ABSTRACT The South Belridge field is located in western Kern County, California. One reservoir in the field, accounting for about 20% of the daily field oil production, is the Belridge diatomite member of the Reef Ridge Shale. The field is developed on a elongated anticline. Within the field, normal faulting appears in three episodes: early Pliocene large offset lystric faults, the middle Pliocene large offset Middle Belridge fault, which geologically separates the northern portion of South Belridge field from the southern portion, and late Pliocene small offset vertical faults. The small offset faults, along with the natural fracture system, are the primary permeability conduits in the Belridge diatomite reservoir. In northern South Belridge field the natural fracture system trends Ν45°Έ and is near vertical. Around section 12, T28S, R20E, MDB&M, four intervals within the Belridge diatomite are productive: the 12 Zone, upper diatomite, middle diatomite, and the lower diatomite; all of the lower Belridge diatomite north of the Middle Belridge fault lies in the opal-CT facies and is a distinct hydrocarbon reservoir. Lithologies of the three opal-A intervals vary from diatomaceous mudstone to silty diatomite. Productive zone thicknesses range from an average of 100 ft to 775 ft. Average effective porosity is 36.7% to 55.4%, average helium permeability is 1.86 md to 103 md (0.11 md to 0.56 md to brine), and average free water saturation is 55.4% to 69.0%. Formation waters vary from 25,085 ppm TDS to 40,000 ppm TDS with resistivities of 0.35 ohms to 0.17 ohms at 25° C. Oil gravities range from 22.2° API gravity to 32° API gravity. Diatom floras from wells in South Belridge field show the middle and lower diatomite to be late Mohnian to middle Delmontian and the upper diatomite and 12 Zone to be late Delmontian. The section is probably correlative to the Bitterwater Creek Shale of the southern-most Temblor Range and is time-correlative to the Sisquoc Formation diatomites of coastal California. The diagenetic transition of Belridge diatomite from opal-A to opal-CT occurs between 2000 ft and 2300 ft and is coincident with the top of the lower diatomite interval. The transition from opal-CT to quartz occurs at about 3700 ft. Formation temperatures within the Belridge Diatomite suggest that there has been 925 ft of post-opal-CT/quartz transition uplift and 300 ft of post opal-A/opal-CT transition uplift in South Belridge field. The coincidence of the opal-A/opal-CT transition with the top of the lower diatomite suggests that diagenesis preceded structural deformation. Using average compacted sediment deposition rates, the estimated time to deposit the Belridge diatomite was 1,643,400 years. Comparison of the lower Belridge diatomite sections at the north and south ends of South Belridge field suggests that the relative basinal subsidence during deposition was -0.48 ft/1000 years.

ABSTRACT Surface subsidence due to reservoir compaction during production has been observed in many large oil fields. Subsidence is most obvious in coastal and offshore fields where inundation by the sea occurs. Well known examples are Wilmington field in California and Ekofisk field in the North Sea. In South Belridge field the Belridge diatomite member of the late Miocene Reef Ridge Shale has proven prone to compaction during production. The reservoir, a high porosity, low permeability, highly compressive rock composed largely of diatomite and mudstone, is about 1000 ft thick and lies at an average depth of 1600 ft. Reservoir compaction within the Belridge diatomite due to withdrawals of oil and water in section 12, T28S, R20E, MDB&M, was noticed after casing failures in producing wells began occurring and tension cracks, enlarged by hydrocompaction after a heavy rainstorm, were observed. Surface subsidence in section 12 has been monitored since April, 1987, through the surveying of benchmark monuments. The average annualized subsidence rate during 1987 was -1.86 ft/yr, -0.92 ft/yr during 1988, and - 0.65 ft/yr during 1989; the estimated peak subsidence rate reached -7.50 ft/yr in July 1985, after l½ yrs of production from the Belridge diatomite reservoir. Since production from the Belridge diatomite reservoir commenced in February, 1984, the surface of the 160 acres producing area has subsided about 12.50 ft. This equates to an estimated reservoir compaction of 30 ft in the Belridge diatomite and an average loss of reservoir porosity of 2.4% from 55.2% to 52.8%. Injection of water for reservoir pressure maintenance in the Belridge diatomite began in June, 1987, and has been effective in mitigating subsidence and repressurizing the reservoir to near-initial pressure. An added benefit of water injection has been improved recovery of oil from the Belridge diatomite by waterflood. The operation of four other water injection projects in South Belridge Field in the Belridge diatomite reservoir suggests that reservoir compaction and surface subsidence is a common occurrence in the field.

