On paper, the Monterey shale play should be the toast of the coast—California’s fastest rising star with the possible exceptions of Jennifer Lawrence and the LA Dodgers.

The potential is breathtaking. Just 27% of the size of the Bakken with more than four times its estimated recoverable
crude oil—15.42 billion barrels (bbl.), this is the play destined to reverse the Golden State’s petroleum production
woes, bolster the San Joaquin Valley’s economy and strengthen the U.S. position in global energy markets.

So far, not so much. The promised boom has proved to be elusive and the reasons, true to the nature of California,
are complex. Even a slight uptick in Monterey activity could be a boon to midstream operators.

Rocks in a hard place

Understanding the Monterey means understanding what it is not: It is neither the Bakken nor the Eagle Ford.

“The Monterey shale in California is very different from the other plays,” declares Hart Energy Research & Consulting
in its 2011 “Global Shale Oil Study.”

“This formation is the source for nearly all of the giant oil fields in California,” the study continues. “The oil within the Monterey shale can range anywhere from 6°API gravity up to 30°API, and is thus much heavier than the oil associated with most shale oil plays. The low gravity oil indicates that thermal maturity is barely within the oil window.”

North Dakota’s Bakken play is a Late Devonian-Early Mississippian formation that dates to about 360 million years ago. The Eagle Ford in Texas was deposited in the late Cretaceous period about 90 million years ago.

“Those formations were deposited on broad, only moderately deep shelves that extended for great distances with only minor environmental change,” Richard J. Behl, professor of geology at California State University, Long Beach,
tells Midstream Business. Behl, who directs the university’s MARS project (Monterey And Related Sedimentary rocks), specializes in the geologic history of California.

The Monterey shale is the baby of the bunch, a Miocene formation ranging in age from 17 million to 5 million years. Its location, on the edge of the continent as opposed to its middle, adds to the complexity of its profile.

Says Behl: “The Monterey was:

• “Deposited on a tectonically deforming margin with great variation in water depth; and
• “Along a marginal oceanic current setting where there was great temporal variation in climate and upwelling
strength.”

Tupper Hull, vice president of strategic communications for the Western States Petroleum Association, likens the contrast to two sheets of paper. Bakken and Eagle Ford are smooth and clean, right out of the box. The Monterey’s sheet of paper, as Hull describes it to Midstream Business, is crumpled.

This translates to dramatic changes in thickness and organic composition in close proximity, a geologic scrum presenting unique challenges to petroleum producers.

“Because of the tectonic activity of California,” says Behl, “the thickness and composition are much, much greater than the kind of shale deposits that are being exploited in Texas and North Dakota and Ohio and Pennsylvania and New York, etc.”

A moving target

Thicker rock may not discourage producers in an industry in which the business model includes the expectation of multiple failures followed by success. But successful unconventional plays in the middle of the country boast a significant
advantage over their cousin on the West Coast: The crude pretty much stays where it is until pumped out of the ground.

Not so in the restless Monterey. There, the unique nature of the formation allows oil to migrate until it finds a reservoir to call home.

This oil is not necessarily “lost.” Much of it makes its way to conventional oil production sites where it is pumped out of the ground. In fact, most conventional oil production in the Monterey involves crude that migrated from source rock, according to geoscientist J. David Hughes in a presentation made to the California Council on Science and Technology earlier this year.

Plenty of potential

Much of the optimism surrounding the Monterey shale derives from a study prepared for the U.S. Energy Information Administration (EIA) by INTEK, an Arlington, Virginia-based consulting firm specializing in energy, environment and sustainability issues. Its July 2011 report, “Review of Emerging U.S. Shale Gas and Shale Oil Plays,” provided the estimate that 15.4 billion bbl. of crude oil could be recovered from the Monterey. That figure dwarfs projections for the Bakken (3.59 billion bbl.) and Eagle Ford (3.35 billion bbl.) and constitutes a remarkable 64% of estimated recoverable crude oil in the lower 48 states of the U.S.

The EIA/INTEK report was followed by “The Monterey Shale & California’s Economic Future,” published by the University of Southern California’s Price School of Public Policy in March 2013.

Anticipating the expansion of hydraulic fracturing and employing a “North Dakota scenario,” the Southern California report forecast state job creation from Monterey shale activity at 512,000 to 2.8 million, or an increase as high as 10% by 2020. California’s per capita GDP was projected to grow as much as 14.3%, personal income as much as $222.3 billion and state and local government revenues as much as $24.6 billion.

The unbridled optimism in these reports is tempered by the reality that California is not North Dakota or Texas
and that the Monterey is not the Bakken or the Eagle Ford. What California does have is Senate Bill No. 4, commonly
known as SB-4, a law that took effect January 1, 2014, to regulate oil and gas well stimulations, specifically
hydraulic fracturing.

“These are onerous regulations,” says Hull of the Western States Petroleum Association, whose group successfully lobbied to avert a legislative moratorium on hydraulic fracturing. “We supported a balanced and comprehensive approach. We had hoped to negotiate and persuade lawmakers to make the bill more balanced.”

Still, he acknowledges that this method of drilling will be heavily regulated everywhere in the future, so implementation
of SB-4 carries with it a significant positive: “The policy of the state is that hydraulic fracturing is an
appropriate technology,” he says

Work in progress

The Monterey shale has not developed into Bakken with a tan, but is by no means a giant dry hole.

“Exploration is taking place,” Hull says. “Companies are in a period of examining what combination of methods
gets the best result.”

And while the middle of the country frets about what to do with the sudden bounty in production, California needs
to keep drilling.

“California only produces 38% to 40% of the oil that we need,” Hull says. “The economics are pretty clear. If the oil
is produced here, then it will be used here.”

The EIA/INTEK report’s findings are wildly optimistic for geologists Behl and Hughes, who cannot scientifically
find a basis for the stated potential and are skeptical that hydraulic fracturing will be effective in the Monterey shale, at least in the short run.

The formation, however, has been reluctant to reveal all of its mysteries. “We know a fair amount about the shallowly buried areas,” Behl says, “but we know next to nothing about the deeper areas.”

Hughes is also curious about what’s down there.

“Oil might be found when we drill very deep wells,” he says. “Who knows?”

Joseph Markman can be reached at jmarkman@hartenergy.com or 713-260-5208.

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