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Things are changing in Cook Inlet, Scott Jepsen tells Alliance Price, market, remaining reserves now make gas exploration feasible, says Phillips Alaska’s Cook Inlet assets manager Kristen Nelson PNA Editor-in-Chief
Things are changing in the inlet, Scott Jepsen told the Alaska Support Industry Alliance April 11. Predictions that Cook Inlet is running out of gas — headlined in the press beginning in late 2000 — are alarmist, said Jepsen, Cook Inlet assets manager for Phillips Alaska Inc., and are based on “simplistic” calculations: known reserves divided by annual gas usage.
Gas fields don’t decline linearly, he said, and while the reserves-production ratio, reserves divided by production, may be 12 years for Cook Inlet, in the Lower 48 it “has been about seven to 10 for the last 20 years: And the last time I checked,” Jepsen said, “they still have a lot of gas down in the Lower 48.”
In addition to known reserves there are also potential reserves, Jepsen said, and the U.S. Geological Service has estimated that there is a greater than 10 percent chance that there are 2.4 trillion cubic feet of undiscovered reserves in the inlet.
If gas is likely, companies will explore Current known reserves are 2.5 tcf, Jepsen said, and “the RP ratio of 12 assumes there’s no more gas to be discovered.
“The problem with that is it really violates one of the fundamental tenants of the oil and gas business,” he said: “If you provide us with a price for our commodity, you provide us with markets to sell it in and if there’s a reasonable belief that there are economic accumulations of oil or gas, companies will go out there and explore for it.”
In the 1970s, Jepsen said, the reserves-production ratio stood at about 55 years: “If you were unfortunate enough to discover gas, you probably couldn’t sell it for a long time or else you’d have to basically sell it at a very low price in order to displace somebody else’s gas.”
“Really all the low RP means is that there’s actually a market developing to sell gas,” he said: “You know those headlines could very easily have read that for the first time in 30 years, if somebody finds gas, they can sell it!”
And predictions about the difficulty of meeting needs on the coldest days of the winter don’t reflect a reserves problem, he said, but a problem of deliverability — having storage available which can be drawn on to meet those peak demands.
Meeting that peak demand, he said, is a “business opportunity for some entrepreneurs who want to go out there and provide peaking facilities for local utilities.” Mid-sized fields missing When companies look at basins, Jepsen said, one thing they look at is drilling records and the results others have had. Because gas exploration hasn’t been a priority, there aren’t gas exploration records for Cook Inlet.
What companies can look at is analogies with other large hydrocarbon basins.
“When you do that, there are a couple of common themes that jump out at you,” Jepsen said.
The first is that basins contain fields of different sizes.
“One thing about naturally occurring phenomenon like oil and gas accumulations is they occur in what we call a log normal distribution. Simplistically what that means is there are always going to be a few large fields, giant fields, with an ever-increasing number of smaller fields,” Jepsen said.
And in Cook Inlet 85 percent of gas discovered has been in four fields each of which initially contained more than 1 trillion cubic feet of gas. Then there have been four fields found with reserves from 100 to 250 billion cubic feet and a handful of fields in the 50-100 bcf range.
“Statistically,” Jepsen said, “one would expect to see more of the mid-sized fields than we’ve seen so far.” Geological concepts The other common theme with large basins is discovery cycles, Jepsen said: A geologist has a concept, it’s successful and a number of discoveries follow.
Then there will be a period of no discoveries, “and then somebody comes up with another concept and there’s another round of discoveries.”
The best example right now is Alpine and the discoveries in the National Petroleum Reserve-Alaska.
“Alpine was discovered because of an evolution in 3-D seismic technology. We could not have found that field 20 years ago. And of course that gives rise to other prospects, now in NPR-A, that we’d have never tried chasing 15 or 20 years ago,” Jepsen said.
The other change in the inlet is new players. In other large basins, “independents are the vast majority of people that are drilling wells out there now.”
And “the more players that you have, the more likely wells are going to be drilled.
