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Part 4: Monterey Shale: Twice as polluting as Keystone XL?

Editor’s note: In Part 1 of our series on the Monterey Shale, Next Generation researcher Robert Collier outlined the technical challenges of developing the Monterey Shale oil field – and how a technique known as “matrix acidizing,” which uses hydrofluoric acid to dissolve underground rock formations, may be the key to its development. In Part 2 we explored the risks of widespread HF use and in Part 3 we took a look at the potential impacts of Monterey Shale development on California's emissions goals.

As California decision makers ponder how to plan for a potential new oil boom in the Monterey Shale, they are faced with the daunting task of calculating many complex factors – not only a wide range of oil development scenarios, but also the potential increase in fracking and acidizing, the implications for state budgets, possible impacts on in-state consumption and refinery activities, and serious gaps in understanding of the geologic and environmental issues that may arise with a boom.

Much of California’s current petroleum output is categorized as heavy or extra-heavy oil, meaning it is more viscous and requires more energy and time to refine into fuel than lighter grades of crude. In many ways, it is similar to the thick “bitumen” petroleum that comprises Alberta’s tar sands. Lighter grades, such as those found in Texas and North Dakota, have lower carbon emissions footprints because they require less energy to extract and refine.

All heavy and extra-heavy grades require a variety of energy-intensive methods to liquefy, extract from the ground, and refine into gasoline, diesel and other transportation fuels. As a result, many California oilfields have greenhouse gas emissions per barrel similar to the Alberta tar sands crudes, according to the California Air Resources Board. In 2007, 70 percent of California’s active wells produced extra-heavy or heavy crude, and 56 percent of new wells drilled were extra-heavy or heavy.[1]

As a rule of thumb, California’s inland oilfields tend to have heavier crude, while coastal and offshore oilfields have lighter varieties. For example, the carbon intensity of the state’s largest oilfield, Kern County’s Midway-Sunset, and its eighth and ninth largest, San Ardo in Monterey County and Coalinga in Fresno County, are as high or higher than those of the Alberta tar sands. Most oilfields in the San Joaquin Valley are heavy or extra heavy.

In contrast, the oil along the coast tends to be lighter. Many fields in the Los Angeles Basin, Ventura Basin and offshore Santa Barbara produce cleaner burning, light, sweet grades of crude that are as coveted by refiners as the light, sweet blends from Saudi Arabia and Ecuador, California’s two leading sources of foreign imported oil.

Legacy of the 1969 spill

Given the disparity in oil types, worries have arisen that the state’s climate policies could cause a paradox – pushing the Monterey Shale’s coming oil boom into the lighter, cleaner crudes along the coast, rather than into the dirtier, heavier deposits under the badlands of Kern County.

California’s oil lobby has warned that, if strict carbon regulations are applied to Calfornia crude oil production and refining, they will be forced to conduct a process known as “shuffling,” in which California refiners would export the state’s heavy, high-carbon oil to other countries, and then import lighter, lower-carbon oil from abroad. They note that only 39 percent of the crude oil refined in California is produced in the state. The remaining 61 percent comes from Alaska or foreign imports via oil tankers, or from western U.S. states by rail. Under shuffling, oil executives say, California oil would likely be replaced by imported sources of light, sweet oil.

Political realities suggest this will not happen. Oil industry lobbyists have recently backtracked on earlier suggestions that they would shuffle their oil supplies. They now say they will go where the political going is easiest – which means staying away from cities and the coast, where memories of the 1969 Santa Barbara offshore oil spill are still vivid and public opposition to oil drilling is strong.

“I don’t really expect that there will be much work in the Monterey outside of the San Joaquin Valley, at least for quite a while,” said Tupper Hull of the Western States Petroleum Association.[2] “As you know, Los Angeles and the coast is a very strict regulatory environment. The San Joaquin is where most of the resource is.”

What’s more, the state’s complex climate policies may not allow shuffling. Adam Brandt, an assistant professor of Energy Resources Engineering at Stanford University and the state Air Resources Board’s chief expert on the climate impact of transportation fuels, says that the state’s cap and trade system, which is now in operation, and the Low Carbon Fuel Standard, which is now under court challenge, prohibit shuffling. All in-state sources of crude are averaged in a single basket for greenhouse gas intensity, with no differentiation between companies’ individual sources of in-state supply.

 “This issue is confusing, I’ll admit,” said Brandt. “But despite the real disparity in carbon intensity of California crudes, or because of it, the state has deliberately designed its rules to prevent that kind of shuffling.”[3]

The upshot of all this is that the dirtiest portions of the Monterey Shale are likely to be developed first, making the overall prospect for an oil boom a distinctly carbon-intensive affair.

 

Video: Stanford expert Adam Brandt: Transit options reduce emissions; will Monterey Shale increase them?

