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American Association of Petroleum Geologists, Energy Minerals Division Table 9. California Oil Fields Produced by Thermal Recovery Methods Field Midway-Sunset Kern River South Belridge Cymric Lost Hills San Ardo Coalinga Kern Front Poso Creek McKittrick Edison Placerita North Antelope Hills 2011 Oil, MMB 30.564 26.804 25.165 13.089 11.232 6.835 5.603 2.829 2.781 1.832 0.840 0.710 0.380 2011 GOR °API 165 11–14 0 13 414 13–14 374 11–14 710 12.7–13.9 193 11–12 38 9–13 0 13–14.8 4 13 1,202 10–12 5 14 0 13 0 14 Oil Viscosity, cp 1000–10000 4000 1500–4000 1000–2000 1500–4000 1000–3000 2000–28000 1500 2800 13000–51000 2000 10000 1400 Oil Temp., °F 85–130 90 95 95–105 75–82 125–130 84–105 80–95 110 83 90 90 80 The fields are arranged by 2011 total oil yield (in million barrels, MMB); the volume of associated gas is indicated by the gas–oil ratio (GOR) in units of SCF gas/barrels oil. The characteristic oil gravity, oil viscosity, and reservoir or in situ oil temperature of the fields are also shown. 1 Barrel (oil) = 0.159 m3; °F = °C99/5 + 32. Data from California Division of Oil, Gas, and Geothermal Resources and Koottungal (2012). the Monterey Formation. However, the South Bel- ridge field produces from diagenetically altered, highly fractured diatomite. The Coalinga field pro- duces from sandstones in the Temblor Formation underlying the Monterey Formation; the source rock is the Middle Eocene Kreyenhagen Formation unconformably overlain by the Temblor Formation. The larger thermal oil fields (Table 9) have experienced oil production declines in the 5-year period 2007–2011 on the order of 11.3% (Kern River) to 28.8% (Cymric). Smaller fields have had little or no declines. The young (1952) San Ardo field immediately west of the San Joaquin basin (Fig. 20) has actually doubled production in this period. A small portion of the supergiant Wilming- ton field in the Los Angeles basin was produced by steam flood using two pairs of parallel horizontal injector and producer wells. The project was stopped because of surface subsidence problems. With the exception of this successful pilot, air quality issues associated with steam generation have limited the expansion of thermal recovery methods in the Los Angeles basin. In addition to the heavy oil accumulations that are being produced, California has numerous shal- low bitumen deposits and seeps that are not cur- rently exploited. The total resource is estimated to be as large as 4.7 billion BBLs (0.74 billion m3) (Kuuskraa et al. 1987). Five of the six largest tar sand deposits are in the onshore Santa Maria basin (central Coastal zone in Fig. 20), covering a total area of over 60 square miles (155 km2). In general, the deposits are in the Sisquoc Formation, which overlies and is a seal to the oil- generating Monterey Formation. An additional ma- jor deposit is in the onshore Ventura basin (extreme southeast of the Coastal zone). Minor tar sand deposits and surface seeps are scattered throughout the oil-producing areas of California normally over- lying or updip from known oil fields. During the past decade, oil production in Cali- fornia has steadily declined (U.S. Energy Informa- tion Administration 2012e). The rate of decline is being slowed, and may be reversed, through the application of fully integrated reservoir character- ization and improved recovery technologies that are resulting in higher recovery factors (Dusseault 2013), up to 70–80% in some fields. AlaskaÕs heavy oil and bitumen deposits on the North Slope are very large (24–33 billion BBLs, or 3.8–5.2 billion m3) and they hold promise for com- mercially successful development. Since early 1980s (Werner 1987), two very large, shallow heavy oil- impregnated sands have been known to overlie the Kuparuk River field and underlie a 1,800 ft (549 m) thick permafrost (Fig. 21). These are the Ugnu Sands (8–12 °API) at depths of 2,000–5,000 ft (610–1,524) and the West Sak Formation (16–22 °API) at 2,300– 5,500 ft (701–1,676 m). The size of the deposits is well defined with the numerous wells tapping the under- lying conventional oil fields. For the Lower Ugnu Sands and West Sak Formation the resources are 12– 18 billion BBLs (1.9–2.9 billion m3) and 12 billion BBLs (1.9 billion m3), respectively. The reservoirs are fluvial-deltaic sands deposited during the Late Cretaceous–earliest Paleocene in the north andPDF Image | Unconventional Energy Resources
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