Overview of Heavy Oil, Seeps, and Oil (Tar) Sands ...

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Hein, Frances J., 2013, Overview of heavy oil, seeps, and oil (tar) sands, California, in F. J. Hein, D. Leckie, S. Larter, and J. R. Suter, eds., Heavy-oil and oil-sand petroleum systems in Alberta and beyond: AAPG Studies in Geology 64, p. 407 – 435.

Overview of Heavy Oil, Seeps, and Oil (Tar) Sands, California Frances J. Hein Energy Resources Conservation Board, Suite 1000, 250-5th St. SW, Calgary, Alberta, T2P 0R4, Canada (e-mail: [email protected])

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 heavyoil 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.

Copyright n2013 by The American Association of Petroleum Geologists. DOI:10.1306/13371587St643550

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These technological developments, along with improved computing techniques (i.e., threedimensional [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.

INTRODUCTION In its most recent assessment, the International Energy Agency (2010) predicted that unconventional oil production will rise to more than 9 million bbl/day by 2035 compared with a production of about 2 million bbl/day in 2009. Currently, conventional oil production and thermal enhanced oil recovery (EOR) in the United States and heavy-oil production in California are in a decline (U. S. Department of Energy, 2010). As production from these commodities becomes more limited, other unconventional resources such as tight oil, shale gas, oil sands (also called tar sands), oil shale, and shale oil are receiving increased interest on a world basis. Almost all of California’s main oil fields (Figure 1) were discovered between 1890 and 1925, by which time California was a major exporter of oil, accounting for more than 22% of the world oil production (Tennyson, 1998, 2005; Croft and Patzek, 2009). In 1985, California oil production peaked at 1.1 million bbl of oil/day (BOPD) (California Department of Conservation, Division of Oil, Gas and Geothermal Resources, 2006). As conventional hydrocarbon production decreased, the development of thermal production in the 1960s allowed continued oil production of California’s heavy-oil deposits, which surpassed conventional oil production in the mid-1980s (Olsen and Ramzel, 1995). By 2006, California’s oil production declined to 685,000 BOPD, of which 409,000 BOPD was heavy oil and 113,000 BOPD was offshore production (California Department of Conservation, Division of Oil, Gas and Geothermal Resources, 2006). Much of the world’s heavy-oil technologies were originally developed in California. One example is the Kern River field of the San Joaquin Basin (Figure 1), the 10th largest heavy-oil field in the world (10–148 API). It started producing in 1902 and 107 yr later (in 2009), continued to produce about 29 million bbl of oil (Beeson and Singer, 2011). As of 2011 it has an estimated 725 million

bbl of oil remaining (Jaramenko, 2011). For more than 60 yr in California, steam injection, along with steamflood and condensed-water drive, has been used to produce heavy oil (in-situ viscosity 0.05 0.05 – 0.10 >0.7 0.2 – 0.31

Miocene Pliocene Miocene/Pliocene Miocene Miocene

Santa Maria

Coalinga Santa Maria

1.9 0.1

Pliocene Miocene/Pleistocene

Santa Maria Santa Barbara

Faulted margin Unknown Unknown Faulted anticline Flank of anticline/ regional sand wedge Closed anticlines Faulted margin

>0.05

Miocene

Santa Barbara

Tulare ss, dty

0.05 – 0.15 0.9 0.83

Miocene/Pleistocene Miocene/Pliocene Miocene

Los Angeles Los Angeles San Joaquin

Poncho Rico ssy

0.05 – 0.1

Miocene/Pliocene

San Joaquin

Sisquoc dty

0.05 – 0.1

Miocene

Santa Maria

0.5 0.7 0.1 0.15

Miocene/Pliocene Miocene/Pliocene Miocene/Pliocene Pliocene

Ventura Paris Santa Maria Santa Maria

>0.05

Miocene

San Joaquin

0.4 0.1 – 0.15

Miocene/Pliocene Miocene/Pliocene

Los Angeles Santa Cruz

0.4

Miocene/Pliocene

Sisquoc dt/ Careaga ssy Pliocene ssy Poncho Rico ssy Pismo ssy Pleistocene ss,y Vaqueros ssy Paso Robles ssy Miocene ssy

Reef Ridge

Heavy oil, diatomite Oil (tar) sands Oil (tar) sands Oil (tar) sands Oil (tar) sands, diatomite Oil (tar) sands

Vaqueros ssy Sisquoc dt/ Careaga ssy Miocene ssy

Richfield Santa Cruz

Oil (tar) sands Oil (tar) sands

Santa Margarita ssy

Sargeant Ranch Sisquoc (Zaca_Sisquoc)

Oil (tar) sands, diatomite Oil (tar) sands

South Belridge

Oil (tar) sands

South Belridge and Belridge

Heavy oil; diatomite

Oxnard Paris Valley Point Arena Red Rock Mountain

Reserves (billion bbl)

Oil (tar) sands Heavy oil; diatomite Oil (tar) sands Oil (tar) sands Oil (tar) sands Heavy oil Oil (tar) sands; heavy oil Oil (tar) sands Oil (tar) sands

Cat Canyon Chino Cholame Creek Coalinga Edna (Arroyo Grande)

Formation and Lithology

Purisma ss, Monterey ss, dty Careaga ss, Monterey dty

Faulted margin/ sandstone wedge Anticline Anticline Faulted anticline Faulted anticline/ sandstone wedge Anticline/flank of anticline Syncline Anticline Anticline

9** 3** 3** 4** 1, 2, 3, 5, 9** 9** 3** 3** 3** 9** 1, 2, 3, 6** 3** 3** 3, 9** 9** 3** 3, 6**

9** 3, 5, 9**

Purisma

Faulted margin/ sandstone wedge Faulted anticline Faulted margin/ sandstone wedge Anticline

Pliocene

Santa Maria

Faulted anticline

3, 5, 6, 9**

1

Pleistocene

San Joaquin

2

Miocene

San Joaquin

Unconformity and anticline Unconformity and anticline

0.14 – 0.5

3**

3, 5**

7** 6, 7, 8**

Hein

Name

Santa Cruz Miocene 0.1 – 0.2

San Joaquin Miocene 0.13 Oil (tar) sands

Oil (tar) sands

West Midway/Sunset

West San Ardo

Miocene ssy

Santa Maria Santa Cruz Miocene Miocene >0.5 0.05 – 0.15 West Cat Canyon West King City

Santa Margarita ssy

Ventura Miocene/Pliocene Miocene/Pliocene >0.5 0.1 Fernando ssy Cantua ss, Temblor dty

Oil (tar) sands Oil (tar) sands, diatomite Heavy oil Oil (tar) sands Upper Ojai Vallecitos

*Modified from Hein (2006) and Dibblee (1984). **(1) Dibblee (1984); (2) Dibblee et al. (1987); (3) de Chandenedes (1987); (4) Bate and Graham (1987); (5) Walters (1974); (6) Ingle (1981); (7) Beyer (1987); (8) Roadifer (1987); (9) Kuuskraa et al. (1987). y ss = sandstone; dt = diatomite.

