The thick, siliceous, highly tectonically fractured, organic-rich formation known as the Monterey is widely considered to be the primary source rock for hydrocarbons throughout California, supplying world-class prolific fields that have been exploited since the late 1800s. These fields include the Wilmington, Elk Hills, Kern River, and Midway-Sunset.
The basins for which the Monterey formation is thought to be the primary source rock include the San Joaquin, Los Angeles, Santa Barbara-Ventura, Santa Maria, and Central Coastal. Some examples of stratigraphic units that produce from the Monterey itself include the Antelope, McLure, McDonald, and Reef Ridge shales and the Belridge diatomite in the San Joaquin basin, as well as variously named members of the Monterey formation in the Santa Maria and Santa Barbara-Ventura basins. In all these basins and in the Los Angeles basin, the bulk of Monterey-sourced oil is produced from interbedded and overlying sandstone reservoirs into which the oil has migrated from the Monterey.
It is estimated that 38 billion bbl have been produced to date from fields whose source rock is the Monterey.
The prolific Monterey formation has a very heterogeneous geological composition and can serve as both source rock and reservoir. R.L. Garnett, in paper SPE 70992, describes the Monterey formation as a “complex reservoir with intense structuring, fracturing, and highly variable rock properties. It is a dual-porosity system, with low-permeability matrix rock and extensive fracturing.”
Richard J. Behl, a professor of geological sciences at California State University, states in “The Monterey Formation of California: New Research Directions” (August 2012), “The Miocene Monterey formation is an exceedingly heterogeneous, biogenic-rich (siliceous, calcareous, and carbonaceous) deposit, and only a minor fraction of its volume would be considered a true ‘shale.’ It is California’s primary petroleum source rock and an important ‘conventional’ reservoir in many areas, primarily exploiting naturally fractured rocks.”
“Because the Monterey was deposited in a time of tremendous climatic change,” said Behl in an interview, “there is a great variability in rock types as you go through the stratigraphic column.”
The formation is described in an IHS/CERA presentation (“Tight Oil Revival,” May 2012) as “the great facies mix.” This facies mix, Behl stated, “consists of a huge variety of shales, porcelanites, cherts, limestones, dolomites, sandstones, phosphates, and diatomites.”
Monterey source rock is much younger, at 5 to 17 million years old, than that found in the Bakken or Eagle Ford—typically around 300 million or more years old in the Bakken (Late Devonian to Early Mississippian periods) and around 80 million or more years old in the Eagle Ford (Cretaceous Period). Unlike the Monterey, the Bakken, which was initially described by geologist J.W. Nordquist in 1953, occurs entirely in the subsurface, without outcrops. While the Eagle Ford does not have as extensive a number of outcrops as the Monterey, some, such as those in Val Verde and Terrell counties, Texas, (including deep road cuts) have been important in understanding the Eagle Ford’s subsurface character.
Studying the Monterey
In addition to being exploited, the Monterey has also been studied and its petroleum content noted for more than 100 years. In “Miocene Foraminifera from the Monterey Shale of California,” by Rufus M. Bagg Jr., published by the USGS in 1905, the author states, “It is of interest to note that nearly all of the Monterey shale in this neighborhood contains a notable amount of hydrocarbon—enough, at least, to cause it to burn with a flame when placed in a hot fire.”
The “Preliminary Report on the Santa Maria Oil District, Santa Barbara, California,” by Ralph Arnold and Robert Anderson, published by the USGS in 1907, is introduced as follows: “During the last three years the region near the Pacific coast in the northern part of Santa Barbara County, California, has shown promise of becoming one of the most productive oil fields of the West, if not of the whole United States. The developed fields lie on the low, rolling hills between the Santa Maria and Lompoc valleys, and the wells are known to obtain their oil from the Monterey shale, which underlies this region.”
The Arnold/Anderson report was generated during the area’s early hydrocarbon-producing days: “This district was, up to 1899,” the report states, “entirely unknown as an oil-producing territory.” Pay quantities of oil were encountered in August 1901, in the third prospective hole drilled. Among others, the following companies were noted as active in the area by 1907: Union Oil, Western Union Oil, Graciosa Oil, Pinal Oil, Brookshire Oil, Recruit Oil, Palmer Oil, Hall & Hall Oil, Los Alamos Oil & Development, Todos Santos Oil, Southern Pacific, and Standard Oil.
Source and Reservoir
Already by 1999, according to Behl, in the paper “Since Bramlette (1946): The Miocene Monterey Formation of California Revisited,” the Monterey was noted as being unusual in that it had been exploited as both a source and reservoir of oil.
