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Are Cook Inlet gas supplies in crisis? As winter approaches, Chevron manager presents facts, figures about natural gas supply and demand in Southcentral Alaska Alan Bailey Petroleum News
Natural gas has flowed out of the Cook Inlet basin with apparent ease for around 40 years, in some ways the life blood of Southcentral Alaska, firing heater furnaces, fueling power stations and supporting significant industrial activity. But does recent talk about gas shortages in the basin signal the beginning of the end for Cook Inlet gas? Or is the region merely transitioning through a period when gas supplies come more into balance with demand, following years of excess gas resources?
At the Oct. 15 meeting of the Alaska Geological Society, Steve Wright, Chevron’s Alaska development manager, presented his perspectives on the Cook Inlet gas situation. Wright, an experienced oil industry geologist, now oversees Chevron’s Cook Inlet oil and gas development program.
Most of the Cook Inlet gas comes from oil and gas fields discovered during the heyday of oil exploration in the 1960s and 1970s. And, after many years of production, gas reserves — the volumes of gas confidently thought to exist in proven gas reservoirs — have declined by about 80 percent, from about 8 trillion cubic feet to about 1.5 tcf, Wright said.
“The Cook Inlet gas reserve base is now believed to be at its lowest point for 40 years,” he said.
At the same time the gas deliverability — the rate at which gas can be produced and delivered to market — is also dropping.
“Total Cook Inlet gas deliverability has declined about 40 percent in the last three to four years,” Wright said.
High investment The declines in reserves and deliverability have come despite a high level of expenditure in Cook Inlet gas development in recent years, with something in excess of $500 million being invested in just the last two years, Wright said.
“Over the past two years alone there have been 29 gas development wells drilled in 11 different gas fields around the basin,” he said.
Development activities have included six wells in the Grayling Gas Sands; three wells in the Beluga River field; two winter-drilled wells on the west side of Cook Inlet; two development wells and a compression project in the Ninilchik field; three development wells in the North Cook Inlet field; eight development and storage wells in the Kenai field; and two development wells in the Happy Valley field.
That development activity probably slowed the annual rate of the gas deliverability decline to between 10 and 15 percent; the natural decline rate would likely be 15 to 20 percent, were there to be no development intervention, Wright said.
Production data from the Alaska Oil and Gas Conservation Commission indicates that the deliverability decline has become especially pronounced in the last three years, mainly as a consequence of production declines from the four big legacy gas fields: Beluga River, North Cook Inlet, Grayling Gas Sands and Kenai. In fact, the Ninilchik field, a good-sized field that came on line in 2003 as a result of modern exploration, has actually been increasing its production, Wright said.
Faced with declining deliverability, Cook Inlet gas producers have developed three underground gas storage facilities, to warehouse summer-produced gas to help meet peak demand levels in the winter.
Grim picture A chart of historic and forecast annual gas production, published by the Alaska Department of Natural Resources in December 2006 and sometimes referred to as the “gas cliff,” paints a grim picture of future gas production expectations. According to this chart, after a huge ramp-up in Cook Inlet gas production in 1965 to 1970, production continued to climb for another 10 years before leveling off and remaining fairly constant until around 2006-07. Using future production estimates based on known gas reserves, DNR predicted that production would plunge precipitously in subsequent years.
But current estimates of gas production for 2009 indicate an overall production level considerably lower than the projected value on the 2006 DNR graph, Wright said.
“You might conclude that the DNR forecast was somewhat optimistic overall,” he said.
And an Alaska Natural Gas Development Authority projection of gas supplies versus gas demand shows annual supply volumes dropping below total gas demand around 2012-13, Wright said.
“After that point, total supply will not meet utility demand in the basin,” he said.
Data presented to the Regulatory Commission of Alaska by Enstar Natural Gas Co., the main Southcentral Alaska gas utility, and by Chugach Electric Association, a major Southcentral electric utility, suggest shortfalls in utility gas supplies at around that same 2011-13 timeframe, Wright said.
Production figures from the LNG plant at Nikiski on the Kenai Peninsula also make sobering reading — the LNG plant was originally built to establish an export market for excess natural gas from the Cook Inlet basin.
According to data from ANGDA, in 2008 the LNG plant used on average about 180 million cubic feet per day of Cook Inlet gas, a gas volume that represented about 42 percent of the total amount of gas produced from the basin.
“Exports from the LNG plant have ramped down significantly this year, and the 2009 numbers may actually show those LNG volumes to be half of what they were in 2008,” Wright said.
Urgent Plots of projected daily gas deliverability versus daily gas demand show an even more urgent problem: Daily gas deliverability will likely fall below peak demand requirements during the cold of the winter, well before total annual gas production drops below annual gas needs.
With much of the utility gas being burned to heat buildings, daily temperatures in Southcentral Alaska form the key drivers behind gas consumption, Wright explained. And there is an obvious annual cycle of temperature changes between warm summers and cold winters, he said. But superimposed onto that broad cycle are chaotic day-to-day temperature fluctuations, fluctuations that become much more extreme during the winter than during the summer.
