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Estimates of how much oil or natural gas are “technically” or “economically” recoverable are moving targets. Until just a few years ago, the hydrocarbon-producing potential of the Bakken, the Permian and the Marcellus were vastly underestimated—hardly anyone would have wagered in 1995 that North Dakota, West Texas and northeastern Pennsylvania would emerge as oil and gas hotspots. So what are we to make of California’s Monterey tight oil play, which as recently as 2011 was hailed as the next big thing for tight-oil production, but which is now on just about no one’s mind? Today, we consider what it might take to turn a hydrocarbon frog into a prince.

U.S. oil production dropped to 8.6 MMb/d in 1986, and it continued falling for the next 22 years, bottoming out in 2008 at an even 5 MMb/d. Since then, as we all know, oil production’s been on the rise, and in 2014 it proved that it’s back by hitting the exact 8.6 MMb/d mark it registered when the production decline started in the mid-1980s. Few but the most cockeyed optimists would have guessed in 2008 that the strong, sustained recovery in domestic production we’ve witnessed the last seven years was possible. Behind that oil-production decline and resurgence were ever-changing estimates of how much oil was technically and economically recoverable--particularly from tight-oil/shale plays, which weren’t on most people’s radars in the 1980s and 1990s. Before we look at California’s Monterey tight oil play (whose potential appeared to go from boom to bust in less time than it takes to wear out a good pair of boots), let’s discuss terminology. The (not to scale) diagram in Figure #1 – produced by the Energy Information Administration (EIA) in July 2014 – illustrates terms used to categorize oil and natural gas resources based on certainty (more certain to the right, less certain to the left). The total universe of hydrocarbon resources is represented by the outer oval (outlined by dashed line); the red-colored slice to the right represents what has been produced so far.



Figure #1; Source: U.S. Energy Information Administration (Click to Enlarge)


Within the remaining part of the big oval (colored in various shades of blue) we’ve got “remaining oil and gas in-place” (light blue) which represents the best estimate of the oil and gas that exists but which we haven’t tapped or burned. Within that, there’s technically recoverable oil and gas (medium blue), which refers to estimates of how much can be produced based on current technology. (For information on the latest reserves estimates, see I want to Take You Higher.)  Of course, what’s “current technology” is always changing; as it develops, and as drillers learn to “crack the code” on maximizing hydrocarbon production, the estimates for technically recoverable oil and gas increase. Then, within the technically recoverable oval we’ve got “economically recoverable” oil and gas (dark blue)—estimates determined by both oil and gas prices and by the capital and operating costs associated with production. These estimates are fluid too; as oil and gas prices fall—something the energy industry is now all too familiar with—estimates of how much oil and gas are economically recoverable fall too, and vice versa when prices rise. Changes in capital and operating costs also affect estimates of how much oil and gas is economically recoverable. (In fact, all of this has been happening in spades in recent months—oil and gas prices fell, but so did per-Bbl and per-Mcf capital and operating costs as drillers cut their costs and producers focused on their most productive wells – see Getting Better All the Time.) Finally, within the economically recoverable oval we’ve got “proven reserves” (very dark blue), which are defined as the volumes of oil and gas you can reasonably expect (from geologic and engineering data) to recover under existing economic and operating conditions.



Figure #2; Source: Post Carbon Institute (Click to Enlarge)

With all that in mind, let’s take a closer look at the Monterey tight oil play, which sits beneath parts of central and south-coastal California (red-dashed blobs in Figure #2). As recently as 2011, the EIA was saying the Monterey play had about 15 Billion Bbls of technically recoverable oil, more than all the other tight-oil/shale plays in the Lower 48 combined. (In that same estimate, the Bakken was estimated to have about 4 Billion Bbl of technically recoverable oil, and the Eagle Ford about 3 Billion Bbl.) By 2014, however, EIA had dramatically honed back the Monterey estimate to only 600 Million Bbl—a 96% drop. (That’s like hearing, “No sir, your gas tank’s not full. You’re actually running on fumes.”) EIA said the big downgrading of the Monterey play’s potential—at least given current technology—was tied to new geological information and the lack of production growth like that seen in the Bakken and Eagle Ford shales. Subsequent industry reports have indicated that the Monterey play’s geology and that of the Bakken and Eagle Ford are like night and day, with the Monterey play’s being much more complex—and less predictable.

What does that mean in terms of recoverability? Well the principle technology advances behind the shale revolution are the application of hydraulic fracturing (fracking) and horizontal drilling techniques to unlock oil and gas from “tight” shale formations (see Tales of the Tight Sand Laterals). Previously oil and gas were only recovered in commercial quantities from “conventional” wells drilled into formations where oil or gas had seeped out of the source rock and become trapped in porous rock formations. As such, conventional drilling always has a fair amount of “hit and miss” about it because finding those porous rock traps is not easy (the proverbial dry hole). “Unconventional” drilling – as fracking and horizontal techniques are known – involves drilling into the hydrocarbon source rock itself. The great thing about unconventional drilling is that we generally know where the hydrocarbon bearing shale is – reducing the hit and miss element substantially. Where the shale rock is thick, predictable and located reasonably close to the surface as it is in the Bakken and the Eagle Ford, unconventional drilling can be highly productive and akin to mining a shale “seam”. What the geologists have discovered about the Monterey is that in this case, the hydrocarbon bearing shale is generally more akin to an ice cream swirl than a layer cake – with the width and depth of the formation varying widely over quite small areas. That makes recovering the oil and gas way more complicated and expensive than it is in the big home run Texas and North Dakota shales.

The bottom line is that, at this point, no one knows for sure what the Monterey play’s real potential is. As part of the implementation of SB 4, a 2013 California law on hydraulic fracturing, the state is in the midst of a more detailed analysis of the Monterey play’s geology, what it would likely take for producers to crack the play’s code—and, with that, what the most realistic estimate of the play’s technically recoverable oil would be. (From everything that’s out there, that estimate may well end up above—maybe even well above—EIA’s most recent prediction of 600 Million Bbl.)

It’s important to remember when considering the long-term prospects for the Monterey tight oil play that 20 years ago many people might have guessed that Bakken is a grunge band and that Eagle Ford is a car dealership. (There is an Eagle Ford dealership, but it’s in Johannesburg, South Africa. Back to our topic.) The point is that each tight-oil/shale play has offered its own complexity and special challenges, prime examples being the multiple layers in the Permian Basin (see Stacked Deck--Why Producers Like Their Odds In The Permian) and the low-permeability clays of the Tuscaloosa Marine Shale (see Frackin’ The Shale In Tuscaloosa). The technology and productivity are improving all the time. So while there’s a what-the-heck-happened aspect to the Monterey tight oil play estimates, there’s no reason to give up hope that it may one day turn out to be a major production area.

For the moment, of course, experimentation is an expensive hobby that independent producers can’t afford to indulge in. In the current low oil price environment they have cut back drilling and are concentrating on ‘sweet spot” wells that produce higher rates of return. But as we pointed out in “All About That Base” the shale resource base is not going anywhere – it will still be there when prices and technology advances transform more of these resources from technically recoverable to economically recoverable. At that point we may well be revisiting the Monterey shale play – in future blogs.

Article featured in RBN Energy LLC.


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