. Because of drilling and completion difficulties, the proposed multiple fracture stimulations were not attempted. Nonetheless, use of highly deviated to horizontal wells with multiple fracture stimulations remains an economically viable option for maximizing productivity from the thinning, distal margins of layered, low-permeability turbidite reservoirs.

Abstract Yowlumne is a giant oil field in the San Joaquin basin, California that has produced over 100 MMBO from a low-permeability (10-100 md), fan-shaped turbidite complex with left- and basinward-stepping geometries deposited in an active-margin basin. The Yowlumne and other “deep water,” upper Miocene sandstones in the San Joaquin basin make up a clastic facies of the Monterey Shale called the “Stevens” sandstone, which has contributed more than 15% of 12 BBO produced here since 1864. The Yowlumne reservoir is a prograding turbidite complex of seven lobes deposited on the basin margin during Miocene orogeny. Although the fan is lens-shaped, it does not significantly incise underlying strata. Apparently, deposition resulted from confinement of prograding lobes, about 2 km wide by 4 km long, between a faulted paleohigh on the west (left) side of the fan, and another high, associated with overbank deposition and possibly differential compaction, on the east (right) side. Basinward-stepping compartments in the reservoir represent deposition during decreasing accommodation, and high sediment flux, whereas left-stepping compartments reflect the influence of Coriolis forces. More abundant shale-bearing levee facies characterize the east (right) margin of the fan, whereas sand-rich lobe facies characterize the west. Therefore, reservoir quality decreases from the fan axis eastward towards the fan margin. Cost-effective exploitation of bypassed oil trapped against the thinning margin is facilitated by 3D-computer modeling to effectively locate highly deviated to horizontal wells, and design completions that maximize productivity from the layered, low permeability turbidite reservoir that characterizes the distal fan margin.

ABSTRACT In this paper, we analyze source, seal, trap, reservoir, timing, and migration to explain petroleum occurrence and exploration prospectiveness in the southernmost San Joaquin basin. The factors that control oil occurrence and field size vary greatly among the three productive geologic domains in the area. We term these three domains the Foothills, the Basin, and the Upturn. The Upturn lies in between the structurally high Foothills and the structurally low Basin, and is a near-vertical panel of highly faulted strata with 5,000’-15,000’ of structural relief. Monterey Formation source rock in the southernmost San Joaquin basin has reached oil maturity mainly within the Basin. Oil generation there began about 4 Ma and continues today. However, the onset of anticlinal growth in the Basin at about 1 Ma dramatically changed oil migration pathways and delivery destinations. Prior to 1 Ma, oil migrating out of the Basin was delivered broadly across the entire east-west extent of the Upturn and Foothills. After 1 Ma, migration pathways became more complex and more east to west, resulting in very large oil pools in the southwestern San Joaquin basin. In the Basin, abundant oil has been generated, seal is ubiquitous, and early-formed traps are present. However, reservoir presence, reservoir quality, and the availability of migration pathways limit the amount of commercial production. Commercial oil is found mainly within gently dipping upper Miocene Reef Ridge and Stevens submarine-fan sand stratigraphic traps. The upper Miocene is sand poor, so sand mapping is critical. Fortunately, modern 3-D seismic combined with well data allow reliable mapping of sand fairways and fan facies. Little oil production exists above the upper Miocene because the high-angle faults that facilitate migration from the lower Monterey hydrocarbon kitchen do not penetrate high enough to allow charging of shallower strata. Little commercial production exists below the upper Miocene because depths are too great for sands to retain reservoir quality. The Upturn is well charged with oil, has abundant migration pathways, and contains numerous fault traps, many of which formed before oil migration began. However, it is sparsely drilled and difficult to image seismically, so exploration for the fault-footwall traps that are the typical targets is risky. Perhaps surprisingly given the active dense faulting, the presence of several oil fields in the Upturn indicates that seals can be effective. As in the Basin, sand is generally sparse, so sand presence is an important play control. The eastern Upturn toward the Tejon embayment is sandy, but the western and central parts generally are not. Where sand is present, reservoir quality is adequate even in lower Monterey and older strata that are tight in the Basin because burial of these strata was never deep. Most Foothills fields are located in Quaternary surface anticlines. However, central and eastern Foothills anticlines are undercharged because their present-day fetch areas are small and their trap timing is late: most of the anticlines are extremely young, so were not available to capture early-generated oil migrating from the Basin. To date more oil has been produced in the eastern than in the western Foothills, partly because sand content increases eastward.

ABSTRACT Study of Aqueduct field has revealed insights about the seismic signature, reservoir distribution, and possibly oil charging of Stevens fans. These relationships are especially well revealed at Aqueduct because of the field’s structural simplicity and the availability of a diverse data set including high-quality 3-D seismic. Aqueduct field is a stratigraphic trap formed by pinchout of the upper Monterey Stevens submarine-fan reservoir sand combined with a gentle structural bowing. The sand is time equivalent to updip interfan pelagic siliceous shale that provides the seal. Aqueduct field lies within the Aqueduct fan system, one of several southernmost San Joaquin basin upper Stevens fan systems deposited within the Monterey. The fan system is expressed on seismic profiles, cross sections, and interval isopach maps as a thick, which is typical for Stevens fans. The distal part of the system is fan shaped, but the proximal part is narrow and linear. Aqueduct field lies in the proximal part of the fan, where the lateral pinchouts of sand from the fan axis to flanking shale are abrupt. In spite of the linear proximal fan shape, we interpret that erosion at the base of the fan was minor. In the distal fan, sand passes gradationally from the fan axis to siliceous shale in the interfan area. Seismic, geochemical, and oil-water contact data suggest that Aqueduct field probably is compartmentalized into at least three separate oil pools. Sands at Aqueduct field may have been deposited as a series of prograding shingled fan lobes. If so, we interpret that the shales between these shingled lobes isolated the pools from one another. Aqueduct field has smaller reserves than nearby fields that are otherwise similar and is remarkably unfaulted. The small size may be due to charge limitation. At Aqueduct field, the absence of faults to facilitate vertical oil migration from the lower Monterey hydrocarbon kitchen upward into the reservoir may limit field size.