Shale plays globally are a very good long-term asset and the continuing hype about the under-explored Monterey Shale in California is worthy of most of the superlatives, according to two analysts at Wood Mackenzie’s Houston office.
“Looking operationally at what operators have been able to do with shale assets — now versus where the plays were a decade ago — it is absolutely remarkable at how savvy the industry has become at extracting hydrocarbons from them,” said Robert Clarke, manager of global unconventional gas service at Wood Mackenzie. That applies mostly to North America, but is spreading around the world, he said.
Clarke and Matthew Woodson, a fellow analyst focused on upstream development, agreed with earlier U.S. Energy Information Administration (EIA) estimates that have said oil reserves in the Monterey could be bigger than the Bakken and Eagle Ford shale plays combined, placing Monterey’s long-term potential at more than 15 billion bbl. The EIA estimate was released nearly a year ago (see Shale Daily, Sept. 13, 2011).
Woodson noted that when EIA’s metrics are broken down, the projection comes across as relatively conservative because it is based on a limited swatch of the Monterey Shale, which covers a vast area of California and the Pacific Rim. EIA restricted its analysis to the existing leaseholders, of whom Los Angeles-based Occidental Petroleum Corp. (Oxy) is the largest and the rest, including Denver-based Venoco Inc., are relatively few.
Noting Monterey has the advantage in some areas of only needing simpler, cheaper vertical wells, Woodson said that Oxy and Venoco (the two most active operators there) are “still getting the play figured out” and a Calgary, Alberta-based company, Zodiac Exploration Inc., is still testing deeper shale with horizontal drilling and hydraulic fracturing (fracking). Nevertheless, Woodson thinks a majority of the wells will be vertical and not involve fracking.
“Monterey is an interesting play when you look at it at the highest level, vis-a-vis a lot of the other tight-oil assets in North America,” Clarke said. “From a basic discounted cash flow value model, you’re drilling wells that are a little bit smaller, but they are a lot cheaper and you get a lot more revenue/bbl than a lot of the other plays. You’re not dealing with big differential plays like you are in the Bakken where the oil sells for a premium to WTI.
“So when you look at break-even costs on a per-barrel basis, the [Monterey] play is very attractive, and that leads to the question of why aren’t more companies trying to get positions there?” Clarke’s explanation is California may be too challenging for would-be operators getting the necessary state drilling permits, particularly in new, step-out extension areas away from existing producing fields.
“There may be some hesitation for companies not in California trying to set up large operations if they are not familiar with operating in the state, or you don’t have an existing position there.”
The Monterey Shale formation is made up of a number of fields which do not necessarily require fracking to fully exploit, the two analysts said. “Fracking is going to be required in some areas of the Monterey, just not all of them,” Clarke said.
“Shales are a good long-term asset,” Clarke said. “Some of the improvements that operators are showing in the shales are tremendous.” He noted that the per-well productivity keeps improving through what he called “the shortening of the learning curve and driving costs out of the system through vertical integration.”
© 2023 Natural Gas Intelligence. All rights reserved.
ISSN © 2577-9877 | ISSN © 2158-8023 |