Chapter H of 

Geologic, Engineering, and Assessment Studies of Reserve Growth 

U.S. Geological Survey Bulletin 2172–H

Oil and Gas Exploration in the United States, 1998 

Each dot represents 

1 square mile 

Oil 

Gas 

Both 

Dry 

U.S. Department of the Interior

U.S. Geological Survey
i

Cover. This map represents historical oil and gas exploration and production data for 

the conterminous United States and Alaska. It was derived from data used in U.S. Geological 

Survey Geologic Investigations Series I-2582.* The map was compiled using Petroleum Information Corporation’s (currently IHS Corporation) database of more than 2.2 million wells 

drilled in the U.S. as of June 1993. The area of the U.S. was subdivided into 1 mi2 grid cells 

for which oil and gas well completion data were available. Each colored symbol represents 

a 1 mi2 cell (to scale) for which exploration has occurred. Each cell is identified by color as 

follows: red, a gas-producing cell; green, an oil-producing cell; yellow, an oil- and gas-producing cell; gray, a cell that has been explored through drilling, but no production has been 

reported. Mast and others (1998) gives details on map construction. 

*Mast, R.F., Root, D.H., Williams, L.P., Beeman, W.R., and Barnett, D.L., 1998, Areas of historical 

oil and gas exploration and production in the conterminous United States: U.S. Geological Survey 

Geologic Investigations Series I-2582, one sheet. 
Growth History of Oil Reserves in 

Major California Oil Fields During the 

Twentieth Century 

By M.E. Tennyson 

Chapter H of 

Geologic, Engineering, and Assessment Studies of Reserve Growth 

Edited by T.S. Dyman, J.W. Schmoker, and Mahendra Verma 

U.S. Geological Survey Bulletin 2172–H

U.S. Department of the Interior

U.S. Geological Survey
U.S. Department of the Interior

Gale A. Norton, Secretary 

U.S. Geological Survey

Charles G. Groat, Director 

U.S. Geological Survey, Reston, Virginia: 2005

Version 1.0, 2005 

This report is only available on-line at:


http://pubs.usgs.gov/bul/2172/h/


For more information about the USGS and its products:


Telephone: 1-888-ASK-USGS


World Wide Web: http://www.usgs.gov/


Any use of trade, product, or firm names in this publication is for descriptive purposes only and does not imply 


endorsement by the U.S. Government.


Although this report is in the public domain, permission must be secured from the individual copyright owners to 


reproduce any copyrighted materials contained within this report.

iv Contents


Abstract ................................................................................................................................................. 1


Introduction ........................................................................................................................................... 1


Data......................................................................................................................................................... 3


Analysis of Growth Patterns............................................................................................................... 3


San Joaquin Basin ...................................................................................................................... 3


Los Angeles Basin....................................................................................................................... 7


Coastal Basins ............................................................................................................................. 7


Offshore Fields ............................................................................................................................. 9


Discussion ............................................................................................................................................. 11


References Cited .................................................................................................................................. 12


Figures 

1. 	Index map of part of southern California showing the three regions discussed 


in the text.......................................................................................................................................... 2


2. 	Diagrams showing estimated ultimate recovery over time for giant fields in the 


San Joaquin Basin, plotted by calendar year and by number of years since 


discovery .......................................................................................................................................... 4


3. 	Plots for Midway-Sunset field showing number of producing wells, cumulative pro­


duction, and estimated ultimate recovery by year, and volumes of steam injected,


cumulative oil produced, estimated ultimate recovery, reserves, number of injection


wells, cumulative injection volume, and volume of oil production directly attribut­


able to thermal recovery................................................................................................................ 6


4. Diagrams showing estimated ultimate recovery over time for giant fields in


Los Angeles Basin, plotted by calendar year and by number of years since 


discovery .......................................................................................................................................... 8


5. Plot for Wilmington field showing number of producing wells, cumulative 


production, estimated ultimate recovery, reserves, volumes of water injected, 


and number of injection wells....................................................................................................... 10


6. 	Diagram showing estimated ultimate recovery over time for giant fields in coastal 


California basins .............................................................................................................................. 10


7. 	Diagram showing estimated ultimate recovery for offshore fields, all discovered 


between 1966 and 1981, plotted as a function of years since discovery .............................. 11


Tables 

1. 	Chronology of discoveries of pools and application of secondary and tertiary 


recovery programs in Midway- Sunset field............................................................................. 5 


2. Chronology of discoveries of pools and application of secondary and tertiary 


recovery programs in Wilmington oil field ................................................................................. 9


III 
Growth History of Oil Reserves in Major California 

Oil Fields During the Twentieth Century 

By M.E. Tennyson 

Abstract 

Oil reserves in 12 of California’s 52 giant fields (fields 

with estimated ultimate recovery >100 million barrels of oil) 

have continued to appreciate well past the age range at which 

most fields cease to show significant increases in ultimate 

recovery. Most of these fields were discovered between 1890 

and 1920 and grew to volumes greater than 500 million barrels 

in their first two decades. Growth of reserves in these fields 

accelerated in the 1950s and 1960s and is mostly explained by 

application of secondary and tertiary recovery techniques, primarily waterflooding and thermal recovery. The remaining 

three-fourths of California’s giant fields show a pattern of 

growth in which fields cease to grow significantly by 20–30 

years following discovery. Virtually all of these fields have 

estimated ultimate recoveries less than about 500 million barrels and most are in the 100–200 million barrel range. Three of 

six offshore giant fields, all discovered between 1966 and 1981, 

have shown decreases in their estimated ultimate sizes within 

about the first decade after production began, presumably 

because production volumes failed to match initial projections. 

