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The Many Lives of Belridge

Nearly declared dead by its owners only eight years after discovery, new technologies introduced over the past century allowed Southern California’s Belridge Field to grow into a prolific oil producer. Now, 101 years since that discovery, innovative insights into its varied reservoirs promise to keep Belridge productive well into the 21st century.
This article appeared in Vol. 9, No. 2 - 2012

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  • Discovery well photographed in 1912 (above) and the crowded nature of the field today (below). Source: Kern County Museum

  • Source: Jane Whaley



Located on an outcrop of oil-stained sand near a small stream bank in Southern California, the Belridge Oil Company Well No. 101 was started on March 11, 1911 and finished on April 21, 1911. The driller’s log shows the well penetrated 238m of clay, tar sand, oil sand, and shale. They perforated an oil sand interval from 198m to 231m in the Pleistocene Tulare Formation and the underlying Upper Miocene Monterey Formation diatomite. The well’s initial production was 100 bpd of 23.4° API gravity oil. This new field would be called South Belridge and the discovery of the North Belridge Field would follow one year later.

These were indeed humble beginnings for the field. The Belridge Oil Company’s own Valuation Report in 1919 stated, “...within ten years both pools will be commercially exhausted.” However, new steel derricks and diesel engines introduced in the late 1920s enabled safer and deeper wells to be drilled in the field. By 1934, the field held the deepest well drilled in the world at 3,468m. Consequently, new oil pools were discovered in the North Belridge Field and it remained an important petroleum resource throughout World War II.

Peak daily production for the 24 km long by 5 km wide field was 186,000 boe in 1986. Today, daily production is at 80,500 boe and the field has produced over 1.6 Bbo of the 6 Bbo in place. More than 25,000 wells have been drilled in the structure, giving Belridge the closest well spacing of any field in the world, with vertical and horizontal wells as close as 11.5m. Through the use of new technology and ideas, over 700 new wells have been drilled and completed each year since 2005 in an effort to recover much more oil. Also, after a gap of many years, new exploration wells are being drilled to look for deeper structural and stratigraphic traps.

The Belridge Field is located in Kern County, California, 75 km west of Bakersfield and 225 km north-west of Los Angeles. Four Kern County fields (shown in red) including Belridge, Midway-Sunset, Elk Hills, and Kern River have all produced over 1.0 Bbo. Source: Allan and Lalicata, 2011 AAPG Pacific Section

Kern County’s Colorful Oil History


The Lakeview Gusher photographed shortly after blowing out. Source: Kern County Museum The occurrence of oil and tar sands in the southern San Joaquin Valley has been known for centuries. Source: Malcolm Allan In the 1500s the Spanish explorers found Native American Indians gathering the very thick oil from natural seeps. Early settlers used the seeps along the well traveled route on the west side of the San Joaquin Valley to lubricate their wagon wheels. The first commercial production started in 1864 when small amounts of oil were refined into kerosene in the nearby farming town of Bakersfield, California. By 1877, the first oil wells were drilled in Kern County. Numerous fields were discovered in the following years including several giant oil fields that still rank near the top 10 ever discovered in the US. These include the Midway-Sunset Field in 1894, Kern River in 1899, Elk Hills and the Belridge South fields, both in 1911. The 1899 discovery from a shallow, hand-dug well near the bank of the Kern River really started the oil boom for the area. After that, wooden derricks sprang up north of Bakersfield and soon the Kern River production accounted for 70% of California’s oil production. By 1903, California was the country’s top oil producing state.

During these early times, drilling was occurring at a frantic and somewhat reckless pace across the area marked by numerous blowouts. Some of the notable blowouts included the Wild Goose Gusher, 1887, Shamrock Gusher, 1896, Blue Goose Gusher, 1898, and the Silvertip Gusher in 1909. The Lakeview Gusher in the Midway-Sunset Field blew on March 15, 1910. Drilled to a depth of 678m, this well came in with a roar that blew off the crown block with an estimated flow of 125,000 bpd. Soon the column of sand and oil six meters in diameter and 60m high completely enveloped all the well equipment. Crews built sandbag dams to contain the crude and in just four hours a four inch pipeline was built to convey oil to large holding tanks four km away. This well flowed for over 18 months and finally died when the bottom of the well caved in. An estimated 395 million gallons (1.1 MMm³) of crude were discharged on the surface to become the largest spill in US history, at least twice as much as the Deepwater Horizon disaster spilled into the Gulf of Mexico in 2010. Today, there is little evidence left from the Lakeview Gusher.

Many more fields were discovered in the Southern San Joaquin Valley over the decades following these first important discoveries. Thanks primarily to steam flooding, the San Joaquin Valley oil production peaked in 1985 at almost 300 MMbo/year, 256 MMbo/year for Kern County alone. By 1993, 16 Kern County fields had produced over 100 MMbo. Twelve refineries were built in Kern County to handle all this oil, with only two remaining today. The last major find in the area was made by Occidental in 2009. Located between the Elk Hills and Railroad Gap fields, the 150 MMboe Gunslinger discovery is the largest in over 30 years.