3**

3**

6, 7** 3**

3** 3**

1, 2, 6** 3** San Joaquin Santa Barbara Miocene/Pliocene Miocene >0.05 Heavy oil Oil (tar) sands Taft Tapo Canyon

Vaqueros ssy

Oil (tar) sands South Sulfur Mountain

Monterey ssy

0.05 – 0.15

Miocene

San Joaquin

Anticline/flanks of anticline Faulted anticline Anticline/faulted margin Synclinal valley fill Faulted margin/ sandstone wedge Complex anticline Faulted margin/ sandstone wedge Faulted margin/ sandstone wedge Faulted margin

3, 6**

Overview of Heavy Oil, Seeps, and Oil (Tar) Sands, California

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extensional phase in middle–late Miocene was followed by two contractional phases between the Pliocene and the Holocene (Karner and Dewey, 1986). Initial fill of the basins, near adjacent uplands, was mostly fluvial to shallow marine, evolving downdip into more marine and deep-marine embayments. At different times during the Miocene, regional upwelling along the continental borderland resulted in a very high production of organics, along with biogenic silica, mainly associated with diatom blooms. The resulting organic-rich shales and diatomites, mostly belonging to the siliceous Miocene Monterey Formation (Figures 5, 6), provided much of the source rocks for the heavy-oil reservoirs and oil-sand deposits along the margins of the basins (Ingle, 1981; Isaacs, 1981a, b, 1987; Reid and McIntyre, 2001). True diatomites within the Monterey Formation tend to have high contents of biogenic silica and generally lack organic matter. By contrast, the associated phosphatic shales and mudstones of the Monterey Formation tend to be the best and most prolific source rocks. Hydrocarbon migration was updip to the margins of the individual basins and occurred during the latest Tertiary (de Chadenedes, 1984, 1987; Dibblee, 1984; Dibblee et al., 1987; Yeates and Beall, 1991; Magoon et al., 2004). Current resource plays within the Monterey Formation are mainly light, tight oil that have high enough flow rates through induced fracs for economic recovery. Typically, on their own, the more heavy-oil zones within the Monterey Formation are not economically produced at high enough rates through induced fracs. For economic production, the heavy-oil zones may be produced, along with lighter oils, that are within and adjacent to areas of very mature Monterey source rocks. The Monterey Formation is highly fractured (Figure 6B) and locally forms structural traps of fractured reservoirs in the Santa Maria Basin and offshore Santa Barbara Channel (Figure 1). The Monterey succession is the main source for much of the hydrocarbons in the coastal and offshore seeps, in the heavy-oil fields, and the oil (tar) sand outcrops (Wilkinson, 1972; Hostettler et al., 2004; U. S. Geological Survey, 2005) (Figures 1–3). Elsewhere, other source rocks contribute to the multiple petroleum systems operating within the different subbasins of California. The stable carbon isotope, biomarker, and Rock-Eval pyrolysis data indicate that, in addition to the Miocene Monterey Formation, some of the other source rocks include the Eocene Kreyenhagen shale (Reef Ridge – Kettleman Hills and Coalinga oil field), the Miocene Point Sal shale (Santa Maria Basin), and the upper Miocene Belridge diatomite (Reef Ridge Member) and associated underlying shales of the McClure Formation (Reef Ridge–Kettleman Hills, South Belridge, and McKittrick oil fields) (Figure 5) (Lillis and Stanley, 1999; Magoon et al., 2004).

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Figure 3. Google map of California with highlighted part showing locations of the main oil seep and tar pits discussed in this chapter; inset index map of part of California illustrating the coastal area, the Los Angeles and San Joaquin basins, with major oil and heavy oil field outlines indicated in black. Modified from Tennyson (2005); U.S. Geological Survey (2005). 100 km (62 mi). A significant amount of structural variation developed as this part of the western North American plate boundary reorganized from a convergent plate boundary (before the Oligocene) to a fully developed right-lateral San Andreas transform boundary by the Miocene. A

series of transgressive–regressive cycles superimposed wedges of sands and associated diatomites on the larger evolving tectonic features to produce combination stratigraphic-structural traps for many of the California oil fields (de Chadenedes, 1984, 1987). Similar regional


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Figure 4. Examples of natural oil seeps, coastal area (Figure 3), between Point Conception and Los Angeles, California: (A) Koeningstein Road oil seep, north of Santa Paula, east of Ojai, consisting of bitumen and asphaltum; (B) Surface emanation of heavy oil and gas, north Sulfur Mountain area, Ojai oil field, Ventura County, California; (C) Hamp oil seep (arrow), consisting of heavy oil, bitumen, and bitumen-saturated oil sand, Silverthread area, Ojai oil field. Note fault trace shown by the line.

interactions of sedimentation, eustasy, and tectonics resulted in structural and stratigraphic complexity, interrupted by major unconformities (Figure 5A). On a regional basis, the diatomaceous mudstones, diatomites, and black shales are the main source rocks (Figure 5A). Associated heavy-oil reservoirs were emplaced within a variety of sandstones, including basal lowstand deposits and transgressive and regressive sandstones. Surficial oil sands are hosted within mainly unconsolidated Pliocene–Pleistocene and Pleistocene sands.

HEAVY OIL For decades, much of the heavy-oil production has been associated with the Miocene Monterey Formation. This is a thin-bedded, mixed-lithology succession of finegrained mudstones (Figure 6)—one of the more typical unconventional mudstone and mudrock reservoirs presently being exploited in North America. The Monterey is an organic-rich hemipelagic deposit, locally phosphatic, calcareous, or dolomite rich. It represents hemipelagic deposition of drowned basins in a variety of environments from shelves to banktops, deep sea slopes, and base-of-slope settings (Figure 7). Later diagenesis and structural deformation of the Monterey Formation was complex, mostly a function of mudrock composition, petrography, and burial history. Originally, the hemipelagic diatomaceous silica was deposited as a metastable opal (amorphous opal; opal-A), which underwent two stages of dissolution and reprecipitation to form the metastable opal (cristoballite and

tridynamite; opal-CT), and then eventually to form the more stable quartz phases. These diagenetic changes resulted in the development of systems of fractures, which augmented the structural fractures that were forming in response to tectonic forces on the brittle, hard, siliceous rocks. The diagenesis resulted in the expulsion of significant volumes of water from the highly porous matrix of the diatomite and siliceous muds. The micro-overpressure associated with the dewatering and associated column loss (opal-A porosity up to 70%, opal-CT up to 40%, and quartz up to 20%) generated a microfracture fabric in the less terrigenous facies of the Monterey Formation. Because of the original low matrix permeability of the Monterey diatomaceous shales, the petroleum system flow paths were dependent on the fracture flow paths created during diagenesis and tectonism. Fracture and fault system patterns that developed were a function of the host rock type, the bed thickness, and regional stress regimes. In the Monterey succession, a wide variety of structural features occurs at several scales (Gutierrez-Alonso and Gross, 1997). Large-scale structural features include normal faults, bedding-plane detachments, low-angle thrust faults, triangle zones, thrust duplex structures, and fault blocks. Mesoscale features include: ptygmatically folded veins, folded beds of chert, inverted normal faults, fault-propagation folds, and breccia zones (Jeffrey et al., 1991). Aside from the Monterey Formation, it is difficult to present representative or type deposits of heavy-oil reservoirs in California because such significant variation exists between the different subbasins (Figure 7). This is