The data suggest that: 

1. 	Only fields that attain an estimated ultimate size of several hundred million barrels shortly after discovery and 

have geologic characteristics that make them susceptible to advanced recovery techniques are likely to show 

substantial late growth. 

2. 	Offshore fields are less likely to show significant 

growth, probably because projections based on modern 

seismic reflection and reservoir test data are unlikely to 

underestimate the volume of oil in the field. 

3. 	Secondary and tertiary recovery programs rather than 

field extensions or new pool discoveries are responsible 

for most of the significant growth of reserves in 

California. 

4. 	Field size data collected over many decades provide a 

more comprehensive context for inferring reasons for 

reserve appreciation than shorter data series such as the 

Oil and Gas Integrated Field File (OGIFF) from the 

U.S. Department of Energy’s Energy Information 

Administration (EIA). 

5. Efforts to project future growth in California fields, and 

perhaps fields in other regions, should focus on evaluating the potential for enhanced recovery in fields with 

current estimated ultimate recoveries of about 250–500 

million barrels. 

6. 	By analogy with oil, attempts to project growth in gas 

reservoirs, in California and perhaps elsewhere, should 

focus on larger fields with lower permeability reservoirs where advances in recovery technology, such as 

perhaps horizontal drilling, are more likely to add substantial reserves. 

Introduction 

California oil fields have contributed a very large proportion of additions to domestic reserves in recent years. Almost 

half of additions to U.S. proved oil reserves in 1997 came from 

old fields in California (Anonymous, 1998). These fields were 

discovered between about 1890 and 1930 and contain mostly 

(but not exclusively) relatively heavy oil (<≈20° API). In the 

San Joaquin Basin (fig. 1), California’s most prolific basin and 

the only one in which much exploration has taken place since 

the mid-1980s, analysis of the Oil and Gas Integrated Field File 

(OGIFF) of the Department of Energy’s Energy Information 

Administration (EIA) indicates that 97 percent of additions to 

reserves in the 1980s came from reserve appreciation rather 

than discoveries (Caroline Isaacs, unpub. data, 1993). Methodology used in previous USGS national oil and gas assessments 

(Root and Mast, 1993; Attanasi and Root, 1994; Gautier and 

others, 1995) has not been entirely successful in projecting this 

growth. Without at least a qualitative understanding of the factors responsible for the late growth in these old fields, future 

assessments risk continued imprecise prediction of additions to 

reserves in this important region, along with perhaps undue 

influence on other regions stemming from failure to isolate factors peculiar to California. 
2 Geologic, Engineering, and Assessment Studies of Reserve Growth 

Coastal 

San 

Joaquin 

Los Angeles 

San Ardo 

Point Arguello 

Wilmington 

Midway-Sunset 

South 

Belridge Kern 

River 

Hondo 

Pescado 

Huntington 

Beach 

Long 

Beach 

Beta 

Santa Fe 

Springs 

Coalinga 

Dos Cuadras 

Carpinteria 

McKittrick 

Cymric Elk 

Hills 

Mount 

Poso 

Lost 

Hills 

121° 120° ° ° 

34° 

35° 

36° 

0 60 MILES 

Ventura 

119 118

Buena Vista 

30 

Figure 1. Index map of part of California showing the three regions discussed in text (Los Angeles Basin, coastal basins, and 

San Joaquin Basin), and outlines of giant fields. Names are shown for fields mentioned in text. 

The long-term growth history of the 52 giant oil fields in 

California provides a basis for determining what factors have 

contributed to growth of reserves and for observing styles in 

growth patterns that are functions of geologic or other characteristics of the fields. Comprehensive field chronologies, 

including annual data on cumulative production, reserves, and 

number of producing wells for each field, along with the history 

of discovery of new pools and areas (a term used in California 

for field extensions), abandonments of pools or areas, combination of multiple fields into single fields, and chronology of 

application of secondary and tertiary recovery techniques, provide a basis for inferring influences on reserve appreciation. In 

addition, growth histories can be examined to search for potential influences common to many fields, either geologic (for 

example, development of waterflooding technology in fields 

with good porosity and permeability and sufficiently light oil, 

or application of newly developed seismic reflection technology at mid-century to find stratigraphic traps) or strategic/economic (such as World War II, increases in the price of oil, or 

real estate value exceeding oil value), or, conceivably, regulatory (spacing rules, environmental policies). 

The information presented in this study, based on data 

compiled by Tennyson (1998), consists mostly of graphical displays of annual ultimate recovery estimates for California’s 52 

giant fields, supplemented with additional data for the relatively 

few fields that have grown more than about 200 million barrels 

after 30 years since discovery. For two fields that show marked 

growth, additional information was compiled, quantifying the 
Twentieth Century Reserve Growth in Major California Oil Fields 3 

extent to which secondary and tertiary recovery techniques 

were applied, in order to evaluate the association between 

reserve growth and enhanced recovery. 

Data 

Cumulative production volumes, reserve estimates, and 

numbers of producing wells were compiled annually as available, along with the chronology of discovery or abandonments 

of pools or areas and application of secondary recovery technology. The principal sources of production and reserves data 

were: 

1. 	An early paper containing the first published estimates 

of field sizes in California (Collum and Barnes, 1924) 

2. 	Production and reserves data published by the American Institute of Mining and Metallurgical Engineers 

(AIME) in the 1930s (Wilhelm, 1932, 1936, 1937, 

1938, 1939; Wilhelm and Miller, 1933, 1934) 

3. 	Annual production and reserves data published by the 

Oil & Gas Journal beginning in the mid-1940s (Oil & 

Gas Journal, 1946 to 1978) 

4. 	Annual production and reserves data published by the 

California Division of Oil and Gas (1977 to 1992) and 

California Division of Oil, Gas, and Geothermal 

Resources (1993 to 1999) 

The history of pools discovered within the fields and the chronology of secondary recovery programs undertaken in each 

pool were compiled from California Division of Oil and Gas 

(1991b) and California Division of Oil, Gas, and Geothermal 

Resources (1998). 