Belridge’s Early Lives


The diatomite reservoirs are composed of about 40% diatoms, 40% detrital quartz and feldspar, and 20% mixed layer clays. While having high, fluid-supported porosities greater than 50%, the formation is extremely tight with very small pore throats and permeabilities ranging from 0.1 to 1.0 mD. The developed area of the North and South Belridge fields gradually expanded over time until the two fields were joined. Source: Allan and Lalicata, 2011 AAPG Pacific Section Using wooden derricks and steam powered workings, drilling focused on the area around the original 1911 and 1912 discovery wells. After only eight years of development, Belridge Oil Company stated that the “Southern Belridge Field is entirely drilled up” and the “future production is estimated to be about 1,800,000 barrels”. Thus, the two Belridge fields remained very small in area. Only about 100 wells had been drilled in the south field by 1920 and only about 30 wells through 1930 for the northern field. The original discovery pools, the Tulare Formation that contained heavy 11–15° API oil and the Monterey diatomite pool with its much lighter 25–39° crude were often completed together. This completion method would allow the light oil from the diatomite zone to dilute the heavy oil in the Tulare and allow economic production of the heavy oil. This practice continued into the 1970s.

The Belridge Field’s second life was marked with the advent of more powerful steel drilling rigs that were able to reach objectives below the Tulare and Monterey diatomite reservoirs. The 1932 discovery of the sub-Monterey reservoirs (Miocene to Eocene) in the North Belridge Field was an important find, increasing both oil production and the productive area. The 650 km2 pool reached a peak daily production in 1938 at 38,600 boe. More producing intervals were discovered in the sub-Monterey in the 1940s and 1960s and today remain the deepest reservoirs in either field at 1,830 to 2,865m.

Cyclic steaming in the Tulare pool began in 1963 and marks yet another new life in the field’s production process. The cyclic steam stimulation involves initial steam injection into the heavy oil zone. After a soak period to heat the reservoir fluids, oil and some water flow back though the same well. The oil flows back at a dramatically reduced viscosity because of the added heat to the reservoir. Gradually larger areas are heated and the pattern can be converted to continuous steam injection with dedicated producers and injectors. A peak daily production rate of 186,000 boe was achieved in 1986; nearly 70% of it was from steaming the heavy oil.

More life from the oil field ensued with the first successful hydraulic fracture in the diatomite reservoir in 1977, followed by the use of water injection in the 1980s. The first horizontal wells were drilled in the early 1990s, keeping the field viable but producing only about half of what it did at its peak. Much oil remains locked in the ground, only about 25% of the oil-in-place has been produced, leaving more than 4 Bbo yet to be recovered.

Belridge – The Final Chapter?

Pictured at his Belridge workstation, Malcolm Allan, geologist and reservoir manager for Aera Energy claims, “Belridge’s next life requires applying conventional technologies and techniques in new and unconventional ways.” Shell purchased the assets of Belridge Oil Co. in 1979 and Aera Energy LLC was formed in 1997 from the Shell and Mobil assets in the area. Malcolm Allan has been working with the complex reservoirs at Belridge for 10 years. One of his first priorities was to organize all the geologic, petrophysical, and completion data into a single unified database. “We are using Landmark’s OpenWorks© database and Stratworks© plus Schlumberger’s Petrel programs,” says Malcolm. “The database contains over 15,000 wells and we are adding about 700 more each year. About 80% of the wells have digital logs that can be used to pick markers. The markers, porosity, oil saturation calculations and pressure surveys are in a single database that can be used by all our geoscientists. From this data, we can generate reservoir models and pseudo-logs (synthetic logs) necessary to pre-plan the wells and schedule completion intervals. On wells we have logged, the predictions have proven to be very accurate.”

At just under 50,000 bopd, the Monterey Formation diatomite reservoir is currently producing the most oil at Belridge. It is also a very unique reservoir and may be one of the first unconventional shale reservoirs to be produced commercially. “Fluids move very slowly through this reservoir at only 0.3 to 1.0m per year,” says Malcolm. “It has extremely high porosity, a large surface area per unit volume, and is highly compressible; all very challenging characteristics for a reservoir that can be 300 to 400m thick.”

“The first horizontal wells were aligned parallel to the anticline axis and completed with multiple transverse fracs,” explains Malcolm. “This area had limited productivity and since then nearly all our horizontal wells have been drilled along the flanks of the anticline and completed with longitudinal fracs along the wellbore. After multi-stage fraccing, these wells have proven to be very successful.”

“Water injection is essential to improve oil recovery and to maintain reservoir pressure to avoid compaction in the diatomite. With this massive, thick reservoir, accurate placement of injectors is warranted,” states Malcolm. “To solve this problem, we are using a multifaceted approach. Open-hole Repeat Formation Tester (RFT) data allows us to easily locate where additional injection support is needed to maintain hydrostatic formation pressure. In that same content, we are using satellite data every 24 days to compare surface subsidence caused by reservoir compaction. This allows us to monitor conformance of injection and production across the field. Additionally, we have 50 well pilot programs to monitor water injection profiles using distributed temperature sensing (DTS) with the optical fiber between the casing and cement. Full DTS deployment may involve over 1,000 wells. For active reservoir monitoring, microseismic arrays have been deployed to monitor fracture growth and cross-well tomography may be used in the future to detect changes in reservoir fluid content. These are clear examples how new technologies can solve surveillance issues in oil fields.”

“Going forward, and along with trying to recover more oil from existing reservoirs, Aera is drilling new exploration wells into deeper zones throughout the field,” says Malcolm. “To lower our environmental impact, the old gas-fired steam generators may soon be replaced with solar or biomass steam generation. We are also trying to minimize the surface impact with possible redevelopment by multilateral horizontal wells.”

A final life could occur at Belridge towards the end of this century with the recovery of heat from the steamed reservoirs using low temperature geothermal technology. Until then, Aera will continue to apply modern technologies to this giant field to keep producing oil from its huge remaining reserves.

Acknowledgement: Special thanks to Malcolm Allan for his valuable contributions to this article.

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