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Figure 5. (A) Stratigraphic nomenclature of southern California for the offshore and onshore areas and oil fields discussed in this chapter. Yellow indicates source rocks, black bars are main hydrocarbon fields, red bars show host rocks for surficial oil-sand deposits exposed in either basin-marginal settings and/or surface areas with structural deformation, exposing the deeper successions at surface (sources: Oakeshott et al., 1954; de Chandenedes, 1984, 1987; Dibblee, 1984; Dibblee et al., 1987; Norton and Otott, 1996; Bridges and Castle, 2003; Imhof and Castle, 2004). (B) Approximate line of section for the stratigraphic nomenclature discussed from the Wilmington oil field southeast to the Coalinga oil field in the northwest. 100 km (62 mi). caused by differential rates of subsidence and uplift, sediment supply, paleooceanographic histories of regional circulation and upwelling, and sill depths between the different subbasins (Bridges and Castle, 2003; Bowersox, 2004; see Schwartz, 1988, for a good summary). All of these paleogeomorphic factors were coupled with several transgressive-regressive pulses associated with changes in relative base level from the postCretaceous to the Holocene. This results in stratigraphy and petroleum flow system(s) that are nonuniform and complex (Figure 5). The overall result is a patchwork of different sedimentation and tectonic histories and reservoirs that range the spectrum from deep-marine to near-

shore, nonmarine fluviolacustrine and alluvial-fan environments. On a field basis, facies models from most environments are applicable (dependent on the sedimentary and tectonic history within an individual basin). Because of this inherent complexity, in this section, some of the major oil fields are discussed that show the main reservoir types and their dominant controls.

Fluvial and Lagoonal and Nearshore Reservoirs: Coalinga Oil Field The Coalinga oil field, central California (Figures 3B, 8), originally discovered in the late 1800s, started


417

Figure 5. (cont.).

production in 1890. Cumulative production was in excess of 912 million bbl, with estimated remaining reserves of 58 million bbl, and more than 1600 active wells (end of 2006). It is now the eighth largest producing oil field in California. The main operators are Aera Energy LLC and Chevron Corporation (California Department of Conservation, Division of Oil, Gas and Geothermal Resources, 2006). The Coalinga oil field is one of the first discovered and described oil fields in California and became one of the more prolific producers of heavy oil in California (Arnold and Anderson, 1910). The oil on the west side of the field is heavy (11–198 API); on the east side, both heavy and medium-grade oil (12–308 API). Most of the oil and heavy oil are produced from multiple discrete intervals within the lower part of the Temblor Formation (Figure 5) (Bate, 1984; Bate and Graham, 1987; Clark et al., 2001). The Coalinga field is divided into the East and West Coalinga, separated by the northwest–southeasttrending Coalinga anticline (Figure 8) (Clark et al., 2001). The Coalinga oil field is part of a petroleum system, in which the organic-rich rocks of the underlying middle

Eocene Kreyenhagen Formation were the source rocks, and the accumulated oil was reservoired in the overlying Temblor Formation sandstones (Figures 5, 8). Traps are mostly stratigraphic in nature, with some structural complications. Along the eastern side of the San Andreas Fault reservoir rocks outcrop, several historical oil seeps (Figure 8A, B) also exist. Here, local solidified tar mats and tight zones within the reservoir rocks provide cap rocks to the subsurface reservoirs (Clark et al., 2001; Imhof and Castle, 2004). Structure at the Coalinga oil field is a southeastern-plunging anticline (Figure 8A) (Clark et al., 2001). The Coalinga anticline is one of a series of enechelon anticlines that occur on the eastern side of the San Andreas Fault and define the western fold belt of the San Joaquin Basin (Bridges and Castle, 2003). The Temblor Formation unconformably overlies the Eocene Kreyenhagen Shale and, in turn, is unconformably overlain by the Etchegoin Formation shales, the McLure Shale, the Reef Ridge diatomaceous shale, or by regressive sands of the Santa Margarita Formation (Figures 5; 8B, D). The Coalinga oil field reservoir consists of the Miocene Temblor Formation braided stream

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Figure 6. Miocene Monterey Formation diatomite, southern California. (A) Representative stratigraphic column showing textural variation on the left, mineralogy and total organic carbon plotted on the right (from Isaacs, 1981b). (B) Outcrop photograph of wispy-laminated dark organic shale, light-gray silty mudstone, and white very fine sandstone/siltstone interlaminations, Monterey Formation (from Isaacs, 1981b). (C) Outcrop photograph of fractured, light-tan, silica-rich diatomite, with bitumen and heavy-oil fracture fills, overlying unfractured, parallel-laminated, fissile organic shale at the base, coastal outcrops, Point Conception, California. (D) Photograph of hand specimen of fractured and folded Miocene Formation diatomite, Arroyo Burro, Santa Barbara, California.

Figure 7. Submerged topography of the California borderland during highstands that emplaced the regional, hemipelagic, diatomaceous shales and mudstones. These organic mudstones, mainly from the Miocene Monterey Formation, were source rocks for later hydrocarbon accumulations, including heavy oil, seeps, and oil sands in California (from Gorsline and Emery, 1959, published in Pickering et al., 1989).


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Figure 8. Coalinga oil field, San Joaquin Basin. (A) Structure contour map showing the outline of the field, the southeastplunging Coalinga anticline, and line of section BB0. Division of the Coalinga oil field is into the West Coalinga and East Coalinga areas. Map also shows lease locations, cored wells, sonic logs, seismic data, and outcrops. The Coalinga Nose anticline represents the East Coalinga part of the field, and the monclinal flank is the West Coalinga part of the field. (B) Cross section BB0 of the East Coalinga field showing the absence of an updip seal at Coalinga, where the Temblor reservoir is breached at the surface. Oil accumulates behind near-surface tight cemented rocks and tar seals to create the underlying giant oil field. (C) Core photograph (white light) of the basal Temblor unconformity (BT) showing onlap of Temblor sands onto the diatomaceous shales of the Kreyenhagen Formation. (D) Core photograph (white light) of the top Temblor unconformity (TT) showing onlap of Etchegoin shales onto the cemented, bioturbated, and oil-stained Temblor sands. Scale bar in tenths of feet. Modified from Clark et al. (2001). sands that are overlain by transgressive lagoonal and shallow-marine sediments. Internally within the Temblor Formation are five different systems tracts, including incised-valley, estuarine, tide- to wave-dominated shoreline, diatomite, and subtidal deposits (Bridges and Castle, 2003). The basal reservoir cobble conglomerates and cobble sands were emplaced as broad (tens of meters wide), shallow (several meters deep), braided channels that were cut into and deposited over the siliceous source rock shales of the Kreyenhagen Formation (Figures 5, 8C). The overlying coarse clastics are a sequence of sandstone and mudstones deposited in a variety of nearshore marine environments that draped the Coalinga anticline (Clark et al., 2001). The trap is a tar seal that formed at the air-oil contact in the eastern part of the oil field (Bate and

Graham, 1987). Internally, the lower Temblor reservoir was highly compartmentalized with a complete lack of vertical transmissibility between the different braidchannel sands (Lennon, 1976). Detailed mapping of both vertical and lateral reservoir anisotropy is needed for a 3-D characterization and visualization of the geologic framework. This allows for proper placement of wells to ensure optimum production from a very heterogeneous heavy-oil reservoir in a basin-marginal setting (Lennon, 1976; Bate and Graham, 1987). Recently, seismic facies mapping with 3-D reservoir visualization and modeling tools are being used routinely in the Coalinga field. These are used to build geologic models for reservoir planning, simulation, and monitoring and to construct the

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Figure 9. (A) Cross section of the McKittrick oil field along N408E, subsurface depths in feet. Modified from Allan et al. (2006). (B) Cross section of the McKittrick oil field along N308E, subsurface depths in feet. Modified from Dibblee (1984). (C) Threedimensional block model of the faulted anticline of the South Belridge oil field, with zone color key indicating the main stratigraphic units (from Allan et al., 2006). 1000 ft (305 m).

pathways for horizontal wells, aided with logging-whiledrilling (LWD) systems (Sanford and Wildman, 1999; Clark et al., 2001; Imhof and Castle, 2004).