 

A USA worth of emissions? Or two Keystones?

There are two ways of comparing greenhouse gas emissions for the California oil industry: A broader scope, known as the “well-to-wheel lifecycle” approach, which adds the cumulative total of emissions from the oil’s production and final consumption, regardless of where the oil is eventually used, over the project’s entire lifetime; and a narrower scope that measures the annual rate of in-state emissions from the “upstream” process of drilling, extracting and transporting the oil but does not measure refining or consumption.

Both yardsticks have their weaknesses. The well-to-wheel lifecycle approach might exaggerate the net carbon impact if Monterey Shale oil simply displaces imported sources of oil, and if it does not increase end-use consumption by the state’s transportation sector. The upstream-only approach does not show the overall impact on global greenhouse gas emissions of an up-or-down decision to develop the oil or instead leave all of it in the ground.

Well to wheel lifecycle approach. According to calculations by Argonne National Laboratory using data from ARB, the lifecycle emissions – extracting, transporting, refining and consuming – of the average barrel of California oil are equivalent to 0.5 metric tons of carbon dioxide.[4] As a result, production of the Monterey Shale’s entire 15.4 billion barrels would release 7.7 billion metric tons of carbon dioxide, equivalent to 17 years of California’s total greenhouse gas emissions at 2010 levels, or about one year of total emissions for the United States.

This approach essentially measures the carbon cost of extracting the oil rather than leaving all of it untapped. Of course, there is no guarantee that the Monterey’s 15.4 billion barrels could actually be extracted. Given the current technical difficulties in accessing the oil amid its jumbled formations, there is a real possibility that a significantly lower proportion of that resource will be used. Nor is the speed of this process at all clear – over a few decades, or stretched out over a century? Another difficulty with this approach is that it does not recognize the likelihood that the Monterey’s production would displace imported supplies of crude, making little measurable impact on the in-state emissions of California’s own transportation sector. All these caveats suggest some caution in drawing conclusions.

Upstream only. It’s possible to construct a range of possible emissions scenarios by taking three potential rates of growth for the Monterey Shale, based on output rates in other states from 2007 to 2012 – the North Dakota rate of 40 percent annual increase, the Texas rate of 14 percent, and the nationwide U.S. rate of 5.1 percent. Based on these scenarios, the California oil and gas industry’s annual output of greenhouse gases would rise by the following amounts from approximately 12.5 million metric tons of CO2 equivalent in 2015.

The policy implications of the above scenarios vary wildly. The state’s climate plan mandates that 80 million metric tons must be cut from the state’s overall annual emissions by 2020. If the state’s oil output were to grow by the U.S. rate, the impact on the climate plan’s goals would be moderate – still a step backward, but not unmanageable. If it were to grow by the North Dakota rate, however, the impact would be severe, forcing more drastic cuts in emissions elsewhere.

Another point of comparison is the projected annual rate of emissions from the oil transported by the Keystone XL pipeline, which the U.S. Environmental Protection Agency has estimated at 27 million metric tons. If the California oil industry’s output were to grow at the North Dakota rate, its emissions would be twice as large as the Keystone XL emissions.

The above growth scenarios do not include significant increases in refinery emissions.[5] The state’s 18 refineries have a total capacity of about 2 million barrels per day, of which California’s current oil production supplies only about one-quarter. Federal law strictly limits crude oil exports from the United States to foreign nations; given the lack of any major oil pipelines that could send California crude to other states, it seems likely that most, if not all, Monterey Shale oil will remain in-state and will merely replace supplies of crude that are currently imported.

In addition, California’s refining capacity is configured for a wide range of oil viscosity, including heavy imported crude. So a switch to local supplies would have little net effect on refineries’ energy use and emissions – leaving no basis to assume any substantial change of the refinery sector’s emissions under any of these scenarios.

For now, the Monterey Shale remains a mirage waiting to become reality. The wide gamut of possible scenarios – boom, mini-boom or bust? – means that the jury is still out on the possible climate impact of a net increase in oil production. As with other facets of the national and global debates over climate change, much remains unknown.

But the success of California’s landmark climate policies are clearly at stake. Time will tell if the state’s leaders will remain as committed to existing climate goals when – and if – the black gold starts flowing from the Monterey Shale.

  


[1] With API under 10 and 20, respectively.

[2] Interview, May 14, 2013.

[3] Interview, May 24, 2013.

[4] Email to author, July 25, 2013, from Agmad Elgowainy, Principle Energy Systems Analyst of the Argonne National Laboratory's Center for Transportation Research.

[5] In recent months, the Western States Petroleum Association and researchers at UC Davis have engaged in a vigorous back-and-forth debate over the effects of AB 32 on the refining sector. These important issues are separate from the subject matter at hand.

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