“The more wells that are going to be drilled, the more likely that’s you’re going to have discoveries.”
Jepsen said the smaller players are also a positive thing, because small fields can be economic for small companies, where they are not for larger players. Lower 48 comparable price Price has also been a factor in slowing Cook Inlet gas exploration, Jepsen said. For long periods the gas price in the inlet was about 25 cents per thousand cubic feet.
“You pretty much gave your gas away, but that’s also pretty much what you would expect if you had an RP of 55 years — there’s not much market for your supply,” he said.
The recent Enstar contract tied gas prices to the Henry Hub price, which means Alaska gas prices are “tied to something in the Lower 48,” making it easier for companies to compare investing in gas prospects in Alaska with gas prospects elsewhere.
“So in the last several years, we’ve seen all the key elements come together to motivate exploration. We’ve seen a decrease in RP, which means there’s an active market. We’ve seen higher prices, which means investors can probably get a reasonable rate or return on their investment. And lastly, I think there is a consensus that there’s a reasonable probability that more gas remains to be found,” Jepsen said. Recent activity In 1998, Phillips (then ARCO Alaska Inc.) and Anadarko Petroleum Corp. found Moquawkie. “We were looking for oil, but we found gas,” Jepsen said.
Aurora has since brought the Nicolai Creek field back into production, and Unocal and Marathon have announced 90-plus billion cubic feet near Clam Gulch.
“And just last Friday (April 5), a pretty exciting announcement by Forest Oil with regard to gas: They found a 589-foot gas column in their last well that they drilled over at Redoubt Shoal. That’s a significant gas column, folks. That’s the kind of gas column we have in the North Cook Inlet field.” A deliverability issue The issue of providing gas on the coldest days in the winter is a deliverability issue, Jepsen said.
“Historically, if Enstar needed additional gas on a real cold day, they could call us up over at Beluga” and ask for more gas the next day.
“We could do it. We just opened a few valves and the gas would flow. We didn’t need compression. Things are changing a bit now. On those cold days we might fire up a compressor …for a couple of days.”
But now, Jepsen said, Cook Inlet needs to look at meeting peak demands. Elsewhere, “you don’t rely upon the wells to provide that peak deliverability,” he said.
Elsewhere peak demand is met with liquefied natural gas storage or natural gas storage in abandoned reservoirs.
“Generally speaking that is a function of the utilities, that’s what they do, they can build those facilities, put it into the rate base and that’s how those things get paid out,” he said. And those discussions are happening now for Cook Inlet.
“Because the gas is there. We have plenty of gas. It’s not a function of not having the gas on those peak days. It’s … just a function of putting in the deliverability systems.” Phillips and gas Phillips would like to see more gas discovered in the inlet, Jepsen said, and while the company has no current plans to drill, “we’re constantly looking. We’re doing our own internal evaluation work in determining if there’s gas exploration that we want to do in the general Cook Inlet area.”
Whoever does the drilling, Jepsen said Phillips expects to see gas exploration going on over the next five to 10 years, “and many of the questions that we have right now are going to be answered through the drill bit.”
If there is a big gas discovery — say a couple trillion cubic feet — “then we’ll probably see everything go quiet again.
“There’s no point in looking for a lot of reserves if the RP is back up there around 30 or 40,” Jepsen said.
“I guess one thing I want to leave everybody with, if you’re not familiar with the business, is: you don’t need more reserves than you can sell. You put your money someplace else.” The LNG plant Phillips is 70 percent owner of the Nikiski LNG plant, and all of the gas from its North Cook Inlet unit produced through the Tyonek platform goes to the LNG plant.
Jepsen said the export license for the LNG plant runs through March 2009.
The company is often asked if the plant will operate beyond 2009, Jepsen said.
“And we’d certainly like to.
“But at this point in time we don’t have any plans to file another application to renew our export license, primarily because we need more gas before we can do that.”
A big gas discovery would be needed, he said, but probably wouldn’t result in a plant expansion because of competition from other gas sources at tidewater.
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