Data were organized as tables and plots, both for individual fields (Tennyson, 1998), and for all the giant fields in three 

general areas of the State—Los Angeles Basin, San Joaquin 

Basin, and coastal basins, as well as the six offshore fields (fig. 

1). The plots were used to identify fields that showed unusual 

growth patterns. The exploration, development, and advanced 

recovery histories of these less typical fields were briefly investigated in order to hypothesize responsible factors. 

Analysis of Growth Patterns 

San Joaquin Basin 

Of the 21 giant fields in the San Joaquin Basin, five stand 

out as having shown substantial growth, late in their histories—Coalinga, South Belridge, Elk Hills, Kern River, and 

Midway-Sunset (fig. 2). These fields, all discovered between 

1887 and 1919, grew by factors of 1.8 to 17 between 1950 and 

1995, with increases in estimated ultimate recovery (EUR) 

ranging from 400 million barrels to 1.8 billion barrels. Each of 

the other giant fields in the San Joaquin Basin grew by less than 

233 million barrels during the period 1950–1995: four fields 

(Cymric, Lost Hills, McKittrick, and Mount Poso) grew by 

volumes ranging from 180 to 233 million barrels, and the 

remainder grew by volumes generally less than 100 million barrels. Seven grew very little; of these, four are fields that barely 

exceed 100 million barrels of estimated ultimate recovery. 

Midway-Sunset, discovered in the 1890s, is by far the largest of these fields that show late growth. The first published 

estimate of its size was just under 1 billion barrels in the 1930s. 

New pools continued to be discovered into the 1950s, and minor 

pools were discovered as late as 1983 (table 1). The Buena 

Vista Area of the field was split off as a separate field in the 

1950s. In the early 1960s, operators began pilot cyclic steam 

projects, which proved sufficiently successful that cyclic steam 

recovery operations became widespread throughout the field 

(Rintoul, 1995). Fireflooding was attempted in several pools in 

the 1970s with some success. The development of steamflooding in the 1960s and 1970s, however, was clearly the most significant cause of reserve growth. Reserves were revised 

upward repeatedly beginning in the late 1960s (fig. 3), at a 

much greater rate than had typified the earlier period of growth 

by new pool discovery. An upward revision in 1991 of 500 million barrels of oil was followed in 1999 by another jump in 

reserves of more than 700 million barrels. From 1988 to 1998, 

about 80 percent of the oil produced at Midway-Sunset (477 

million of 600 million barrels produced) was “incremental” 

production attributable to enhanced recovery. In the last several 

years, operators have been experimenting with horizontal wells 

within steamfloods, but no clear results have yet emerged; a 

new era of reserve additions is possible if these experiments 

prove successful. 

Oil gravities reported from the pools in Midway-Sunset 

field where steamflood operations are in progress range from 8° 

to 14° API; most are 11°–13° API. Porosity in reservoir sands 

is typically 30–35 percent and permeabilities range from a few 

hundred to several thousand millidarcies. The field is quite shallow for such an immense accumulation—few wells penetrate 

below about 7,000 ft (Lennon, 1990), so reservoir temperatures 

are relatively low, some under 100°F. Thus, the field presents 

an ideal situation for thermal recovery: excellent reservoir properties but heavy, relatively cool oil. 

The Kern River field is another old field containing dominantly heavy oil (10°–16° API). It was discovered in 1899; a 

gradual decline in production rates over the next 60 years was 

suddenly reversed in the 1960s when steamflooding was introduced. By the early 1980s, the field’s daily production was 

almost three times what it had been in the initial decade after 

discovery (Rintoul, 1999). 

The striking growth in South Belridge field has been 

driven by two independent advances in recovery technology: 

steamflooding and diatomite fracturing. The field produces 

from two principal reservoirs, shallow Pleistocene deltaic sands 

that contain heavy oil (13°–14° API), and deeper diatomaceous 

mudstone in which the oil is lighter (20°–32° API). From discovery in 1911 until about 1950, the field grew by areal expansion, to an EUR of about 80 million barrels, mainly from the 
4 Geologic, Engineering, and Assessment Studies of Reserve Growth

A

1900 1910 1920 1930 1940 1950 1960 1970 1980 1990 2000

YEAR

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

ESTIMATED ULTIMATE RECOVERY, 

IN THOUSANDS OF BARRELS 

0

5

10

15

20

25

30

35

NOMINAL OIL PRICE, IN DOLLARS

Coalinga (1890)

Coalinga East (1938)

Coles Levee North (1938)

Cymric (1909)

Edison (1928)

Elk Hills (1911)

Fruitvale (1928)

Greeley (1936)

Kern Front (1912)

Kern River (1899)

Kettleman North Dome (1928)

Lost Hills (1910)

McKittrick (1896)

Midway-Sunset (1894)

Mount Poso (1926)

North Belridge (1912)

Rio Bravo (1937)

Round Mountain (1927)

South Belridge (1911)

Nominal Oil Price (EIA)

MidwaySunset

Kern River

Elk Hills 

South 

Belridge

Coalinga

EXPLANATION

Yowlumne (1974)

