A new revision to a study by Petrotechnical Resources of Alaska, or PRA, into Cook Inlet gas supplies makes sobering reading for anyone living in Southcentral Alaska. Essentially, the revised study has found that, in the absence of a fairly dramatic increase in the amount of gas well drilling or the discovery of a significant new gas field close to the existing gas infrastructure, supplies of gas from the Cook Inlet basin will start to fall short of gas demand perhaps as early as 2014.
Southcentral residents depend on natural gas for the heating of buildings and for about 90 percent of the region’s power generation.
“Without some really large discoveries that can be brought on quickly, the current pace of development activity, even if it continues or increases, could still mean a shortfall in Cook Inlet supplies to meet our demands as early as 2014, but more likely 2015,” PRA consulting petroleum engineer Pete Stokes told a meeting of the Alaska Support Industry Alliance on Oct. 11.
An earlier incarnation of the PRA study, published in 2010, had predicted that without new development drilling there would be a gas shortfall in 2013. And, although some new gas wells and new gas compression in gas fields have boosted gas supply levels since 2010, these infrastructure additions have only moved the time of the predicted shortfall by about a year, Stokes said.
Stokes said that although heightened levels of gas development and exploration in the Cook Inlet basin will likely lead to an eventual improvement in the gas supply situation, the lead time in bringing new sources of gas on line, coupled with rates of drilling below what is required to stave off the gas production decline, make it unlikely that new gas can come on stream in sufficient quantities before perhaps 2019. That leaves a supply gap in the intervening period.
“I am concerned about the short term,” Stokes said.
And, with no realistic possibility of bringing North Slope gas by pipeline to the Cook Inlet region before 2020, should proposals for such a pipeline come to fruition, the import of liquefied or compressed natural gas from out of state has to be considered to bridge the gas shortfall gap, Stokes said. Stokes likened the import option to an insurance policy: It might not ultimately be needed, but without the work to enable it to happen, the option will disappear.
“There is ongoing work towards this goal,” he said, referring to actions that the Southcentral utilities have been taking to find some way of importing gas. Although there has been much talk of importing gas in liquefied form, the import of compressed natural gas from the Lower 48 may be a better option, given the price differential between cheap North American gas and expensive liquefied natural gas on the Pacific Rim, Stokes said.
In conducting its study into Cook Inlet gas supplies PRA has investigated the production decline rates of the Cook Inlet gas fields and the decline characteristics of individual gas wells. The outcome of this work has been a predicted decline curve for the entire Cook Inlet basin, if no new wells come on line.
With the export license for the LNG export facility on the Kenai Peninsula expiring in March 2013, PRA has assumed a fairly constant level of gas demand from 2014 onwards, with that demand essentially coming from Southcentral gas and power utilities; from the use of gas by the oil refinery on the Kenai Peninsula; and from gas used as fuel in the operation of the Cook Inlet oil and gas fields.
PRA’s predicted gas supply decline curve drops below the anticipated demand level in 2014, with the supply shortfall increasing year-on-year after that.
But this prediction of gas shortfalls is pessimistic because it assumes that no new gas wells will be drilled and that no new compression will be added to fields, Stokes explained.
In 2010 PRA tried to figure out the drilling rate required to avoid the supply shortfall and concluded that 13 to 14 new wells per year would be needed. Unfortunately, since then there have only been around five or six new wells drilled per year, so that gas supplies have continued to decline.
PRA has found that the drilling of three to four wells per year, perhaps adding 10 million cubic feet per day to gas production, would still leave a supply shortfall in 2014. Upping that drilling rate to six to eight wells, increasing production by around 20 million cubic feet per day, would delay the shortfall into 2015, Stokes said.
And significant recent changes in the Cook Inlet gas industry do give some cause for optimism about development drilling activity in the near future.
Hilcorp Energy, the company that has taken over Chevron’s Cook Inlet assets and is in the process of acquiring Marathon’s interests in the region, is planning major capital expenditures on Cook Inlet oil and gas projects. ConocoPhillips has just completed two new wells in the Beluga River field, Buccaneer Energy is drilling in its Kenai Loop development and Armstrong Cook Inlet has permitted two new wells in its North Fork gas field in the southern Kenai Peninsula.
But, taken together, these new actions still only seem in total to amount to five to six new wells per year, a level of activity below what is needed to boost gas supplies to required levels in 2015 and beyond, Stokes said.
So, what about the heightened level of exploration activity around the inlet?
Nordaq Energy plans to delineate its discovery at Shadura on the Kenai Peninsula and is exploring at Tiger Eye on the west side of the inlet; Buccaneer has announced new exploration near Anchor Point on the Kenai Peninsula; Cook Inlet Energy is exploring the west side of the inlet; and Apache Corp. has been shooting a major 3-D seismic program, with plans to drill its first well on the west side of the inlet later this year. Offshore, both Furie Operating Alaska and Buccaneer now have jack-up drilling rigs in the inlet and Apache has shot some offshore 3-D seismic. Furie is drilling its second well from its jack-up rig.
But exploration is a risky business with uncertain outcomes, and unless there is a significant find near the existing infrastructure, sufficient gas from exploration discoveries is unlikely to come on line in time to prevent a gas supply shortfall. In particular, it would likely take three to five years after an offshore discovery to bring a new offshore gas field into operation, Stokes said.
The other crucial gas supply issue is ensuring that the gas deliverability — the rate at which gas can be delivered through pipelines — is adequate to meet peak demand levels, especially in the depths of winter. And Cook Inlet Natural Gas Storage Alaska’s new gas storage facility on the Kenai Peninsula will play a key role in ensuring that utilities can meet their gas deliverability needs. Essentially, the facility can warehouse gas during the summer when demand is low and then release the gas in the winter when demand is high.
The storage facility can help meet about 50 percent of the average peak monthly demand level while also eliminating the need to overstress gas wells by running them flat out during severely cold weather, Stokes said.
Stokes also commented that the small size of the local Southcentral gas market is a particular concern. It would take relatively few large new gas discoveries to flood that market with gas, he said. Then, without a market to sell into, companies might leave the region, ultimately causing a recurrence of the current gas supply problems. An industrial consumer, such as the current liquefied natural gas plant on the Kenai Peninsula, can create the type of larger market that drives long-term market stability, but can also bring conflicts over competing gas demands in the short term, he said.
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