It’s young, thick, and structurally and lithologically complex. But the Monterey shale is quickly moving past the science project stage.
It’s not unusual for explorers to chase a prolific onshore play offshore. In the case of the Monterey shale in California, the opposite occurred – companies producing from the shale offshore decided to chase it onshore.
Thus began the exploitation of what is arguably the largest shale play in the US – the Monterey shale.
The Monterey is not an unknown concept. Production from the shale actually began in the Santa Maria Basin in 1900. But its potential as a source rock outshone its reservoir rock potential for decades as companies began developing such mammoth fields as Midway-Sunset, Belridge South, Kern River, Cymric, and Elk Hills. It is estimated that 38 Bbbl has been produced from fields relying on the Monterey as source rock.
Now operators are starting to take a serious look at the Monterey and at California, which has a tremendous amount of undeveloped potential. The reasons for this lack of development are many, according to Michael G. Edwards, vice president of corporate and investor relations for Venoco Inc. For one thing, California is probably the only state in the Lower 48 to be dominated by the majors. These companies still operate fields like Midway-Sunset, Belridge, and Kern River, but they haven’t been doing much wildcatting in their fields to tap deeper targets. California also doesn’t have a lot of public land, which makes leasing much more difficult. And it has a bit of a reputation.
“I think there’s a perception that California is at least a different place to operate if not a difficult place,” Edwards said. “That perception keeps a lot of independents away.”
Not your average oil-prone shale
The Monterey shale is rather atypical of the types of shales found elsewhere in the country. For one thing, it’s much younger, only about five to 17 million years old compared to other shales that are around 300 million years old. This means that the shale is in the peak oil generating window.
It’s also quite thick and not at all homogeneous. It’s been characterized as a large deposit of diatomaceous material. At shallower depths it has very low permeability and needs stimulation to recover oil. Further down, as temperature and pressure increase, the shale becomes more brittle and contains more natural fractures. Ultimately it evolves into a quartz phase, and any part of the shale may contain sandstones as well.
Characterizing this hodgepodge of lithologies is further complicated by the fact that the Monterey shale is in a very tectonically active area. The plus side here is that this provides the potential for more hydrocarbon traps.
Because of its age and thickness, Edwards said there really isn’t an analogous shale elsewhere in the country. “It was right on the coast, so there was erosion and runoff intermixed in the beds,” he said. “There are also some barriers like small islands that kept some of the sediment from going farther, so beyond that is almost pure diatoms raining down and forming the structure. There’s definitely some variability depending on where the organic matter was deposited.”
The Monterey is not likely to see the types of multi-stage fracs performed in other shale plays, with operators preferring large-volume hydrofluoric acid jobs. Edwards said that Occidental Petroleum (Oxy) published a white paper several years ago stating that its engineers didn’t see an economic benefit to hydraulic fracturing. “We’ve tried some fracs,” he said. “We haven’t concluded that the model doesn’t work, but we believe acid jobs will yield better results overall.”
Overall, the Monterey shale is estimated to contain more than 400 Bbbl of original oil in place.
Tapping the potential
Edwards said that Venoco has been producing from the Monterey horizon offshore since 1997. In its Sockeye field it produces from a deeper part of the Monterey called the M4.
“We decided that we’d do some recompletions in those wellbores into a zone called the M2,” he said. “We tested anywhere from 30 to 80 bbl per day from the vertical recompletions. We then decided to drill a horizontal into that interval. We had IPs of 150, 600, and 800 bbl per day.”
These were unstimulated, open-hole completions, he added.
Not surprisingly, these IPs piqued the company’s interest. “Our geologist said, ‘If you like those results, you can find that rock in lots of places onshore.’” This kicked off an investigation of available acreage.
Venoco had several criteria for choosing which acreage to lease. “We wanted areas that are easy to operate in,” Edwards said. “The LA Basin has a lot of potential, but there are 10 million reasons why you don’t want to spend your time there.”