Fluvial, Lacustrine, and Deep-Sea Slope Reservoirs: South Belridge Oil Field The South Belridge oil field, southern San Joaquin Basin (Figures 3, 9A – C), originally discovered in 1911, is the fourth largest oil field in California and sixth most

productive in the United States. Cumulative production is close to 2 billion bbl, with estimated remaining reserves of 520 million bbl and about 6000 active wells (end of 2006). The main operator is Aera Energy Ltd. that has stated a production of 140,000 bbl of oilequivalent per day (Miller and McPherson, 1992; California Department of Conservation, Division of Oil, Gas and Geothermal Resources, 2006). This oil field has mostly produced heavy oil (10–148 API), mainly from the Pliocene–Pleistocene Tulare Formation (Beyer, 1987; Eagan et al., 1999) (Figures 5, 9B).


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Figure 9. (cont.). Different reservoir types within the field have been produced by either thermal stimulation or through hydraulic fracturing. The structure in the South Belridge oil field consists of a northwest-trending elongate anticline that is plunging to the southeast and oriented subparallel to the San Andreas Fault system (Figure 9A–C) (Miller and McPherson, 1992). The shallow successions dip gently on the flanks of the fold. Several unconformities occur in the field, with the most prominent at the base of the Pleistocene Tulare Formation. The producing intervals within the Tulare Formation are lenticular, nonmarine, fluvial-lacustrine deltaic sandstone reservoirs, which attain aggregate thicknesses of about 70 m (230 ft) on structural closures and up to about 180 m (590 ft) on the flanks of the fold. These lenticular sands are interbedded with siltstone and claystone, and the main reservoir is a stratigraphic trap associated with a westward lensing out of the Tulare sands. Thermal stimulation is used to produce heavy oil (oil gravity ranges from 12 to 158 API) from unconsolidated to weakly indurated, poorly sorted Tulare sands. Historically, the Tulare production accounted for about 80% of the production and reserves of the South Belfied oil field (Beyer, 1987). A cross section and seismic survey of the South Belridge oil field (Figure 9A, B) shows the various structural and stratigraphic relationships of the Tulare reservoir sands that overlie the Monterey diatomite (opal-A) reservoirs. In the South Belridge field, the diagenetic

transition from opal-A to opal-CT occurs between 457 and 549 m (1500 and 1800 ft) depth in the southern part of the field. The anticlinal structure of the diatomite rocks that contains medium-gravity oil (Figure 9C) underlies the Tulare oil sands (Figure 9A, B). At present, the diatomite of the South Belridge field is being steamed continuously on the crest of the anticline and cyclically on the east flank of the anticline (Miller and McPherson, 1992). The trap at South Belridge consists of a combination of structural and stratigraphic traps and local tar seals in both the Tulare sands and the underlying diatomite reservoirs. Compared with other fields in the San Joaquin Basin, the petroleum accumulation in the South Belridge oil field is relatively young, and the field is not in equilibrium. Hydrocarbon migration was predepositional or syndepositional with the Tulare Formation, as indicated by tar mats in the Pliocene Ethegoin Formation and earliest Tulare sediments along the basal unconformity. At present, the deeper Monterey diatomite is generating hydrocarbons at depth. The Monterey diatomite has a subcropping relationship with the overlying Tulare succession along the axis of the South Belridge anticline, thus providing the pathway for hydrocarbon charging in the oil field (Figure 9A, B) (Miller and McPherson, 1992). Several bitumen accumulations are present at the crest of the structure that are thought to be paleo-tar pits, formed when the diatomite was exposed at the surface in the Pliocene – Pleistocene. These were subsequently overtopped by

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late Pliocene and Pleistocene fluvial and alluvial deposits. The bitumen contains very little sedimentary material, indicating it was relatively solid at the time of Tulare deposition. The biggest challenge in production from the Tulare reservoirs is the lateral discontinuity of the reservoir sands, which typically die out in 3 to 30 m (10–100 ft) and are bounded by floodplain and lacustrine mud and siltstones that range from local to fieldwide in extent (Eagan et al., 1999). Normal faulting (at least five were mapped) further complicates the stratigraphy and locally may lead to compartmentalization of the heavy-oil reservoir. In the past, it has been difficult to place the injector and producer wells in ideal locations. It was also impossible to ascertain the actual geospatial relationship of the injector and producer wells to one another and their orientation with respect to the thin lenticular reservoirs and internal cap rocks. In 1998, this led to a fieldwide development of a 3-D surveillance geologic framework using data from 650 wells to describe the complex stratigraphic and structural relationships of the reservoir and nonreservoir rock. The resulting computer model has 22 different reservoir zones, each from 1.5 to 6 m (5–20 ft) thick, and specifically models the influence of the five most prominent faults. Preliminary results of the 3-D geologic model and visualization have led to optimizing the placement of the injector and producer wells and provide for real-time visualization and quantification of production and flow units (Eagan et al., 1999). In the South Belridge oil field, below the Pleistocene unconformity is the Belridge diatomite (Reef Ridge Member, Monterey Formation) (Figure 5A). Oil from this deeper diatomite is lighter oil (20 – 318 API). This deeper succession is more sharply folded than the overlying Tulare Formation. The Belridge diatomite consists of silty or clayey diatomite with thin sandstone and siltstone interbeds and lenses of porcelaneous clay-shale (Schwartz, 1988). Wells were completed by hydraulic fracturing. The Belridge diatomite (Reef Ridge shale) accounted for about 20% of the production and reserves for the field. Other very limited production occurred from underlying siliceous rocks of the Monterey Formation (below the Reef Ridge Member) because they are opal-CT and very tight. Some production occurred from Pliocene sands and diatomite preserved on the flanks of the anticline, where they were not removed by the Pleistocene erosion (Beyer, 1987). The history of the South Belridge oil field is similar to other fields in the southern San Joaquin Basin. Oil initially accumulated on the main anticlinal structure at South Belridge in the fractured Belridge diatomite. Further faulting and fracturing of local cap rocks above the Belridge diatomite allowed the oil to migrate up into

the overlying Tulare sand reservoirs, where locally, they pinch out along the anticlinal structure, forming a mostly stratigraphic trap. The emplacement of the hydrocarbons into the Tulare is a complex story. What is amazing is that so much oil entered the sands in such a short period. A similar, but more complex, history of emplacement occurred at the nearby Taft-McKittrick oil field and tar pit (de Chadenedes, 1984, 1987) (Figure 9A, B). Plunging folds are faulted, deeper successions are more tightly folded and faulted than shallower successions, and internal unconformities and faults compartmentalize the reservoir. Initially, a simple faulted anticline formed the trap, with oil accumulating in the Miocene Reef Ridge Member and overlying Pliocene–Pleistocene Tulare Formation. Structural deformation during the Pleistocene then thrust the Miocene on top of the Pliocene – Pleistocene Tulare sandstone reservoirs. Subsequent fracturing and faulting of the Miocene overthrust succession permitted further petroleum migration into the Miocene overthrust and to the surface forming the McKittrick tar pits (Figure 9A, B) (de Chadenedes, 1984, 1987).