As C.M. Isaacs notes in paper SPE 12733 (“Geology and Physical Properties of the Monterey Formation, California”), “Interest in the Monterey as a petroleum reservoir was stimulated by inadvertent discoveries in the Monterey offshore in the South Elwood oil field and in the Hondo oil field within the Santa Ynez unit (1969).”
With this history, recent focus on the Monterey as an “emerging” shale play in the same sense as the Bakken and Eagle Ford is misleading. Apparently, this dual role has been one it has played for many decades.
A key reason production from the Monterey’s low-permeability source rock has proceeded without the kind of fanfare surrounding Bakken or Eagle Ford production is in part related to its highly fractured nature. The Monterey formation, whose extent in part hugs the famed San Andreas fault, has been and continues to be subject to long-term consistent tectonic activity—a factor that has had a far lower impact on formations like the Bakken and Eagle Ford. The Monterey consists of naturally fractured, brittle diagenetically altered siliceous and dolomitic rocks.
According to Behl (1999), natural “fractures are critical for fluid flow in the otherwise extremely low permeability (<1 md) Monterey lithologies. The distribution and density of fractures vary with rock type, diagenetic grade, bed thickness, location on tectonic structures, and the regional stress field, and are also related to large-scale faulting.”
The extensive fracturing, providing natural pathways along which crude oil can flow and be produced, has, up to now, ruled out the crucial need for reliance on the combination of the techniques of multistage hydraulic fracturing and horizontal drilling, without which commercial exploitation of the Bakken and Eagle Ford source rock would be impossible. This should not imply that this technical combination is not valuable as a means of stimulating commercial production from certain facies of Monterey source rock.
The other key reason for production over the long term from Monterey source rock is that, writes Behl, Monterey petroleum reservoirs can also generally consist of adjacent or interfingered sandstone beds, members, or formations. Thanks to the San Andreas fault—and in a larger sense plate tectonics—California is one of the most geologically complex places in the world. This not only leads to natural fracturing, but also to folding. Steve Hargreaves in “California Could Be the Next Oil Boom State” (CNNMoney, 15 January 2013) explains that, as a result of the presence and effect of the San Andreas fault, “California’s geologic layers are folded like an accordion rather than simply stacked on top of each other like they are in other shale states.”
Remaining Recoverable Oil Generated by the Monterey
“The Monterey formation is much thicker than shales like the Bakken and Eagle Ford,” said Behl in an interview. “It averages 2,000 to 3,000 feet in thickness—sometimes as much as 10,000 feet. This leads to gigantic estimates of how much oil there could be per square mile.”
So, while there are many estimates that exist for Monterey formation “original oil in place” and “unproved discovered technically recoverable resources,” estimates of conventional oil that could be recovered given technology that exists today, might prove more useful than focusing on oil-recovery estimates of the Monterey source rock itself. Two reports issued by the US Geological Survey in 2012 assessed remaining recoverable oil in major fields in California’s San Joaquin and Los Angeles basins—both largely generated by the Monterey formation. One—USGS Fact Sheet 2012-3050 (April 2012)—focuses on the San Joaquin basin. The other—USGS Fact Sheet 2012-3120 (September 2012)—focuses on the Los Angeles basin.
In the former report, “A team of USGS scientists recently completed an assessment of potential additions to oil reserves that could result from improved oil-recovery technologies in selected large oil fields in the San Joaquin basin oil and gas province in central California.”
The report further points out that during the 1980s, reserve additions began to be made using hydraulic fracturing in Monterey formation diatomites (sedimentary rock made up of the tiny silica skeletons of diatoms) on the west side of the basin.
The San Joaquin basin report estimates that a mean of approximately 6.5 billion bbl of oil could be recoverable. This would be based upon the following:
- Improved recovery in diatomite reservoirs of the Monterey formation, given continued technological evolution
- Continued application of thermal-recovery technologies to shallow reservoirs containing heavy oil
- Injection of CO2 in a few reservoirs, particularly deep sandstone reservoirs containing relatively light oil such as the Monterey formation sandstone within the Elk Hills field
In the latter report, using what is described as a “probabilistic geology-based methodology,” USGS scientists assessed the remaining recoverable oil in 10 oil fields within the Los Angeles basin. Using existing technology, an amount assessed at between 1.4 and 5.6 billion bbl of additional oil could be recovered from those fields.
According to the report, “the basin’s small areal extent, prolific source rocks, thick sandstone reservoirs, and large anticlinal traps constitute a nearly ideal petroleum system. As a result, the Los Angeles basin has one of the highest concentrations of crude oil in the world.” A total of 60 oil fields have been discovered within an area of about 450 square miles.
“Given the highly urbanized condition of the Los Angeles basin,” the report states, “unrestricted development is hard to envision. Nevertheless, significant petroleum resources could probably be developed if needed.”