Abstract Porosity analysis based on conventional core samples, gamma-gamma logs, and borehole gravity (BHG) surveys is presented for a Pleistocene unconsolidated sand reservoir and for Miocene diatomaceous, porcelaneous, and fractured shale reservoirs of the Monterey Formation in the South Belridge oil field and West Cat Canyon area of the Cat Canyon oil field, California. BHG surveys, the least well-known porosity method, investigate large volumes of the adjacent rock units and provide very accurate measurements of formation density as averages over vertical intervals. BHG and gamma-gamma densities were most discrepant opposite soft, diatomaceous mudstone and hard, naturally fractured, carbonate- and quartz-bearing siliceous rocks, less discrepant opposite unconsolidated sands, and generally in agreement opposite porcelaneous shale and less pervasively fractured quartz-bearing siliceous rocks. These differences resulted from less accurate compensation of gamma-gamma readings for formation damage, mudcake, drillhole enlargement, and rugosity rather than from errors in BHG densities that were very small. Core samples were used to provide grain density needed to calculate porosity from BHG and gamma-gamma densities. Grain densities of core samples from the Monterey Formation range from less than 2.2 to more than 2.7 g/cm 3 , saturated bulk densities from about 1.4 to more than 2.7 g/cm 3 , and intergranular porosities from 0 to about 65%. The ranges of BHG and gamma-gamma densities and calculated porosities were nearly as large, reflecting the mineralogic and lithologic diversity (including diagenetic phases of silica) in the Monterey Formation. Quantitative evaluation of fracture porosity by BHG survey in the West Cat Canyon field was inconclusive because insufficient core and well log data were available to determine interval averages of grain density and intergranular porosity with requisite precision in this lithologically diverse and thinly bedded reservoir. Anomalous gravity effects, normally small or insignificant, were equivalent to density corrections of as much as —0.22 g/cm 3 for the BHG survey in the South Belridge field and were evaluated with a surface gravity map and the gamma-gamma log.

Abstract California has one of the largest reserves for heavy oil in the world, second only to Venezuela. Recent declines in conventional resources and reserves during the last decade have prompted other jurisdictions to examine their prospective unconventional resources, such as heavy oil and oil sands, in a more favorable technological and economic setting. However, this has not been done universally in the United States, where thermal enhanced oil-recovery technologies (mostly used to produce heavy oil) have experienced a decline in production, concomitant with the downturn in conventional production. In California, the seep and oil-sand deposits are mostly unconsolidated sands bound together by biodegraded bitumen. Source rocks for both modern seeps and oil sands and ancient heavy-oil deposits are mainly the Miocene Monterey diatomites and equivalent diatomaceous mudstones and organic shales. In California, most of the seeps and oil sands overlie or are updip from underlying heavy-oil reservoirs. The seep and oil-sand deposits occur in areas where cap-rock integrity was compromised for the underlying heavy-oil reservoirs, breeched mainly by faults or fractures. Hydrocarbons migrated updip into basin-marginal settings or in structural areas of compromised cap rock and then pooled to form the seeps, later hardening into oil-sand deposits. Hydrocarbons accumulated in a wide variety of depositional environments from deep-sea fans, lobes, and submarine channels to fluvial-lacustrine deltas and incised valleys and every other sedimentary environment in between. This makes it difficult to identify type examples for the California accumulations, although case examples are given. In the past, steam-flood, condensed water drive, cyclic steam stimulation (CSS), and fireflood were used to produce the California heavy-oil reservoirs. Currently, significant California CSS projects underway include Belridge, Cymric, and northern Midway Sunset fields to stimulate intermediate-gravity hydrocarbons in the Monterey, Reef Ridge, and Etchegoin diatomite lithologies. Elsewhere, for example, in Canada, in-situ bitumen and extra-heavy-oil sands are commonly developed using CSS or steam-assisted gravity drainage (SAGD). Combined application of CSS along with SAGD from horizontal wells may recover bypassed pay in heavy-oil reservoirs and may be used to recover bitumen from associated oil sands, and multistage multifracing technologies may recover oil from the deeper unconventional (Monterey) source rocks. These technological developments, along with improved computing techniques (i.e., three-dimensional [3-D] geologic modeling/visualization), allow for real-time exploration and development of unconventional reservoirs. A significant effort exists in California to improve recovery from Pleistocene, Pliocene, and Miocene heavy-oil deposits; for example, at present, 70 to 80% recovery from heavy-oil steam drives is seen in Pleistocene Tulare Formation fluvial and alluvial sands. Full 3-D models anchored by extensive coring and logging programs have reaped benefits in many older oil fields (e.g., South Belridge, Midway Sunset, Cymric, Lost Hills, Kern River). Bypassed pay and new production from associated shallow oil sands and deeper source rocks may ultimately be a key to attainment of increases in secure unconventional energy reserves in North America. In the future, full integration of new technologies, along with technology sequencing, may be applied to old California oil fields for production of bypassed pay in heavy-oil fields.