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Vol. 12, No. 4 Week of January 28, 2007
Providing coverage of Alaska and northern Canada's oil and gas industry

Inlet gas usage sets record

Enstar, Cook Inlet gas producers scrambled to meet peak; new interconnects planned

Kristen Nelson

Petroleum News

Cook Inlet uses more natural gas on cold days — and delivering those peak needs is trickier than in the past.

Enstar Natural Gas, the Southcentral gas distribution company, set a throughput record Jan. 9 of 292.4 million cubic feet, and the company and Cook Inlet natural gas producers had to scramble to meet that demand, says Dan Dieckgraeff, the company’s regulatory and gas supply manager.

The short-term peak actually hit 305 million cubic feet, he told the Regulatory Commission of Alaska Jan. 24 in a winter update.

This was the second record set this season, he said; the first occurred in November.

Dieckgraeff said there was a “very intricate dance” the night of Jan. 8, but the gas got to Anchorage, although to do that, gas had to be pulled from the liquefied natural gas plant at Nikiski, which was shorted 35 million cubic feet.

It took all the producers working together to meet the peak need, he said.

And it took working around bottlenecks, moving gas in ways it doesn’t usually move. “We’ve not seen this since ’99,” he said.

Enstar serves more than 125,000 meters and some 340,000 Alaskans with more than 3,000 miles of distribution and transmission lines. It is the state’s largest energy utility.

Changes since 1999

Dieckgraeff compared peak days on the system — one in 1999 and the one this year.

It was colder Feb. 3, 1999, minus 19 degrees Fahrenheit, compared to minus 10 degrees F Jan. 9 of this year.

But it took more gas to meet 2007 needs, 292 million cubic feet compared to 272 million cubic feet in 1999. The bulk of that, 227 million cubic feet this year and 187 million cubic feet in 1999, was for Enstar gas sales. The company also had commercial transport (16 million cubic feet this year vs. 29 million in 1999); power transport (44 million cubic feet this year vs. 56 million in 1999); and industrial transport (5 million cubic feet Jan. 9 vs. none on Feb. 3, 1999).

Where the gas came from was dramatically different in 1999 than this year.

On Feb. 3, 1999, 89 million cubic feet came from production wells on the Kenai Peninsula; 183 million cubic feet came from production wells on the west side, including the Steelhead platform.

On Jan. 9, 170 million cubic feet came from the Kenai, but only 115 million of that was from production wells: 55 million cubic feet came from gas storage.

From the west side this year Enstar got 122 million cubic feet, 114 million from production and 8 million from storage.

Drop in deliverability

Dieckgraeff said there was more gas available in 1999.

On the previous peak, in 1999, Cook Inlet delivered 744 million cubic feet: 272 million to the Enstar system; 78 million to Chugach Electric Association at Beluga; 224 million to the LNG plant; 157 million to the fertilizer plant; and 13 million to Tesoro.

On Jan. 9, 2007, however, the total dropped to 531 million cubic feet: 292 million to Enstar; 83 to CEA; 150 million to the LNG plant; zero to the fertilizer plant (shutdown for the winter); and 6 million cubic feet to Tesoro.

That, Dieckgraeff noted, is a loss of 200 million cubic feet of deliverability.

In addition to the drop in deliverability, natural gas has to move differently than in the past, Dieckgraeff told the commission. Demand is not being met on peak days, he said, and additional work needs to be done to stem the decline in deliverability.

And infrastructure work is needed to transport natural gas to residential, commercial and industrial customers.

There are bottleneck issues: interconnects are needed between three lines and/or fields. In particular, the North Cook Inlet field, which provides ConocoPhillips’ supply to the LNG plant, only connects to the plant, so a connection is planned this summer between the line going to the plant and CIGGS, the Cook Inlet gas gathering system.

What’s the plan?

The Jan. 9 peak was met by shorting the industrial plants and moving gas in ways it doesn’t usually move.

What if even more gas is needed?

Dieckgraeff said Enstar would ask for more gas from the LNG plant; ask power utilities to decrease sales to customers outside of Cook Inlet; bring power in from Fairbanks — instead of sending power to Fairbanks; and ask power customers to switch to other sources of power, such as hydro and fuel oil, where they can.

Commissioner Dave Harbour asked Dieckgraeff what else they could do in an emergency situation.

Dieckgraeff said if Enstar was getting everything it could from the industrial plants, and power from Fairbanks, and local plants were switching where they could to hydro and fuel oil, it would ask customers to conserve.

The next step, he said, would be to consider blocking off portions of the system.

To cut people off you have to turn the gas off at individual meters, he said.

Enstar might have to block off portions of the system to avoid getting into a situation where there isn’t enough gas to keep pressure up in the system, which would mean the system would shut down. This, Dieckgraeff said, would be the “125,000-pilot light scenario” Enstar has discussed at the commission in the past.

Former Enstar CEO Tony Izzo talked about the loss of adequate pressure in the system, calling it the “nightmare scenario,” at the Southcentral Energy Forum in September (see story in Oct. 1, 2006, issue of Petroleum News).

Each meter, Izzo said, would have to be individually turned off; the lines would have to be tested and gas re-introduced; and each meter and pilot light would have to be individually restarted, work which could, collectively, take months.

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