Buena Vista (1909)

Buena Vista (1909)

Coalinga E Extension (1938)

Coles Levee N (1938)

Cymric (1909)

Edison (1928)

Elk Hills (1919)

Fruitvale (1928)

Greeley (1936)

Kern Front (1912)

Kern River (1899)

Kettleman North Dome (1928)

Lost Hills (1910)

McKittrick (1896)

Midway-Sunset (1890)

Mount Poso (1926)

North Belridge (1912)

Rio Bravo (1937)

Round Mountain (1927)

South Belridge (1911)

Yowlumne (1974)

Coalinga (1887)

EXPLANATION Midway-Sunset

Elk Hills 

Kern River

South Belridge

Coalinga

0

0 10 20 30 40 50 60 70 80 90 100 110

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

YEARS SINCE DISCOVERY 

ESTIMATED ULTIMATE RECOVERY, 

IN THOUSANDS OF BARRELS

120

B

Figure 2 . Estimated ultimate recovery (EUR) over time for giant fields in the San Joaquin Basin, plotted A, by calendar 

year, and B, by number of years since discovery. Most fields achieved their giant status within two or three decades of 

discovery and did not grow significantly thereafter. A few larger fields, however, most of which achieved EUR’s of 

close to 500 million barrels within a few decades of discovery, have shown substantial increases in EUR beginning 

about age 60–70. This “late” growth is largely accounted for by improvement in recovery efficiency attributable to enhanced recovery programs.
Twentieth Century Reserve Growth in Major California Oil Fields 5 

Table 1. Chronology of discoveries of pools and application of secondary and tertiary recovery programs in Midway-Sunset oil field. 

Year Discoveries Secondary and tertiary recovery 

1894 Tulare pool discovered 

1902 Monarch pool discovered

1909 Gusher pool discovered 

1910 Potter and Lakeview pools discovered 

1913 Webster pool discovered 

1920 Mya Tar pool discovered 

1922 Calitroleum pool discovered 

1925 Obispo pool discovered 

1928 Republic pool discovered 

1936 Sub-Lakeview pool discovered 

1941 Marvic pool discovered 

1945 Leutholtz pool discovered 

1947 Pacific pool discovered 

1954 Waterflood started- Calitroleum pool 

1957 Moco pool discovered Waterflood started- Monarch pool 

1959 

1960 

1961 

1962 

1963 

1964 

Fireflood started- Moco pool 

Fireflood started- Top Oil pool 

Firefloods started- Webster, Monarch, and Tulare pools; waterflood started- Kinsey pool 

Steamfloods, cyclic steam started- Tulare, Mya Tar, Top Oil, sub-Lakeview, Potter, Marvic, and

 Webster pools 

Waterflood discontinued- Calitroleum pool 

1965 Steamfloods started- Webster and Moco pools; steamflood, cyclic steam started- Monarch pool; 

cyclic steam started-Kinsey and Leutholtz pools; waterflood 

discontinued- Monarch pool; cyclic steam discontinued- Kinsey pool 

1967 Steamfloods started- Tulare and Kinsey pools; waterflood started- Top Oil pool; waterflood 

discontinued- Kinsey pool 

1968 Steamflood and fireflood started- Potter pool 

1969 Waterflood started- Potter pool 

1970 Steamflood started- Leutholtz pool 

1972 Steamflood started- sub-Lakeview pool; waterflood discontinued- Top Oil pool 

1975 Antelope Shale pool discovered 

1976 Fireflood started- sub-Lakeview pool 

1977 Pioneer pool discovered 

1979 Pulv pool discovered Cyclic steam started- Top Oil pool 

1980 Pulv pool abandoned (one well) 

1981 Fireflood discontinued- Top Oil pool 

1982 Pioneer pool abandoned (one well) Cyclic steam discontinued- Top Oil pool; waterflood started- Calitroleum pool 

1983 Waterflood discontinued- Calitroleum pool 

1984 McDonald Shale pool discovered 

1985 Waterfloods started- Tulare and Monarch pools 

1986 Steamflood started- Marvic pool 

1991 Waterflood started- sub-Lakeview pool; waterflood discontinued- Tulare pool 

1992 Waterflood discontinued- Monarch pool 

1994 Steamflood discontinued- Top Oil pool 

1996 Fireflood discontinued- Webster pool

shallow heavy oil reservoir; the diatomite reservoir had been 

discovered but did not produce at economic rates. In the 1950s, 

a pilot in-place combustion project demonstrated that 40–60 

percent of the oil in place in the heavy oil reservoir could be 

recovered (Miller and McPherson, 1992). A cyclic steam 

project began in the early 1960s, and steamfloods in the 1970s 

and 1980s pushed EUR to about 400 million barrels—about 40 

percent of the oil in place in the shallow reservoir. During the 

1970s, methods of successfully fracturing the diatomite were 

developed. A new operator bought the field in 1979 and began 

major redevelopment, including intensive development of the 

diatomite. EUR almost tripled, to about 1.1 billion barrels by 

1990, as the previously unrecoverable oil in the diatomite was 

added to reserves. During the 1990s, expansion of steamflooding, waterflooding in the diatomite, and infill drilling combined 

to drive expected recovery to 1.9 billion barrels. 