Deep-sea Submarine Slope and Base-of-slope Fan Reservoirs: Wilmington Oil Field The Wilmington oil field, Los Angeles Basin (Figures 3 [inset], 10, 11), originally discovered in 1932, is the largest oil field in California (Mayuga, 1970; Biddle, 1991) and the third largest in the United States (Clarke and Phillips, 2003, 2004). Original oil in place is estimated to be about 9 billion bbl. Cumulative total production is more than 2.6 billion bbl, with remaining reserves of about 300 million bbl (as of 2002), and more than 1200 active wells (California Department of Conservation, Division of Oil, Gas, and Geothermal Resources, 2006). The main operator is the Tidelands Oil Production Company in the Old Wilmington, or western part, of the field, with THUMS’ (artificial islands named after the parent companies: Texaco, Humble Oil [now Exxon], Union Oil [now ConocoPhillips], Mobil Oil [now Exxon], and Shell Oil) Long Beach Unit the field contractor for the eastern part of the field (Figure 10A) (Clarke and Phillips, 2003, 2004). This oil field has highly variable oil gravities, with shallower pools containing heavier oil (12–148 API) and some deeper pools with light oil (25–328 API). Other variations are between onshore and offshore pools (Berman and Clarke, 1987; California Department of Conservation, Division of Oil, Gas and Geothermal Resources, 2006). Oil is produced mainly from the Pliocene Repetto turbidite lobes and the underlying Miocene deep-sea turbidite sands from slope and baseof-slope settings of the Puente Formation (Figure 5)


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Figure 10. (A) Map of the Long Beach area showing the areas of the Wilmington oil field where Tidelands Oil Production Company (western part) and THUMS Long Beach Company (Long Beach Unit) are the field contractors. The city of Long Beach, Department of Oil Properties, operates both. The coastline, harbor areas, breakwater, and oil-drilling islands are shown for reference. Pacific Energy Resources operates the polygonal area between the properties. (B) Aerial photograph of Long Beach – Los Angeles Harbor showing the location of the three horizontal well projects (case histories 1, 2, 3) and fault blocks II through V (FB II– FB V). Oil activities coexist with the busiest harbor in the country, with fault block V steam-flood operations (case history 2) beneath Long Beach’s new $180 million aquarium and northeast of the Queen Mary dockyard. (C) Type logs for the wells 2AU 30B1 and 2AT58B 0 for the steam-flood project in FB V; original picked markers are shown in black, and newly picked markers are shown in red, the difference of which was used to calculate subsidence related to 60 yr of oil production in the area. The inset shows the T4 paleochannel fill from well 2AT58B. Location of wells given in Figure 11C (from Clarke and Phillips, 2003, 2004).

(Truex, 1972, 1974; Henderson, 1987; Slatt et al., 1993; Norton and Otott, 1996). The Wilmington oil field is part of a series of oil fields in the Los Angeles Basin that lie on a series of northwest– southeast-trending en echelon anticlines and complex antiforms that are associated with the NewportInglewood Fault (Pickering et al., 1989; Norton and Otott, 1996) (Figures 11A, 12). Production is from slope and base-of-slope turbidites and channel sands, with the entire succession being folded and faulted (Figures 10C;

11B, C). The basic structure of the field is a large, sygmoidal, asymmetric highly faulted anticline, with field production progressively from east to west in a series of 10 different fault blocks (Norton and Otott, 1996; Clarke, 1999). Internally, the main Wilmington anticline is cut by several normal faults that compartmentalize the reservoir into separate production units (Figures 10B, 11A). These faults also offset both the paleochannel reservoir sands and the onlapping turbidite reservoir sands (Figure 11B, C) (Clarke and Phillips, 2003, 2004).

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Figure 11. (A) Structure map of the T marker in fault block IIA. Observation well locations shown by yellow dots, and trajectories of the horizontal wells are shown by brown curving lines. Contour intervals are 15.2 m (50 ft) from 731.5 to 1036 m (2400 to 3400 ft) below sea level (B) Three-dimensional geologic visualization of the D1F onlap onto the D2 shale in fault block II, vertical exaggeration 2, and the units are displayed in feet; (C) Three-dimensional geologic visualization of the T2 horizon in fault block II, showing the locations of the two type wells in Figure 10. The T4 paleochannel cuts through several horizons and is offset by the Wilmington and Ford faults (from Clarke and Phillips, 2003, 2004). 2000 ft (609.6 m).

One of the biggest challenges in secondary and tertiary recovery from this field is the extreme lateral and vertical heterogeneity in both the reservoir and nonreservoir rocks. Geologic heterogeneity at all scales has made it difficult to properly characterize the reservoir heterogeneity. Individual turbidite beds are normally graded and interbedded with siltstones and shales; however, the turbidites occur in multistory, stacked, and faulted base-of-slope paleochannel fills or in overlapping and onlapping lenticular lobes, with internal channeling (Slatt et al., 1993). In addition to the stratigraphic compilations, many small structural complications exist. The structural faulting is complex, with vertical offsets ranging from 15 to 30 m (50–100 ft). Lo-

cally, some faults in the Repetto Formation are permeability barriers, whereas other faults are only partially sealing (Clarke and Phillips, 2003, 2004). In some areas of the Wilmington oil field, steamflood expansion in the mid-1990s was done using horizontal wells that each replaced four or five vertical wells (Figure 10B), with five observation wells used to monitor the steam growth in the subsurface (Clarke and Phillips, 2003, 2004). This scheme had two steam injectors and two producers placed 122 m (400 ft) apart horizontally in a pseudo-steam assisted gravity drainage (SAGD) scheme. For the scheme to be effective, a complete 3-D geologic model was built by doing detailed wire-line-log interpretation tied to


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Figure 12. Sedimentary basins and main structural features of the southern California Borderland and immediately adjacent on land areas, with approximate thicknesses of basin fills shown in parentheses in kilometers; as follows: 1. Ridge Basin (4.5 km; 2.8 mi); 2. Los Angeles Basin (8.0 km; 5 mi); 3. San Diego Trough (2.5 km; 1.6 mi); 4. Santa Monica Basin (3.5 km; 2.2 mi); 5. Catalina Basin (0.8 km; 0.5 mi); 6. Santa Cruz Basin (1.8 km; 1.1 mi); 7. San Pedro Basin (1.8 km; 1.1 mi); 8. San Clemente Basin; 9. San Nicolas Basin (1.4 km; 0.9 mi); 10. East Cortes Basin; 11. Tanner Basin (1.4 km; 0.9 mi); 12. Patton Basin (1.7 km; 1.056 mi). SMI = San Miguel Island; SRI = Santa Rosa Island; SCrI = Santa Cruz Island; SCI = Santa Catalina Island; SBI = Santa Barbara Island; SNI = San Nicolas Island; SCLI = San Clemente Island. Northwest-trending faults are dextral and synthetic to the San Andreas Fault. Santa Monica Fault is sinistral. Anticline trend is mainly west-northwest (from Pickering et al., 1989).

