Sunday, February 19, 2012

Deciding on best partner; New shale player Royale hopes to drill up to six North Slope wells next winter

Kay Cashman
Petroleum News

Grab a drilling rig while you can — or order one built — because the second new player to target oil in North Slope source rocks is planning to drill up to six evaluation wells next winter, two on each of its three lease blocks.

But before it puts together a drilling and testing program to evaluate oil production from source rocks in its Alaska leases, Royale Energy Inc. has to decide on the best partner for its northernmost venture. Fortunately, it says it has several to choose from.

The San Diego-based company first entered the state when it was high bidder on more than 100,000 acres in the state of Alaska’s Dec. 7 North Slope lease sale.

The acreage has some conventional oil potential in the Brookian and Beaufortian in Royale’s western block of leases, which could result in “cooperation with other North Slope explorers,” company executives told Petroleum News Feb. 8. (See the Mapmakers preliminary lease sale map with this story. Great Bear’s new leases are dark blue and its pre-existing leases are gray; Royale’s tracts are purple; Armstrong affiliate 70 & 148’s are light brown; ConocoPhillips’ bright red.)

But Royale’s focus is on what company Co-President and CEO Stephen Hosmer calls its “promising, hand-picked acreage for oil-rich shale.”

Royale, which was founded in 1986, has 23 full-time employees, and is recognized as one of the 20 fastest growing producers in the United States by Oil & Gas Journal. It has an “unconventional view,” Hosmer said, on the source locations and migration pathways of the oil that escaped northern Alaska’s source rocks, making its way into the region’s world class reservoirs that include the giant Prudhoe Bay field.

“Our view would surprise many geologists working the region,” he said.



Abdel-Rahman and Mukluk

The company’s unconventional concept is not based on idle speculation, but rather years of study and discussion led by Mohamed Abdel-Rahman, Royale’s vice president for exploration and production, who joined the company about five years ago, Hosmer said.
While employed by BP predecessor Sohio in Alaska, Abdel-Rahman headed up the post mortem on the famous 1983, $1 billion, Mukluk well in Harrison Bay. The most expensive dry hole in history, operator Sohio and its partners expected the well to encounter a massive oil pool, but all that remained of any oil that might once have existed in the Mukluk structure was extensive oil staining and residual asphalt-rich heavy oil.

Abdel-Rahman had been working for Shell in the Atlantic on offshore leasing before joining Sohio, and was ultimately named Alaska district geologist for the company.

“I went to work for Sohio in San Francisco in 1982. I started as area geologist for south Alaska. Then I became district geologist for the whole of Alaska. That’s when I was picked to head the Mukluk task force … to do a technical evaluation, in order to determine what really went wrong,” Abdel-Rahman said.

After Mukluk was drilled, “everybody in Sohio and in the industry was in a total shock. … I had not worked Mukluk as a prospect but moved into the position of statewide geologist as it was being drilled,” Abdel-Rahman said, so he didn’t have a personal stake in the task force’s conclusions.

Both a geologist and a chemist, Abdel-Rahman said he has always “used chemistry as much as I can. At the time it was not fashionable to talk about biomarkers — organic compounds that are characteristic of the organisms from which the oil is generated — but we did biomarkers work in Mukluk and compared it to all the other oils that had been discovered on the North Slope. We found an astounding match of the Mukluk oil and Kuparuk oil. … In my view there is no doubt that the Mukluk oil went to Kuparuk.” (See sidebar for more on the Mukluk post mortem.)

Optimum for oil generation

It was from the Mukluk drilling review that Abdel-Rahman developed his “concept, his unique viewpoint” about the locations of the source rock that “charged” Prudhoe Bay and other North Slope oil fields, Hosmer said.
The latest North Slope lease sale “presented us with an opportunity to secure a position along the heart of the oil window, of the source rock itself. We chose leases for their thermal maturity for oil,” Abdel-Rahman said.

Royale took 60 leases in three blocks: Two of the blocks adjoin Great Bear’s acreage to the east and southwest whereas the third block is further west along the Colville River.

Royale was bidding against Great Bear on some acreage and against Armstrong’s 70 & 148, in other areas.