The histories of the other old San Joaquin fields in which 

significant late growth has taken place were not studied in any 
6 Geologic, Engineering, and Assessment Studies of Reserve Growth 

1900 2000 

A 

0 

500,000 

1,000,000 

1,500,000 

2,000,000 

2,500,000 

3,000,000 

3,500,000 

4,000,000 

1910 1920 1930 1940 1950 1960 1970 1980 1990 

YEAR 

THOUSANDS OF BARRELS 

0 

2,000 

4,000 

6,000 

8,000 

10,000 

12,000 

14,000 

16,000 

18,000 

20,000 

NUMBER OF WELLS 

Estimated ultimate recovery 

Cumulative production 

Number of producing wells 

thermal recovery EXPLANATION 

B 

0 

500,000 

1,000,000 

1,500,000 

2,500,000 

3,000,000 

3,500,000 

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

YEAR 

THOUSANDS OF BARRELS 

0 

5,000 

10,000 

15,000 

20,000 

NUMBER OF INJECTION WELLS 

Annual injection volume 

Estimated ultimate recovery 

Reserves 

Number of injection wells 

EXPLANATION 

Cumulative oil production 

Cumulative injection volume 

Incremental oil production from 

thermal recovery 2,000,000 

Figure 3. Plots for Midway-Sunset field showing A, number of producing wells, cumulative production, and estimated ultimate recovery by year, and B, volumes of steam injected, cumulative oil produced, estimated ultimate recovery, 

reserves, number of injection wells, cumulative injection volume, and volume of oil production directly attributable to 

thermal recovery (“incremental oil”). Reserves began to be added after thermal recovery was started. (Data on thermal recovery from California Division of Oil, Gas, and Geothermal Resources annual publications.) 
Twentieth Century Reserve Growth in Major California Oil Fields 7 

detail, beyond noting that enhanced recovery operations are 

widespread in these fields. Late growth in these fields is almost 

certainly due to enhanced recovery as it so clearly is in MidwaySunset, Kern River, and South Belridge fields. 

Los Angeles Basin 

In the Los Angeles Basin (fig. 4), 12 of the 16 giant fields 

reached ultimate sizes between 100 and 500 million barrels 

within the first few decades after discovery and did not grow 

significantly thereafter. Two fields, Santa Fe Springs and Long 

Beach, attained sizes significantly larger than most of the rest, 

but did not grow very much after age 25–30. One field, Huntington Beach, grew past the 1 billion barrel mark at about age 

50 and continued to grow in increments totaling almost 300 million barrels until about age 65; waterflooding was begun in this 

field at about age 40 and appears to be the most probable cause 

of this late growth. By far the most spectacular example of field 

growth in the Los Angeles Basin is the Wilmington field (fig. 5; 

see Mayuga, 1970, for details of field history). Discovered in 

1932, this field grew for its first two decades as 12 pools were 

discovered and developed (table 2), reaching an estimated ultimate recovery of 1 billion barrels at age 20 in 1952. A pilot 

waterflooding program began the following year in an attempt 

to halt rapid ground subsidence that had developed over the previous decade as a result of high production rates related to wartime needs; the ground surface had subsided about 30 ft during 

the 1940s. By the mid 1950s, the results of the waterflooding 

pilot programs indicated that subsidence had slowed to virtually 

negligible rates, so unitization agreements were negotiated during the 1950s that would allow for field-wide waterflooding 

projects. A 1954 seismic survey of the offshore area adjacent to 

the field showed that the trapping anticline continued several 

miles offshore, but expansion could not proceed until local 

authorities were satisfied that subsidence could be avoided. By 

1960, it was clear that waterflooding was effective in stopping 

and preventing subsidence; between 1960 and 1965, the City of 

Long Beach developed contractual arrangements for offshore 

expansion, which began in 1965. In 1963, the estimated ultimate recovery of the previously developed part of the field was 

1.16 billion barrels of oil; 3 years later, in 1966, as the increase 

in oil recoverability caused by waterflooding became evident 

and the reserves due to offshore expansion were added, the estimated ultimate size of the field approached 3 billion barrels (fig. 

5). This included 1.16 billion barrels already produced from the 

onshore area, an additional 0.5–0.7 billion barrels projected in 

the onshore area as a direct consequence of waterflooding, and 

an additional 1.0–1.2 billion barrels from the offshore expansion (Mayuga, 1970). Steamflooding was introduced in a few 

pools in the 1980s. Since 1988, two-thirds of the oil produced 

at Wilmington has resulted from waterflooding and steamflooding (California Division of Oil, Gas, and Geothermal 

Resources, 1988–1998)—150.8 million barrels of the 226.1 

million barrels produced between 1988 and 1998; waterflooding accounted for 93 percent of this incremental oil. The success of waterflooding at Wilmington is apparently attributable 

to good reservoir character along with lack of a natural water 

drive. Porosities in these weakly consolidated submarine fan 

sands are mostly in the 26–32 percent range; permeabilities vary 

widely, from about 80 mD in one pool to 1,000–1,600 mD in 

two of the larger pools (Ranger and Tar). Oil gravity varies considerably: oils in shallower pools have gravities as low as 12°– 

14° API, and some oils in the field are as light as 25°–32° API. 

The oil in the biggest pools onshore (Ranger and Tar) ranges 

from 12° to 25° API (California Division of Oil and Gas, 

1991b), and the offshore Ranger pool, which contains threefourths of the oil in the offshore unit, ranges between 15° and 

20° API (Berman and Clark, 1987). Thus, although these oils 

are somewhat heavy, they are apparently light enough that the 

artificial water drive supplied by waterflooding brought about a 

substantial increase in recovery. 