Another requirement was to find lighter oil, not the heavy oil that’s being steam-flooded in the Kern River field. The team studied well data from some of the 17,000 wells that have been drilled in the region. From this information it was able to map the top and to some extent the thickness of the structure and to identify areas that were likely to have lighter oil, above 25° gravity.
Another criterion was to be close to infrastructure. In the San Joaquin Basin, Edwards said, Venoco’s operations are close to infrastructure in terms of pipeline availability and disposal wells.
Venoco also looked for acreage that included a structural component. “We think we have a better chance of finding accumulations where we can identify some structure,” Edwards said, adding that Venoco and Oxy are jointly funding a 500-sq-mile (1,295-sq-km) 3-D seismic survey, the largest survey ever conducted in California. It expects to have all of the data in-house early this summer.
“That is going to help us as far as having more control over where we put our wells and where there might be faults or dipping beds,” he said. “We also think we have a good chance of identifying some conventional opportunities with that seismic, both above and potentially below the Monterey.” He added that about 86,000 of Venoco’s acres are within the survey boundaries.
Finally, reservoir depth is an issue. Edwards said the company is looking for enough reservoir pressure to move the oil through the rocks, so it looks for acreage in which the Monterey lies 6,000 to 12,000 ft (1,830 to 3,660 m) below the surface. This is not as easy as it might seem – Venoco’s offshore platforms drill the Monterey at 3,000 to 5,000 ft (915 to 1,525 m), but less than three miles away, in the Santa Barbara Channel, the Monterey outcrops.
Success to date
Venoco raised some eyebrows last fall when it announced that one of its Monterey wells was deemed uneconomic due to high water cut. Yet it remained bullish, planning to spend US $100 million, or 50%, of its 2011 capital budget on the play.
According to its Q1 2011 conference call, the company began actively drilling its onshore Monterey acreage in early 2010 and at press time had spudded 18 wells, 12 vertical and six horizontal; set casing on 13 wells, nine vertical and four horizontal; used two vertical wells as pilot holes to start horizontal wells; and is currently drilling two vertical wells. It also is continuing to build on its acreage position, currently at about 240,000 gross and 159,000 net acres. An additional 60,000 gross and 46,000 net acres with Monterey shale production or potential are held by production.
As the industry watches with curiosity what will come from Venoco’s efforts, company officials seem optimistic that they’re putting their money in the right place. In the 1Q press release, founder, chairman, and CEO Tim Marquez noted, “While to date we have not seen significant cumulative production as a result of our drilling in the onshore Monterey, we have been encouraged by the scientific information collected thus far. After extensive logging, coring, and testing, we have accumulated sufficient data from our vertical wells to announce discoveries in our Sevier prospect in Kern County and in our Salinas Valley prospect.” Marquez added that reserves estimates for Sevier are about 90 MMbbl on 20-acre spacing, while Salinas Valley reserves are about 44 MMbbl on 40-acre spacing.
In addition to Venoco, other players are chasing the Monterey (see box). Oxy is by far the largest leaseholder, and in its 1Q 2011 earnings report it announced that the 26 wells drilled in the shale in 2010 proved up 200,000 acres on 10-acre spacing with 400,000 barrels of oil equivalent per well.
During the April 28 conference call, Steve Chazen, Oxy’s president and COO, said that the company’s program in California is proceeding with “satisfactory results,” although permitting, particularly exploration permitting, has been an issue. During the question and answer session, Chazen fielded additional questions about Oxy’s progress in the play.
“The exploration program is slightly stalled from the permitting process,” he said. “We hope that the back half of the year we can catch up. … We are getting better results from the completions than we were historically because we probably figured out how to do it better.”
Other potential Monterey players include Plains Exploration, Newfield Exploration, Berry Petroleum, Canadian Natural Resources Ltd., Western Energy Production, Zodiac Exploration, and Gasco Energy.
Time and experience will tell whether the Monterey can live up to expectations. But for those who like to go exploring, now’s the time.
“This play needs competition,” Western Energy’s Managing Director Steven Marshall said at Hart Energy’s 2010 Developing Unconventional Oil conference. “It’s been landlocked for a long time, and a lot of people didn’t have their exploration hats on.”