reservoir characterization and structural fault delineation (Figure 11B, C). A real-time 3-D working geologic model with 3-D visualization allowed for data inconsistencies to be reconciled and also identified areas of intraformational subsidence and compaction that related to oil production and heavy-oil withdrawal during the previous 60 yr, with maximum subsidence in this area of 8.8 m (29 ft) (Figure 10C). In January 1999, a steam-flood pilot project was halted because of increased subsidence. In October 1999, flank wells were converted to coldwater injection wells, and subsidence was halted by September 2002. Elsewhere, experience from this steam-flood pilot project was applied successfully to the development, definition, exploitation, and capture of bypassed pay (Clarke and Phillips, 2003, 2004). This recent work involving 3-D geologic modeling, visualizing, and measuring-while-drilling technologies have clearly demonstrated that these new and evolving technologies can greatly increase reserves and ultimate recovery from old oil fields in California, such as the Wilmington oil field (Blesener and Henerson, 1996; Clarke, 1999). Production from the western fault blocks are reaching economic limits; elsewhere, in the field,

where water cuts are less, secondary and tertiary steamrecovery techniques have proven to successfully produce the heavy oil. In some cases, steam was used to fuse and indurate the unconsolidated sands to avoid wellbore breakthrough and to allow selective perforations to optimize water recoveries. Three-dimensional seismic studies have aided in reservoir characterization and delineation of the complete geologic framework; were used to geologically model, define, and exploit bypassed pay; and were used to extend the life of the field into more marginal areas, which previously have not been developed (Clarke, 1999; Clarke and Phillips, 2003, 2004).

Seeps Recent world estimates indicate that about 47% of crude oil currently entering the marine setting is from natural oil seepage, and natural oil seeps are the single most important source of oil in the ocean (Kvenvolden and Cooper, 2003). Oil seeps are common in southern and central California and are a natural part of the oilproducing area along the California coastline. Here, many winter storms wash up tar balls along the beaches

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from oil that was mostly sourced in the Miocene Monterey diatomite that crops out along the shoreline (Hartman and Hammond, 1981; Kvenvolden et al., 1999, 2002a, b; Kvenvolden and Cooper, 2003; Hostettler et al., 2004; Minerals Management Service, 2005). Since about 1980, more than 1 million bbl of oil have seeped off along the coast of central and southern California (Minerals Management Service, 2005). These seeps form oil slicks on the water surface, and some have had perennial or continuous discharge since the late 1700s, as noted by early English and Spanish explorers (Wilkinson, 1972). In submarine areas, a unique and diverse macrofaunal seep community exists (Hornafius et al., 1999; Lorenson, 2001). Similarly, on land, ecological studies show areas surrounding seeps to be more diverse and biologically active than surrounding areas lacking seeps. This is interpreted to be caused by the bubbling of both water and oil from the seeps (Lorenson, 2001; Mulqueen, 2007). One particularly active area is in the Coal Oil and Goleta points seep field, located in the offshore Santa Barbara Channel, between Point Conception and Ventura (Figure 3) (Fischer, 1978; Hornafius et al., 1999; Broderick, 2001; Washburn et al., 2005). Here, a series of seeps have been studied since the 1980s by sampling and collection of natural hydrocarbon emanations in ocean-bottom steel pyramids (350-ton and 15-m [50-ft]-high structures) called seep tents. The Coal Oil Point offshore seep area has collectively discharged about 55,000 bbl of oil/yr (equivalent to 50–70 bbl/day or about 1–2 104 L/day), with an additional 1.8 billion ft3 (510 million m3) of natural gas (Allen et al., 1970; Broderick, 2001; Kvenvolden et al., 2002b). This seep area also contributes about 22 tons of reactive organocarbons (ROGs precursors to smog) in the Santa Barbara area each day (Clark et al., 1999, 2005). The connection of submarine discharge in the Coal Point seep field has been tied to subsurface reservoirs, where decreased natural-marine seepages correlate with increased offshore oil production in the area (Quigley et al., 1999a, b). The collection of hydrocarbons on the ocean floor in seep tents have cut emanations to the seawater and atmosphere, with noticeable reduction in the natural levels of ROGs, oil slicks on the sea surface, and the number of tar balls along the shoreline. In addition to the Coal Point seep field, a 1000-m (3280-ft)-thick tar mat is within and overlying the Monterey structures offshore Santa Maria. This tar mat is the seal for fractured Monterey strata that was explored in the 1980s and 1990s.

Oil (Tar) Sands Hundreds of asphaltum and oil (tar) sands locations are in California (de Chadenedes, 1984, 1987). Most of the

largest oil-sand deposits occur in the Santa Maria Basin, in the coastal area of southern California (Figure 3; Table 1). These are mostly hosted within the Sisquoc Formation (Figure 5), which may have been a seal to migrating Miocene oil, hosted from the deeper source rocks of the Monterey Formation and Point Sal Member (Kuuskraa et al., 1987). Other oil sands in the Santa Maria Basin are hosted in basal Foxen deposit and in the overlying Careaga Formation, where underlying source rocks of the Sisquoc Formation are relatively thin (Figure 5) (Kuuskraa et al., 1987). In California, the sixth largest oil-sand deposit is the Oxnard oil field of the Ventura Basin, where bitumen is hosted within two sands of the Pico Formation (Figure 5), which unconformably overlie the source rocks of the Monterey Formation (Kuuskraa et al., 1987). Oil-sand deposits have been mined intermittently for hundreds of years (Earley, 1984), but to date, no commercial in-situ thermal schemes have been operating. In the 1980s, Getty Oil Company ran an experimental heat distillation scheme on the giant McKittrick oil field in the southwest San Joaquin Basin (Figures 3 [inset], 9C). Here, the basic structure is a series of faulted (both thrust and normal) anticlines or anticlinesyncline pairs, with most of the heavy oil and oil (tar) sands in combination structural-stratigraphic traps. Although called tar sands, the deposit is technically oil sand and heavy oil, with oil viscosity increasing with depth from 5 to 208 API (de Chadenedes, 1984, 1987). In the McKittrick oil district, oil is produced mainly from almost all of the Tertiary sands, with the largest production from the Miocene Temblor Formation (Figures 5; 9A, B) (de Chadenedes, 1987). A diatomite project is also in place to extract hydrocarbons from surface exposures of the charged diatomite; at present, cat litter is made from the non-hydrocarbon-bearing offsetting diatomite strata.