The original volume of oil in place (OOIP) at Wilmington 

was about 9 billion barrels (Bbbl). (Available estimates are 

9.6931 Bbbl (Anonymous, 1980), and 8.8 Bbbl (Montgomery, 

1998)). Thus the current EUR of almost 2.8 Bbbl represents a 

recovery efficiency of about 29–32 percent for the field as a 

whole. Berman and Clarke (1987) estimated that the OOIP in 

the offshore part of the field (Long Beach Unit) was 3.8 billion 

barrels, so the OOIP in the onshore part of the field was evidently about 5–6 Bbbl. By the 1990s, cumulative production 

plus proved reserves were about 1.3 Bbbl in the onshore part 

and about 1.5 Bbbl in the offshore part, which suggests recovery 

efficiencies of as much as 26 percent for the onshore and 40 percent for the offshore. It seems likely that the higher recovery 

efficiency for the offshore is due to the inclusion of waterflooding from the beginning of development. The 1952 pre-waterflooding EUR for the onshore part of the field was about 1 Bbbl; 

waterflooding has added about 300 MMbbl (million barrels) to 

the ultimate recovery (about 6 percent of OOIP). This is less 

than the 500–700 MMbbl projected by Mayuga (1970) and is a 

relatively minor part of the overall increase since the mid1960s; most of the fieldwide increase in EUR came from the 

addition of the oil in the offshore unit with its higher recovery 

efficiency. 

Coastal Basins 

Two fields in the coastal province have grown by more than 

about 200 million barrels—the Ventura field and the San Ardo 

field (fig. 6). The Ventura field in the Ventura-Santa Barbara 

Basin, discovered in 1919, grew by seven new pool discoveries 

between 1922 and 1952, reaching an estimated size of about 800 

million barrels at the end of this period. The first waterflood 

project was begun in 1956. Five more of the total of eight pools 

were waterflooded in the 1960s and 1970s; all are still active. 

These waterflooding projects appear to have accounted for much 

of the additional 200 million barrels of reserves that the field 

gained in the 1970s and 1980s; about 21 million barrels in 

reserves were added as recently as the 1990s. Over the last 

decade, 89 percent (49 million barrels) of the 56 million barrels 

produced was incremental oil from waterflooding. Oil gravity 

is around 30° API in all pools. Porosity is about 15–20 percent 
8 Geologic, Engineering, and Assessment Studies of Reserve Growth

1890

Wilmington

Huntington

Huntington Beach (1920)

Long Beach (1921)

Santa Fe Springs (1919)

Brea-Olinda (1880)

Inglewood (1924)

Dominguez (1923)

Coyote, West (1909)

Montebello (1917)

Richfield (1919)

Beverly Hills (1900)

Torrance (1922)

Beta Offshore (1976)

Coyote, East (1909)

Seal Beach (1924)

Yorba Linda (1930)

Wilmington (1932)

EXPLANATION

A

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

1900 1910 1920 1930 1940 1950 1960 1970 1980 1990 2000

YEAR

ESTIMATED ULTIMATE RECOVERY, 

IN THOUSANDS OF BARRELS

Long Beach

Santa Fe Springs

B

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

0 10 20 30 40 50 60 70 80 90 100 110 120 130

YEARS SINCE DISCOVERY

ESTIMATED ULTIMATE RECOVERY,

 IN THOUSANDS OF BARRELS

Beta Offshore (1976)

Beverly Hills (1900)

Brea-Olinda (1880)

Coyote, East (1909)

Coyote, West (1909)

Dominguez (1923)

Huntington Beach (1920)

Inglewood (1924)

Long Beach (1921)

Montebello (1917)

Richfield (1919)

Santa Fe Springs (1919)

Seal Beach (1924)

Torrance (1922)

Yorba Linda (1930)

Wilmington (1932)

EXPLANATION

Santa Fe Springs 

Wilmington

Huntington Beach

Long Beach

Figure 4. Estimated ultimate recovery (EUR) over time for giant fields in the Los Angeles Basin, plotted A, by calendar 

year, and B, by number of years since discovery. Most fields achieved nearly their current ultimate sizes within two or 

three decades of discovery. Wilmington field, in contrast, approximately doubled in estimated ultimate size, beginning at 

about age 30, because of widespread application of waterflooding technology, originally applied to halt surface subsidence. Huntington Beach field also grew appreciably during its fourth, fifth, and sixth decades, apparently also as a result 

of successful waterflooding programs.
Twentieth Century Reserve Growth in Major California Oil Fields 9 

Table 2. Chronology of discoveries of pools and application of secondary and tertiary recovery programs in Wilmington oil field. . 

Year Onshore area discoveries Offshore area discoveries Secondary and tertiary recovery 

1932 Ranger pool discovered 

1936 Upper Terminal pool 

discovered 

1937 Ford, Tar pools discovered 

1938 Lower Terminal pool discovered 

1939 Ranger, Upper Terminal pools 

discovered 

1942 Union Pacific pool discovered 

1943 Tar pool discovered 

1945 237, Schist pools discovered 237, Schist, Ford pools 

discovered 

1946 

1947 Union Pacific pool discovered 

1953 Waterflood started- Upper Terminal/Onshore 

1954 Waterflood started- Tar/Onshore 

1956 Waterfloods started- Ranger and Lower Terminal/Onshore; 

Lower Terminal/Offshore 

1958 Waterfloods started- Ford, Union Pacific/Onshore; Tar, 

Ranger, Upper Terminal, Union Pacific, Ford/Offshore 

1960 Waterfloods started- 237/Onshore and Offshore 

1967 Steamflood started- Ranger/Onshore 

1969 Polymer flood started- Ranger/Onshore 

1972 

Polymer flood discontinued- Ranger/Onshore; waterflood 

discontinued- 237/Offshore 

1979 Shallow gas sand pool 

discovered 

Polymer-micellar flood started- Upper Terminal/Onshore 

and Offshore 

1981 CO2 waterflood started- Tar/Onshore; polymer-micellar 

flood discontinued- Upper Terminal/Onshore and Offshore; waterflood discontinued- Ford/Offshore; steamflood started- Tar/Offshore 

1982 

1989 CO2 -WAG flood discontinued- Tar/Offshore 

Steamflood started- Tar/Onshore; CO2 WAG flood 

started- Tar/Offshore 

in all pools and permeability is 8.8–48 mD. The two 100-million-barrel increases in estimated ultimate recovery in the early 

1970s and early 1980s apparently resulted from waterflooding. 

