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Pipelines plugging progress Marathon says Cook Inlet acreage access good, technology and rigs improving, but Alaska’s pipeline regulatory system needs revising Kristen Nelson Petroleum News Editor-in-Chief
Discovering and developing more natural gas in Cook Inlet will help solve the problem of declining reserves in Southcentral Alaska, but Marathon Oil officials warn that new sources of gas require new pipelines — an area where the state isn’t yet up to speed.
Southcentral Alaska’s natural gas industry dates from the 1950s and 1960s when companies were exploring for oil. They found oil, but they also found trillions of cubic feet of natural gas, creating both utility and industrial opportunities.
Because so much gas was found the price was low, well below Lower 48 prices, and there was no need for gas exploration.
As gas was consumed over the years, proven gas reserves declined.
When Enstar, the local natural gas distribution company, signed a contract for natural gas with Unocal Alaska in 2001, the contract price for the new natural gas Unocal would discover and deliver was indexed to Lower 48 natural gas prices. It was a big change. Price one of needed changes Enstar took the lead in attacking the price problem in Cook Inlet, Marathon Oil’s Alaska business unit manager, John Barnes, told Petroleum News in an April 28 interview. A price high enough to draw investment was one of the things needed to move gas exploration forward in the area, he said, along with access to acreage and new technology.
Barnes said the state of Alaska has done a pretty good job with the access issue. Annual areawide lease sales for state lands, both onshore and offshore, were begun in the Cook Inlet basin in the late 1990s, as well as in the state’s other major hydrocarbon provinces.
On the technology side, companies have been shooting three-dimensional seismic in the Cook Inlet basin, Barnes said, and drilling rigs are being built for work in the area. Marathon brought in its own truck-mounted Glacier rig in 2000. The company also developed the EXcape completion process for the Kenai gas field, allowing it to fracture multiple zones at its gas fields in a continuous process, cutting fracturing time from days to a single tool trip.
But, Barnes said, while “a lot of things are lining up in the right direction,” there are “still things that are going to have to get sorted through” in the Cook Inlet area, to move gas exploration and development forward. DOE report says inlet has potential One of the things that is needed is more exploration.
The U.S. Department of Energy is finalizing a report on natural gas supply and demand in Cook Inlet, and in presentations the report’s authors have said there should be considerable natural gas left to be found. (See story in April 25 issue of Petroleum News) Barnes said that it is good to see validation that there is the potential for more natural gas discoveries in Cook Inlet.
“I think that’s what Marathon’s been saying for a number of years, so we’ve been acting on it,” Barnes said.
Kent Hampton, Marathon’s North America natural gas marketing manager, said Marathon started to kick up its activity level in Cook Inlet about five years ago. “It takes a while, it’s kind of a big ship; there’s a big delay between the time you turn the wheel and the ship starts to turn; it takes a lot of continuous effort to do that.
“And the ship’s turning — you can start to see some of the results,” he said.
Marathon produced almost 66 billion cubic feet of natural gas in Cook Inlet in 2003, Barnes said, second only to what ConocoPhillips produces at the Beluga River field, and has been producing at that level for the several years.
The company drilled 11 new wells last year and expects to drill 11 this year. Of the 11, three in each year are “exploration type, higher risk,” Barnes said.
Drilling last year included wells at the Ninilchik field (Marathon 60 percent, Unocal 40 percent), Cannery Loop, Beaver Creek, the Kenai gas field and Kasilof. These were all Marathon operated, he said, and the majority were 100 percent Marathon wells.
Marathon used its own Glacier rig, but for a period last summer had three rigs working, including Nabors Rig 129 at Ninilchik and Nabors Rig 273 at Kasilof. Both the Ninilchik and Kasilof wells are directionally drilled from onshore pads to offshore bottomholes.
Marathon also shot offshore 3-D seismic last year at Ninilchik which is still being processed, Barnes said, as well as an onshore data set at Sterling.
But there isn’t enough activity overall to really kick up Cook Inlet gas production, Barnes said.
“It’s hard to pull out of that DOE study exactly, but the activity level you really need to see in the inlet’s much higher than probably we’re seeing now. I think that’s still a component that’s missing right now — a high enough activity level,” he said. State needs to get better at pipeline end of the business Once you find the gas, you need to be able to get it to market — that means a pipeline, and the pipeline part of the equation needs work, Barnes said.
Hampton said the tariff process for the company’s new 30-mile Kenai Kachemak Pipeline is taking three years — about three times what it would take to get through the process in Lower 48 parts of the “gas patch.”
When Marathon and partner Unocal built the Kenai Kachemak Pipeline, connecting the Marathon-operated Ninilchik field with the existing Cook Inlet natural gas pipeline system at Kenai, it was the first new pipeline built in the area in at least a decade, Barnes said. The $25 million, 30-mile line Kenai Kachemak Pipeline began moving gas in September.
“We’re not yet done spending money on the regulatory side there,” Barnes said. “It could be 20-25 percent of the pipeline cost ultimately associated with regulatory.”