HISTORICAL AND TECHNOLOGICAL DEVELOPMENT OF HEAVY OIL, SEEPS, AND OIL SANDS IN CALIFORNIA In 1850, the first distillation of seep oil into lamp oil was by Andreas Pico, who collected and distilled seep oil in Pico Canyon, to be used as lamp oil in the San Fernando Mission (California Department of Conservation, Division of Oil and Gas, 1981). By the mid-1860s, oil dug in pits or underground tunnels was being mined in large operations, including those at McKittrick tar pits in Kern County and the Adams Canyon area of the Santa Paula oil field, in Ventura County. More than 130 yr ago, excavations of more than 25 of these tunnels were done by companies that eventually merged to form Union


Oil Company. Tunnels followed the natural oil seepages in the area, and at many of these sites, water and oil are still flowing to the surface. In the 1860s, the tunnels in the Adams Canyon area of the Santa Paula oil field produced more oil than any other production method in California. At the time, the long distances to markets, the relatively high operating costs, and economic factors meant that such operations were sporadic and seasonal. As the oil fields were by Union Oil Company (or by the companies that merged later to form Union Oil), the seep oil production declined, along with a replacement of seep oil production by conventional drilling operations (California Department of Conservation, Division of Oil and Gas, 1981). Most of the technologies used to produce heavy oil were originally developed in California. Guerard (1989) gives a comprehensive review of the history of the technologies developed in California for extraction and production of heavy oil. In the past, although California’s heavy-oil potential was enormous, it was not economical to produce them by conventional means and as such, in the past, these deposits were not economically attractive. With the evolution of secondary and tertiary schemes, mostly thermal steam-flood and fire-flood (in-situ combustion), it became possible to develop these vast resources. As noted by Schamel (1998), recoveries increased from presteam values of less than 10% in the Midway-Sunset field to up to 40 to 70% after steaminjection projects were beyond the pilot stage of development. To produce the heavy oil, the viscosity has to be reduced, which is done mainly by either steam injection or in-situ combustion. Steam produced in steam gen-

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erators, mostly fueled by natural gas, is injected under high pressure into the heavy-oil reservoir. The steam can be injected in either a continuous mode or in a cyclic basis (Figure 13). In continuous steam-flooding, steam is pumped through injector wells into the heavy-oil reservoir. As the steam rises, eventually, it reaches a caprock barrier and then begins to spread laterally at the top of the reservoir. The steam warms the heavy oil in the reservoir and provides drive toward a nearby vertical production well. In CSS, the steam is injected for a few months, followed by a brief (few months) soak time (to allow the heat to penetrate the formation, heat the heavy oil, and lower the viscosity), and then the heated oil is produced up the same well (Guerard, 1989; Dusseault, 2013). Disadvantages of the CSS and steam-flood processes are the costs associated with using natural gas to heat the water for the steam; water requirements for steam generation (Veil and Quinn, 2008); and heat losses through surface lines, wellbores, and latent heat losses to adjacent nonproducing rocks in the formation. Conventional steam injection using vertical wells has a practical limitation of 914 to 1219 m (3000 – 4000 ft) (Guerard, 1989). Recently, horizontal drilling has been used to reduce well spacing in areas with urbanization or environmental concerns (Figure 10A, B) (Clarke and Phillips, 2003, 2004) and to target some of the more marginal areas for heavy-oil production. In pilot areas of California, some of the horizontal schemes are starting to use SAGD to access the heavy-oil reservoirs, as is more commonly done for the Athabasca oil sands of Canada (Hein et al., 2013). The advantage of SAGD with horizontal drilling is that it may allow more uniform

Figure 13. Steam-flooding scheme used in early development of the California heavy-oil fields. Heat from steam is either injected continuously or cyclically into the heavy-oil reservoir. The injected steam heats the reservoir, lowering the viscosity of the oil, making it easier for the steam to push the oil through the formation to the production wells (from Stosur and Slater, 1987).

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heating of the reservoir, the steam and the overlying nonproductive formations have less contact, and latent heat losses may be less than for schemes that use vertical wells with steam-flooding. The difficulty of SAGD is that many of the heavy-oil reservoirs in California are very complex, with channelization, faulting, and significant vertical and lateral barriers. This is in contrast to the Canadian reservoirs that are more laterally continuous and have fewer lateral baffles and barriers. The final thermal process that has been used for heating of heavy-oil reservoirs in California is in-situ combustion, more commonly known as fire-flooding (Garon et al., 1984; Guerard, 1989) (Figure 14). Here, the heavy-oil (or oil-sand) reservoir is heated underground, with initial ignition from a downhole-heating device. Air is then pumped downhole in the injection wells, and a burning front then moves slowly through the reservoir toward the producing wells. Lighter fractions of crude oil ahead of the front are vaporized, leaving a coke behind that is the principal fuel for the in-situ combustion process. The rate of migration of the burning front is dependent on the air injection rate and the type and amount of crude oil being burned (Guerard, 1989). In some cases, water is injected simultaneously or alternatively with the air to help transfer some of the heat to the oil ahead of the burn because of the low heat-carrying capacity of the gases ahead of the burning front. In all cases, once the heavy oil reaches the producing well, artificial lifts, including conventional rods, progressive cavity pumps, or more recently, electrical submersible pumps, are used to lift the oil to the surface.

Figure 14. In-situ combustion scheme used in early development of the California heavy-oil fields. Heat is used to reduce the viscosity of the oil and permit it to flow more easily to the production wells. In a fire-flood, the formation is ignited, and by continued production of air, the burning front is advanced through the reservoir (from Stosur and Slater, 1987).

Ongoing challenges for thermal stimulation of these heavy-oil reservoirs relate to steam-front or burn-front conformance issues, wellbore breakthrough, cap-rock integrity, the use of water, greenhouse gas emissions, and other environmental concerns. Recently, one company, GlassPoint Solar, has built the first solar-powered steam-flood (called Solar Pilot 1) for an oil field in Kern County, California (Terrell, 2011). The solar pilot is a hybrid system of both natural gas and solar energy. The solar pilot array is too far from the injection wells to provide steam directly; instead, the water is heated to subboiling temperatures and then fed to gas-fired steam generators. This pilot has reduced gas usage by 20%, and the hybrid system is below the market prices of natural gas (Terrell, 2011). Several clean-steam and green-steam projects are being piloted in the San Joaquin Basin.