Although this is a significant amount of oil, it is a minor proportion compared to the 800 million barrels from new pool discoveries between 1919 and 1952. It represents about a 6 percent 

increase in recovery efficiency based on Hacker’s (1969) OOIP 

of 3.5 Bbbl, from 23 percent to 29 percent. 

The San Ardo field in the Salinas Basin was discovered in 

1947. All three of its oil pools were discovered by the following 

year; most of the oil is contained in one pool (Lombardi) that 

has an oil gravity of about 10° API, porosity of 23–37 percent, 

and permeabilities of 2,000–3,000 mD. About a decade after 

discovery, the ultimate recovery of the field was estimated to be 

about 200 million barrels, but after thermal recovery programs 

were begun in the 1960s, its ultimate size more than doubled to 

about 530 million barrels by the mid-1970s. 

Offshore Fields 

The six California giant fields that lie offshore were all 

discovered between 1966 and 1981. They are thus just 

emerging from the 2–3 decade-long interval in which older 

onshore fields tended to show rapid growth, although delays 

were unusually long between discovery and initial production at Hondo, Pescado, and Point Arguello fields. These 

delays were in part due to lengthy field delineation programs 

and in part to permitting delays stemming from environmental issues. Hondo and Dos Cuadras have grown irregularly, 

Pescado has not been on production long enough for a trend 

to emerge, and Point Arguello, Beta, and Carpinteria have 

shrunk (fig. 7). Point Arguello’s operator sold the field in the 

late 1990s after disclosing that production had declined faster 

than anticipated, despite attempts to slow the decline by reinjection of produced gas. The rate at which production would 
10 Geologic, Engineering, and Assessment Studies of Reserve Growth

2000

Ventura (30° API) 

San Ardo (10°-13° API)

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

1900

ESTIMATED ULTIMATE RECOVERY,

 IN THOUSANDS OF BARRELS

1910 1920 1930 1940 1950 1960 1970 1980 1990

YEAR

0

5

10

15

20

25

30

35

NOMINAL OIL PRICE, IN DOLLARS

Carpinteria (1966)

Cat Canyon (1908)

Dos Cuadras (1968)

Elwood (1928)

Hondo Offshore (1969)

Orcutt (1901)

Pescado Offshore (1970)

Point Arguello Offshore (1981)

Rincon (1927)

San Ardo (1947)

San Miguelito (1931)

Santa Maria Valley (1934)

South Cuyama (1949)

South Mountain (1916)

Ventura (1919)

Nominal Oil Price (EIA)

Cat Canyon 

(6°-22° API)

waterflooding

begun 

1956 

last 

pool 

discovered

1952 

EXPLANATION

0

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

12,000,000

14,000,000

16,000,000

1940 1950 1960 1970 1980 1990 2000

YEAR

THOUSANDS OF BARRELS

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

NUMBER OF WELLS

Cumulative volume of water injected

Estimated ultimate recovery 

Cumulative production 

Reserves

EXPLANATION

Volume of water injected

Number of wells

Number of injection wells

1930

Figure 5. Plot for Wilmington field showing number of producing wells, cumulative production, estimated ultimate 

recovery, reserves, volumes of water injected, and number of injection wells. Breaks in curves represent years for 

which data were not available.

Figure 6. Estimated ultimate recovery (EUR) over time for giant fields in coastal California basins. Late growth in 

Ventura field (oil gravity 30° API) is attributable to waterflooding and in San Ardo field (10°–13° API) to development of 

thermal recovery technology. 
Twentieth Century Reserve Growth in Major California Oil Fields 11 

0 

50,000 

100,000 

150,000 

200,000 

250,000 

300,000 

350,000 

400,000 

450,000 

500,000 

0 5 10 15 20 25 30 35 40 

YEARS SINCE DISCOVERY 

ESTIMATED ULTIMATE RECOVERY, THOUSANDS OF BARRELS

Dos Cuadras (1968) 

EXPLANATION 

Hondo Offshore (1969) 

Pescado Offshore (1970) 

Carpinteria (1966) 

Beta Offshore (1976) 

Point Arguello Offshore (1981) 

Figure 7. Estimated ultimate recovery for offshore fields, all discovered between 1966 and 1981, plotted against number of years since 

discovery. 

decline was apparently difficult to predict, because the reservoir consists of fractured Miocene chert with highly variable 

permeability. 

It seems significant that three of six offshore fields show 

negative growth. Several of them are in the early stages of secondary recovery, so it is possible that they may yet grow again. 

Nevertheless, it seems likely that development projections were 

overly optimistic on the part of the operators, and that production has not met the predicted levels. This is a very different situation than in the old onshore fields, where few initial attempts 

were made to evaluate ultimate productivities and development 

proceeded in a more erratic fashion as economic conditions 

warranted. 