It’s a whole bunch of little things, he said. Taken by themselves, “a lot of these things make sense — but when you stack them up and add them up, it costs money.” The pipeline regulatory work includes right-of-way work, the Joint Pipeline Office and the Regulatory Commission of Alaska process.
What’s still being worked is the tariff process at the Regulatory Commission of Alaska, which was started “about two years … before first gas, plus or minus. And we won’t have a final tariff until about one year after first gas,” Barnes said.
An improved pipeline regulatory process is going to be especially important for small operators and for smaller fields.
The DOE report predicts that gas fields remaining to be found in Cook Inlet “are going to be small and they’re more dispersed, and so it makes the pipelines all the more important, because now you’ve got to have more infrastructure to get to the smaller fields,” Hampton said.
Barnes said he thinks people tend to take pipelines for granted, but each proposed pipeline extension — whether to Unocal’s Happy Valley prospect or to NorthStar Energy’s North Fork field — is an economic issue.
“It’s going to be fundamental economics, whether they have … enough of a find,” he said.
“If the state can improve, become more efficient, more effective at regulating lines, then that’s an encouragement for others to come and build lines (even) with smaller fields.”
If the regulatory process for pipelines were more efficient and effective, companies would not have to go into a pipeline project saying, “I don’t know what it’s going to cost to build this line,” Barnes said.
The “uncertainty and potential cost exposure — it’s a negative, it’s a disincentive and probably people are going to have to address it.” Barnes said he believes “trying to get good at managing pipelines … that’s a good step for the state to take.”
The Regulatory Commission of Alaska processes need to get “more predictable, more efficient and more effective.” And that’s good for the consumer, “because ultimately you and I as a consumer pay for a lot of that regulatory cost,” Barnes said.
On the other side of the coin, Hampton said, the tariff is a small part of what the consumer pays for the gas. “But that tariff is very important to the pipeline investor, because that’s how he makes his money — so if you drive that thing too hard in the wrong direction you don’t see many more pipelines get built.” Pipeline regulation done all over the world Pipeline regulation and setting of a fair return for a tariff are done all over the world, Barnes said. “We ought to be able to do it here and I think we can.”
Hampton said the amount of time it would take to get a tariff on a line the size of the Kenai Kachemak Pipeline varies, depending on how controversial the line is, “but in a normal environment in the gas patch it shouldn’t take anywhere near this long or this much in legal expenses.”
Tariff for a comparable line elsewhere in the gas patch would take about a year, Hampton said.
He said changes will probably include a combination of procedural changes at the regulatory commission and statutory changes: “some help and guidance and direction from Juneau — it wouldn’t hurt.”
Hampton said a variation on the pipeline regulatory issue is modifying existing pipelines to serve new fields where one piece of the pipeline is “unregulated and private” and another piece is regulated and “supposed to be open access.”
The Kenai Kachemak Pipeline is an example of gas delivery from a new pipeline, “but the existing pipelines and the modification of existing pipelines I think is just as important and can bring in a significant amount of gas, too.” Storage also an issue Another issue that is going to come up for regulation is storage, Hampton said, where some method is found to store gas beyond average daily needs so that on those very cold days in winter there is extra gas available for power generation and home heating.
With the big old gas fields in the inlet, Barnes said, the reservoirs were so prolific you could increase production when you needed it — and you could do that without much expense in wells needed just for peak production.
With the smaller, less prolific fields being found now, it wouldn’t be cost effective, he said, to drill extra wells that you only used on cold winter days. And “the types of reservoirs we’re finding now are the kind you want to produce flat” to protect the reservoir, so “… having storage in the future will be important.” With storage, you can just put your well into production, “and it’s either going into the market or it’s going into storage…”
In a lot of regions of the country, Hampton said, regulators have “unbundled storage and set it up as a separate entity.”
Getting a return on storage is an issue, he said, “because it takes a special reservoir, it takes extra compression and special investment to provide that storage.”
Storage could also be tied in with a spur line from a gas pipeline coming off the North Slope, he said, with a small spur pipeline used “to fill storage down here, supplement the gas that’s already here…
“So you fill up that storage in the summer time, and then you use that as additional supply in the winter time. So you don’t have as much investment in a pipe and you use a lot of the existing facilities you’ve got here.”
But, Hampton said, you’d have to unbundle storage first. “And I don’t think we’ve quite gotten there yet — I don’t think people have recognized that, yeah, we’re going to have to have a separate storage facility and it’s something we need to invest in.”
We’ve gotten better at drilling Cook Inlet gas wells, Barnes said, now we’ve “got to get better at managing pipelines.” Once we’ve gotten better at managing pipelines, he said, then we can work at managing a storage business.
“Right now, I would be very concerned at trying to take a storage opportunity through the regulatory process. It’s never been done before here.”
There are “brand new sets of uncertainties and issues to manage” as the inlet matures, Barnes said, and the state has “got to get better, more efficient, more predictable, more effective” at managing each of those steps.
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