“That’s obvious to all of us who live here and know that winter temperatures can vary by 30 or even 50 degrees over a couple of days,” Wright said.
Those extreme temperature fluctuations, on top of an already heightened winter demand, place a huge stress on the gas deliverability system. And at no time has that stress become more apparent than in January 2009, when a series of events brought utility gas delivery to the brink of failure.
The problem started with two early winter cold snaps in October and November of 2008.
“The gas storage project operators at the three gas storage projects around the inlet had to start depleting the volumes that they had in the reservoirs very early, to meet the demand during these cold snaps,” Wright said.
Levels halved As a consequence, gas levels in the storage facilities had dropped to half of their start-of-winter levels by the end of 2008.
Then came an exceptional, extreme cold period in January, with day temperatures averaging around minus 8 F to minus 10 F, and night temperature bumping 20 below zero for 10 days to two weeks: The semidepleted storage facilities struggled to keep up with the extreme gas demand.
“The reservoir pressures in the storage reservoirs were about half of what they had been,” Wright said. “They could only deliver, because of the dynamics of gas flow, about a quarter of what their total deliverability would have been at the start of the winter.”
The failure of two gas compressors, the machines used to drive gas through the gas pipeline system, then completed what Wright characterized as a perfect storm for gas supplies.
Then, as gas pressures in the gas transportation system started to fall rapidly, oil company and utility personnel swung into action.
“The producers and utilities went into emergency response mode and worked together very effectively and we were able to head off a potential catastrophic situation by supporting one another, moving gas around the system … and working together to deal with this problem,” Wright said.
The various stakeholders in the gas supply system have since been reviewing what happened in this emergency, refining contingency plans to deal with any similar situations in the future.
“What we do know is that these types of temperature scenarios can’t be avoided,” Wright said. “This is reality. What we’ve got to do is put plans in place to deal with those kinds of scenario when they develop.”
Solutions? But what’s to be done about the bigger picture of dwindling Cook Inlet gas supplies?
Natural gas exploration in the Cook Inlet basin is especially challenging, thanks to a high-cost environment, a dwindling support industry, long development lead times and difficult operational logistics.
And the results of exploration over the past 10 years don’t look too encouraging.
According to AOGCC data, eight different operators drilled 15 exploration wells and eight coalbed methane appraisal wells during that time period, Wright said.
“So we obviously had a lot of companies looking for gas,” Wright said. “A lot of different ideas, concepts being generated, plays developed and wells drilled to test those concepts.”
Five of the 15 exploration wells were classified as discoveries, with just two of the discoveries — the Ninilchik and Happy Valley fields — being deemed commercial.
“That translates to a commercial success rate of somewhere between 10 and 15 percent,” Wright said. “Success rates for exploration in the Lower 48 are typically 50 percent or higher these days.”
Moreover, in addition to land access being limited by the closure to oil and gas development of regions such as the Kenai National Wildlife Refuge, all of the moderate- to large-sized geologic structures that typify the reservoir settings of the established gas fields have now been drilled and tested, Wright said. Seasonal access restrictions on the western Cook Inlet coast result in a need to stage equipment over the winter. And, offshore, the listing of the Cook Inlet beluga whale and the increasing difficulty in renewing water discharge permits are raising new challenges for oil and gas development.
Wright also cautioned that, although there are explorers who want to drill offshore using a jack-up rig, a realistic time frame to bring a new offshore gas field on line, taking into account exploration, field appraisal, engineering, platform construction and development drilling, would likely be 10 years.
And, although there may well be potential to find new Cook Inlet natural gas resources in stratigraphic traps, subtle traps formed by the juxtaposition of rock strata, rather than the big structural traps of the established gas fields, discovering those subtle traps would be a major challenge, given the limitations of Cook Inlet seismic data. Essentially, the ancient river channels that would have generated these traps are quite narrow and cannot be resolved in the existing seismic, Wright said.
Other options Other options being considered to bring new natural gas resources into Southcentral Alaska include a direct “bullet line” from the North Slope, or a spur line from a future main North Slope gas line. But first gas from a bullet line would be unlikely to appear before 2018, and first gas from a spur line might not flow until 2023.
Another possibility would be to import foreign LNG through the LNG plant on the Kenai Peninsula, although negotiating an acceptable LNG supply contract for the small quantities of utility gas required in Alaska could prove challenging, Wright said. And then there are possible alternative energy sources such as hydropower, geothermal power and CIRI’s recently announced underground coal gasification plant.
But with so much uncertainty about the future, finding solutions will take a concerted effort by everyone, Wright said.
“We firmly believe that the best way to solve problems is through public and industry awareness, and working jointly,” Wright said. “… There’s no single entity, not a single producer, not a utility, not the regulatory agencies, not the State of Alaska, that can solve this problem on its own.”
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