Discussion 

The data presented here show that roughly three-quarters 

of the 52 giant fields in California have followed a pattern of 

rapid growth in the first two or three decades after discovery, 

followed by decelerating growth in subsequent decades. Most 

of these are the smaller fields in the data set, those whose estimated ultimate recoveries do not greatly exceed 100 million 

barrels. In contrast, the largest fields have continued to exhibit 

significant jumps in reserves. Increases early in the fields’ histories were typically associated with discovery of new pools 

and field extensions, whereas most of the abrupt increases in 

estimated ultimate recovery since the 1950s were associated 

with application of secondary recovery technology, primarily 

waterflooding and steamflooding. These “late” increases are 

generally much larger than contributions made by new pool discoveries—some fields have doubled in estimated ultimate 

recovery as enhanced recovery programs were applied. Offshore fields discovered in the last 30 years have not generally 

shown the rapid growth typical of older onshore fields, perhaps 

because extensive studies of ultimate recovery preceded the 

operator’s decisions to develop the fields. 

The element responsible for “late” reserve growth, then, is 

an increase in recovery efficiency. In California, recovery efficiencies are generally low, estimated at 5–30 percent without 

enhanced recovery programs (California Division of Oil, Gas, 

and Geothermal Resources, 1993b). Data from individual 

fields on volumes of oil originally in place or recovery efficiencies are not generally available, but the few published estimates 

imply 50–100 percent increases in recovery. Estimates referred 

to in the discussion of the Wilmington field suggest an increase 

in recovery efficiency from about 26 percent to 40 percent. 

Lennon (1990) reported estimates for Midway-Sunset field of 

approximately 4.4 billion barrels of oil originally in place, with 
12 Geologic, Engineering, and Assessment Studies of Reserve Growth 

2.25 billion barrels (51 percent) ultimately recoverable; he 

attributed about half of cumulative production as of 1986 to primary recovery and half to secondary recovery. Schamel and 

others (1998) referred to typical heavy oil recovery efficiencies 

of 40–70 percent in steamflooded Midway-Sunset reservoirs. 

The doubling in EUR in several fields after enhanced recovery 

began suggests that recovery efficiencies must have roughly 

doubled, because there are no other apparent causes for the 

increases in EUR. 

The price of oil does not appear to have been directly 

responsible for the more significant reserve increases in the 

largest fields, because big jumps in estimated ultimate recovery 

that were clearly associated with enhanced recovery programs 

begun in the 1950s and 1960s (at Midway-Sunset, Kern River, 

Wilmington, and Ventura) preceded inflation of oil prices in the 

1970s. Furthermore, substantial increases in ultimate recovery 

have continued through the late 1980s and 1990s despite the 

weakening of oil prices during that interval. 

The data do not, in any obvious way, point to other controlling influences on reserve appreciation patterns, such as developments in exploration technology, changes in social priorities, 

economic developments, or strategic needs. Most fields for 

which reserves data from the 1930s and 1940s exist show some 

increase in size during the war years of the 1940s, but these 

increases were relatively minor compared to those associated 

with secondary or tertiary recovery programs initiated since the 

1950s in the largest fields. No effects are apparent of more 

stringent environmental regulations that began to be imposed in 

the 1970s, unless one speculates that more fields would have 

shown significant late growth from enhanced recovery if environmental regulations had not been tightened. The use of seismic reflection technology to improve the understanding of subsurface stratigraphy and structure does not appear to have been 

associated with any particular episodes of reserve growth; as the 

quality of seismic data has improved over the last several 

decades, the number of new pools discovered in existing fields 

has dwindled, and most of those discovered have not had a significant effect on the field size. 

The data summarized here provide a different perspective on reserve appreciation from that of another principal 

source of data on field size, the confidential Oil and Gas Integrated Field File (OGIFF) maintained by the Energy Information Administration of the U.S. Department of Energy. In 

addition to its unavailability to most workers, a major shortcoming of the OGIFF database is that it dates only from 

1977—after the 1950s and 1960s development of major secondary and tertiary recovery programs and the mid-1970s 

jump in oil prices—so it provides little information that can 

be used to infer influences on earlier growth in old or even 

moderately old fields. 

As increase in recovery efficiency appears to be the principal cause of the extreme growth shown by a handful of old 

California fields, future studies of reserve growth potential 

should include attempts to identify the geologic characteristics 

responsible for reservoirs in which primary recovery produces 

only a low fraction of the oil in place. The most obvious of 

these is oil gravity, but depositional setting may also be important—most of the late-growth California reservoirs are submarine fan turbidites, for instance. In addition, fields that achieve 

sizes of at least several hundred million barrels of oil within the 

first three decades after discovery appear to be the ones in 

which late growth is most likely to occur. 

Whether or not reserve growth in California—which is a 

very large proportion of such growth nationally in the United 

States—will continue at its recent rapid pace is not clear. Obviously, increases in recovery efficiency cannot continue indefinitely, so if we assume that the currently achieved recovery efficiencies are approaching their limits, the principal potential for 

increases in reserves should lie in parts of fields where current 

enhanced recovery techniques have not yet been applied. We 

can speculate that growth in California fields may begin to slow 

soon, as enhanced recovery programs are fully deployed and 

sweep the last recoverable volumes of oil from the reservoirs. 

California’s giant heavy oil fields offer little insight into 

the potential for reserve appreciation in other regions or in gas 

accumulations, but if, as shown here, improvement in recovery 

efficiency has as much as doubled estimated ultimate recovery 

in individual California fields, the identification of oil or gas 

reservoirs with low primary production recovery efficiencies 

should be a key to improving our ability to estimate future 

reserve growth. These presumably include mainly low permeability oil and gas accumulations and heavy oil accumulations. 

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