The U.S. Geological Survey (USGS) assessed how much undiscovered, technically recoverable oil and gas — conventional and continuous (unconventional) — may remain in the Santa Maria Basin Province on California's central coast. The assessment covers the province's onshore part and state waters, not the federal offshore.
The answer
| Resource | Mean estimate | Range (F95–F5) |
|---|---|---|
| Oil | 67 million barrels | 13–218 million barrels |
| Natural gas | 56 billion cubic feet | 11–183 billion cubic feet |
| Natural gas liquids | 4 million barrels | 1–14 million barrels |
F95 means a 95% chance of at least that much; F5, a 5% chance. By assessment unit:
| Assessment unit | Oil, mean | Gas, mean | Probability the unit holds resources |
|---|---|---|---|
| Santa Maria Basin Conventional Reservoirs | 65 million barrels | 55 billion cubic feet | 1.0 |
| Santa Maria Basin Continuous Oil | 2 million barrels | 1 billion cubic feet | 0.9 |
An old oil region
Exploration here goes back a long way: the Orcutt field was found in 1901, guided by oil seeps. Most fields were discovered by 1956, and one more conventional field was added in 1984.
The two assessment units in the Santa Maria Basin Province. USGS
The geology
The assessment is built on a Miocene Composite Total Petroleum System, shaped by several phases of tectonic change:
- Basement. Jurassic Franciscan metamorphic rocks and ophiolites lie beneath younger sediments.
- Stretching (early Miocene). The future basin was a west-facing continental slope pulled apart — perhaps by a retreating subduction trench or back-arc extension — into blocks and troughs (horst-and-graben terrain).
- Filling. Coarse nonmarine sediments of the Lospe Formation came first, then mudstones and turbidite sandstones of the marine Point Sal Formation, grading up into the Monterey Formation: organic-rich mudstones, cherts, siliceous shales, phosphatic mudstones, dolomites and sandstones laid down in deep water, together more than 1,000 meters thick.
- Squeezing (late Miocene–early Pliocene). Clockwise rotation of the western Coast Ranges block turned stretching into compression, folding the basin into northwest–southeast structures. Uplift and erosion shed the Sisquoc Formation, Foxen Mudstone and Careaga Sandstone into the basin.
- Cooking. Up to 5 kilometers of Pliocene to Quaternary sediment buried the Monterey's source rocks deep enough to generate oil.
Source rocks
| Rock | Organic carbon (TOC) |
|---|---|
| Monterey Formation — the main source, with the most oil generated, moved and trapped | up to 14% by weight; hydrogen index over 600 mg hydrocarbon per g TOC; sulfur up to 5.9% |
| Point Sal Formation mudstones | up to 3.5% |
| Rincon Shale (lower Miocene) | average 3.5% |
| Sisquoc Formation mudstones | up to 6%, average 2.3% |
How "cooked" the Monterey is — its thermal maturity — is hard to judge, because standard maturity measures don't work well on these rocks.
Two ways oil may be waiting
- Conventional: high-sulfur oil from the Monterey's organic-rich rocks migrated updip into fractured Monterey reservoirs on structural highs. Weak seals may explain the area's many oil seeps and tar deposits.
- Continuous: some oil stayed behind in the matrix of the source rocks after the rest migrated. With no production data from this unit, its inputs were modeled on the USGS assessment of Monterey continuous oil in the nearby San Joaquin Basin.
More results are on the USGS Energy Resources Program website.
Sources
Based on "Assessment of undiscovered oil and gas resources in the Santa Maria Basin Province, California, 2024," U.S. Geological Survey Fact Sheet 2025-3052, by the USGS Santa Maria Basin Province Assessment Team (Christopher J. Schenk and others); a work of the United States government in the public domain.
Licence: CC0 1.0 (public domain) · Adapted from pubs.usgs.gov
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