RESERVE GROWTH OF HEAVY OIL, SEEPS, AND OIL SANDS IN CALIFORNIA In his review, Tennyson (2005) looked at the long-term growth history of the 52 giant oil fields in California to determine whether growth patterns are a function of geologic or other characteristics of the fields, including advances in technology. In California, most of the oil fields had early discoveries, between 1890 and 1925, generally growing to significant volumes (>500 million bbl) within the first 20 yr after discovery. Nine giant fields in the San Joaquin Basin had significant stepped growth late in their life—the Midway-Sunset, Kern River, Elk Hills, South Belridge, and Coalinga. Fields in other


basins that also have significant late stepped growth include the Ventura, San Ardo, Cat Canyon, and Wilmington oil fields (Figure 15A, B). At the Midway-Sunset field, the oil gravities are mainly heavy (11 –148 API), with some extra heavy-oil (88 API). Reservoir sands have porosities of 30 to 35%, and permeabilities are from hundreds to thousands of millidarcys. Most of the field is quite shallow, with a low natural drive (Lennon, 1976, 1990). The MidwaySunset oil field is the largest of these fields that showed late growth (Figure 15A). Pilot cyclic steam injection projects began in the early 1960s, which were so successful that they were deployed throughout the field (Rintoul, 1995, 1999). Limited success with in-situ combustion or fire-flooding was done in 1970s, but the most significant reserves growth were related to the development of steam-flooding in the 1960s and 1970s (Tennyson, 2005). Recently, since about 2000, operators have been

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using steam-floods from horizontal wells, which have again significantly spiked the reserves (Figure 15A, B). A further complexity in Midway-Sunset field is the checkerboard nature of the leases. Operators do not always have contiguous acreage, and it is difficult to get benefits of thermal projects if offsetting producers are not steaming their reservoirs. Another heavy-oil field that showed significant reserve growth related to technological development is the South Belridge field (Tennyson, 2005). The production at South Belridge is from two main reservoirs, the upper shallow Pliocene– Pleistocene heavy-oil sands of the Tulare Formation, which contain heavy oil (10–148 API) and the lower more intensely folded Belridge diatomites (Figure 5) with lighter, medium oil (20–328 API). Two advances in unconventional recovery technology led to the increase in reserves growth of the South Belridge oil field. The first was related to the piloting of steam-flooding in the

Figure 15. Estimated ultimate recovery over time for those giant fields in California that showed late-stage stepped growth, interpreted as reflecting advances in in-situ technological developments. The Midway-Sunset, Kern River, Elk Hills, South Belridge, and Coalinga oil fields are in the San Joaquin Basin; the Wilmington oil field in the Los Angeles Basin; and the Ventura, San Ardo, and Cat Canyon oil fields in the coastal California area (Figure 3) (from Tennyson, 2005).

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upper Pliocene–Pleistocene sands (which was successful and then done fieldwide); and the second was advances related to hydraulic fracturing of the deeper diatomite. From its initial discovery in 1911 to 1950, the South Belridge field reserves grew mainly by expansion and the addition of new pools. In the early 1950s, an in-place combustion pilot (fire-flood) operation showed that up to 40 to 60% of the heavy oil could be recovered by insitu thermal methods (Miller and McPherson, 1992). Early CSS began in the 1960s, followed by the diatomite fracturing technology in the 1970s, with the estimated ultimate recovery tripling by 1990 to 1.1 billion bbl. Since the early 1990s, further infill drilling and expansion of steam-flood and water-flooding in the fractured diatomite have increased the expected ultimate recovery to 1.9 billion bbl (Tennyson, 2005) (Figure 15A). The Wilmington field, in the Los Angeles Basin, consists of weakly consolidated to unconsolidated, Pliocene deep-sea submarine fan turbidites. Oil gravities are variable from heavy (12–148API) in the shallower pools to light (25–328API) in the deeper pools; reservoir sands have porosities of 26 to 32% and permeabilities from 80 to 1600 md. Most of the field is quite shallow, with low natural drive. The Wilmington field grew by the addition of pools for the first 20 yr, with an estimated ultimate recovery of 1 billion bbl. By the mid-1960s, the ultimate oil recoverability increased to about 3 billion bbl because of additions from offshore expansion and increased productivity associated with the fieldwide water-flooding schemes. In the late 1980s, steam-flooding was introduced, and since 1988, both water-flooding and steam-flooding have produced most of the oil from Wilmington (Tennyson, 2005). Recently, new technologies, including horizontal drilling, LWD, and 3-D geologic modeling and visualization, along with continued secondary and tertiary recovery techniques, have continued to improve production efficiencies and extend the production life of the field (Clarke, 1999; Clarke and Phillips, 2003, 2004).

CONCLUSIONS AND FUTURE DEVELOPMENT Steam injection continues to be the favorite method for thermal recovery of heavy oil from California. With increased horizontal drilling, SAGD may be applied in combination with other thermal technologies, such as CSS and steam-flood, to maximize production through technology sequencing in many of these old heavy-oil reservoirs that are nearing the end of their production. Until now, most of the California oil sands have not been commercially developed. Although much of the in-situ steam technology was developed and applied in California to its heavy-oil reservoirs, to date this technology,

has not been, in general, done on the many significant oil-sand deposits in the state (Table 1). Elsewhere, integration of LWD technology has improved unconventional shale gas production for shale gas reservoirs through accurate well placement. The Monterey Formation is actually similar to many of these other unconventional shale plays such as the Woodford Shale of southeastern Oklahoma, which has complex layering, faults, and extensive sealed and open fractures. Three-dimensional seismic and geologic analyses are required to characterize the faults, dips, direction, and intensity of natural fractures for optimal lateral orientation of horizontal wells and completions strategies. In-situ technologies, such as SAGD and CSS, are routinely used in Alberta to produce the vast oil-sands deposits in northern Canada (Hein et al., 2013). These technologies have evolved to the extent that small-scale SAGD is being proposed for many of the smaller leases. Expansion of this type of production to California may be linked into existing infrastructures that are associated with heavy-oil production; in fact, the technologies are very similar to what has been done to rejuvenate the old Wilmington oil field horizontal drilling of multiple wells from a single pad and creation of larger steam chambers in the subsurface that coalesce along the well pairs to give a better conformance to the scheme. In many areas of California, the oil sands, heavy oil, and diatomites occur as separate play types within given fields or in close proximity to one another. These close associations of the diatomites and diatomaceous shales (which are most amenable to hydraulic fracking) make it possible to have full integration of the heavy-oil and oil-sand reservoirs, with deeper development by multistage, multifracing (diatomites), and overlying or laterally adjacent heavy oil and oil sands by SAGD, CSS with or without water-flood and steam-flood. At present, steam-enhanced heavy-oil production in California is in decline. Several other known California heavy-oil or oil-sand deposits have never been developed because it was initially thought that their viscosity was too high for steam or fire-flood to be effective. In-situ technologies such as SAGD or CSS are routinely used to develop the more highly viscous oil sands of Canada. Recently, the use of SAGD in the Oxnard field near Ventura, California, has been proposed. Other known heavy-oil and oil-sand deposits in California, where such technologies may be used, include the large Foxen oil (tar) sand, Santa Maria Basin, and the Arroyo Grande (Edna) in the Kern River area (among others, Table 1). Other prospective sources for California’s future oil production include those offshore undeveloped oil fields, such as those offshore the Santa Maria Basin, north of Point Conception, or undeveloped


fields north of the Channel Islands, San Miguel, Santa Rosa, and Santa Cruz. In the past, in California, technological advances allowed oil production to continue when conventional production declined by switching to heavy-oil production. Today, application of other technologies, such as SAGD, may be applied to the common oil-sand and seep deposits of California and, with technology sequencing with heavy-oil production, may increase or at least maintain California’s oil production. These onshore resources, along with additions from offshore leases, may allow California to again become selfsufficient with its own strategic resources.

ACKNOWLEDGMENTS The Energy Resources Conservation Board, Calgary, provided technical assistance and support. I thank Kevin Parks, Doug Boyler, Jon Schwalbach, and Daniel Schwartz for helpful suggestions to improve the manuscript and Dan Magee for digital graphics. Any use of trade, product, or firm names is for descriptive purposes only and does not imply endorsement by the author or the Alberta Government.

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