“Everything we picked is optimum for oil generation — in all three shales,” Abdel-Rahman said, referring to the North Slope’s three stacked source rocks, from deepest to shallowest, the Triassic-age Shublik formation, the Jurassic-age Kingak shale and the Cretaceous-age Hue, or HRZ, shale, although Hosmer said Royale is most excited about the Shublik, which is very similar in composition to the Bakken shale.

Which company got the best acreage?

The assumption has been that Great Bear tied up the best acreage for shale that was liquids rich, but when asked about that, Abdel-Rahman was reluctant to discuss the difference between his model and acreage choices and that of Great Bear President Ed Duncan.
“I would rather talk about our acreage,” he said. “Let me put it this way: Had all the acreage been available and no acreage taken we would have picked up more acreage but we would have still chosen the acreage we did.”

First a technical partner

Before any well drilling occurs Royale has to decide on a partner.
“We’re hoping to move into technical design so that we can get into drilling phase next winter,” but for that the company will need a partner with technical expertise in designing wells in shale plays, Hosmer said.

“We have a lot of folks talking to us, a lot of opportunities to pick the right partner,” he said.

According to its website, royl.com, its Nasdaq trading symbol, Royale’s model in its Lower 48 operations is to sell a portion of the working interest in each newly acquired lease to third-party investors, retaining a portion of the prospect. The prospects are then bundled into multi-well investments.

“Our model is to partner up with folks; that probably won’t be any different here, but we’re looking for a somewhat different relationship — a technical and strategic partner rather than our traditional model of a group of investors, each with a small piece of the investment,” Hosmer said.

“We typically never like to give up operation but that’s open to discussion in Alaska, based on who that partner might be,” he said.

Royale is considering several potential partners, both oil companies and oilfield service firms, gauging “how comfortable we are with them, and whether their technical expertise lends itself to operating our Alaska leasehold or simply using their technical expertise” in an advisory capacity, Abdel-Rahman said.

So why Alaska?

So why Alaska, when there are proven shale plays in the Lower 48?
“Part of what led us to the choice was it coincided with out move back to the liquids, away from natural gas,” Hosmer said.

According to its website, Royale markets about 15 million cubic feet per day of natural gas from conventional gas wells in California’s Sacramento and San Joaquin basins. The company also has interests in Utah and Texas.

Abdel-Rahman said that a few years ago his company had production from the Monterey shale, a Californian play, before selling its interests to Occidental.

Hosmer and Abdel-Rahman want to get in on the ground floor for producing oil from Alaska shale.

“We had been contemplating it for many years, discussing Mohamed’s concept for the North Slope, and we have a West Coast orientation. We shy away from mid-continent exploration, so Alaska was a natural for us,” Hosmer said.

“We were caught by surprise when Great Bear Petroleum took that much acreage (500,000 acres in the October 2010 state North Slope lease sale). It forced us to move quickly,” Hosmer said.

Royale’s executives would have liked “more time to get rigs in place, internal infrastructure ready, but we had to move on it this year,” he said.

“We are very excited about our land position; it’s just a tremendous position. We are thrilled to be there,” Hosmer said.

The challenge, he said, echoing what Duncan has been saying since Great Bear entered Alaska, “is not in the geology, but in how to get the oil out. The geo-mechanical properties of the source rock needs to indicate high degree of brittleness. In particular the Young’s module and Poisson’s ratio need to be determined for these rocks, which are typically measured in the lab from rock plugs that are taken from cores. These will determine which zones from the vertical wells companies will chose to drill through horizontally and for multi-stage fracs. All these things have really not been done in Alaska to date.”

And they won’t be done, he said, until Great Bear “drills its first few wells, executes its proof of concept program,” starting this spring.

“The challenge is not whether there is oil, but whether or not the oil is going to be extractable economically.”

A lot, he said, will depend “on whether the state of Alaska is willing to work with us to make oil shale prospects viable.”

Many oil provinces have “prospects that have lower risk than Alaska, but much, much lower rewards. The potential reward in Alaska is huge. No other shale opportunity comes close to this, not only in the Lower 48 but in other parts of the world that we can access. This is a prime shale play,” Abdel-Rahman said.