|
A gas supply challenge
Enstar and Cook Inlet producers describe the issues that they are facing
Alan Bailey Petroleum News
During a Feb. 7 joint meeting of Alaska House and Senate Resources committees, executives from Enstar Natural Gas Co. and Cook Inlet gas producers described the challenges that they are facing in maintaining adequate supplies of natural gas for Southcentral Alaska. Gas is the primary fuel used for the heating of buildings and the generation of electricity in the region. Current projections show that gas deliveries from Cook Inlet gas and oil fields could start to fall short of needs as early as 2025, with supplies declining steadily thereafter.
For Enstar, the critical factor is to maintain adequate pressure in its gas transmission lines. Should the pressure drop and deliveries to customers fail, restarting the gas delivery system safely would require a major, time-consuming project. And so, should there be a gas shortage, gas supplies used for power generation would be curtailed first.
Hilcorp Alaska is by far the dominant gas producer in the Cook Inlet basin. Hilcorp produces gas from a number of oil and gas fields, offshore and onshore, around the basin. Furie Operating Alaska produces gas from its Kitchen Lights gas field offshore in Cook Inlet. Vision Operating produces gas from its North Fork gas field on the Kenai Peninsula. And BlueCrest Energy produces a small amount of gas in association with its Cosmopolitan oil field offshore the southern Kenai Peninsula. Other small gas fields consist of Amaroq Resources' Nicolai Creek field, on the west side of the inlet and AIX's Kenai Loop field on the Kenai Peninsula. Cook Inlet Energy's two fields, Redoubt Shoal, offshore on the west side, and West McArthur River, produced from onshore on the west side, produce small amounts of gas along with oil.
The Hilcorp announcement John Sims, president of Enstar, told the committee that on April 12, 2020, Hilcorp informed the Southcentral utilities that it did not plan to extend its current gas supply contracts at the same level as in the past and that, consequently, anticipated reducing the level of firm gas supplies that they could deliver to the market. The issue centers on contracts for firm, guaranteed gas supplies, as distinct from interruptible supplies.
Sims commented that with interruptible contracted supplies there is no penalty if the producer does not deliver, there is no set quantity of gas to deliver and typically there is no set price.
Homer Electric Association would be impacted first by the gas delivery shortfall, with its Hilcorp supply contract terminating at the end of March of this year. Enstar has negotiated a one-year contract with Hilcorp to enable the gas utility to supply gas to Homer Electric into next year. Most other firm contracts with Hilcorp expire in 2027 and 2028.
Sims said that three days after the Hilcorp announcement the utilities formed a working group to address the gas supply problem. And the utilities subsequently hired Berkeley Research Group to lead the effort, with a number of other companies also involved.
Reviewed potential options The team reviewed a list of all potential options for addressing the pending gas shortage, including new gas exploration and development in the Cook Inlet basin; a gas pipeline from the North Slope; and various options for importing liquefied natural gas. None of the options appeared capable of meeting a target of assuring reliable gas supplies in time. Sims commented that the earliest that a fully functional LNG importing arrangement can be brought into operation is 2030. A major issue would be the time taken to obtain the various permits required, he said.
He said that the LNG option that would start in 2030 would likely have gas costs around $16 per thousand cubic feet, mcf, compared with the current cost of around $10 per mcf. An interim arrangement for obtaining out-of-region gas before then might result in gas costs of $30 or more per mcf.
Much as he dislikes the concept of importing LNG to Alaska, LNG imports would become firm, rather than interruptible, supplies, Sims said. He also cautioned that, while renewable energy such as wind power can deliver energy on an annual basis, this type of energy source cannot be relied on as immediate dispatchable power to support peak demand days.
Sims urged the need for more drilling in the Cook Inlet basin. In 2023 just one entity, Hilcorp, was actively drilling. And, as the volumes of firm gas supplies drop, the weather temperature at which a gas supply crisis as was experienced recently can happen will rise, he warned.
Hilcorp remains fully committed Luke Saugier, senior vice president of Hilcorp Alaska, spoke to the committees about his company's work in maintaining its gas supplies from the Cook Inlet basin, and the challenges that the company faces. He emphasized that the company remains fully committed to the basin and is not pulling back its investments or activity levels in the basin.
The company fully owns and finances its Cook Inlet oil and gas fields, apart from the Beluga River field, which it owns with Chugach Electric Association.
The company drilled 22 wells in the basin in 2022 and 23 wells in 2023 and is the only company to have drilled in the basin since 2019, Saugier said. The company plans to drill 15 to 23 wells per year, with an expectation of drilling about 20 wells in 2024, he said.
Insufficient gas reserves under lease And, while the company will continue drilling more wells to maintain gas supplies as much as possible, the gas reserves that the company has under lease cannot meet future demand, Saugier said. The company can only commit to sell gas that is known to exist as formally proved reserves.
Saugier said that, while total gas demand in Southcentral Alaska has remained fairly constant at around 70 billion cubic feet per year, historically Hilcorp has supplied about 50 bcf per year. With Enstar, for example, Hilcorp has produced an increasing proportion of the utility's gas, as supplies from other producers have dropped over the years.
Drilling constraints Saugier commented on some of the constraints that his company faces when drilling in the Cook Inlet basin. One constraint results from winter ice in the inlet -- while this can limit the company's ability to run boats to its offshore rigs, the sea ice also prevents access for drilling on the west side of the inlet. Another major issue is a shortage of support services for drilling. Several years ago Hilcorp purchased some of the drilling rigs in the region, because the owners of the rigs were threatening to remove them, Saugier said. But, while those rigs need people to operate them, low levels of drilling activity in recent years have shrunk the local drilling support industry.
Compounding the problem is the difficulty and time involved in obtaining the federal permits that are commonly required for drilling activities in the Cook Inlet basin, Saugier said.
SUBHED:
Gas storage
Saugier also commented on the availability of gas storage facilities in depleted gas reservoirs in the basin. Gas storage is primarily used to boost gas deliverability during periods of high gas demand. Cook Inlet Natural Gas Storage Alaska operates a major gas storage facility, south of the City of Kenai on the Kenai Peninsula. The CINGSA facility is a public utility, in which utilities and other entities reserve space in support of their gas deliverability needs.
Hilcorp has three storage facilities that the company uses to ensure that it can meet its contractual gas delivery obligations. The company's Pool 6 storage facility in its Kenai gas field is particularly large, to the extent that Hilcorp does not fully use it. Hilcorp could potentially offer some gas storage to be available on the market, Saugier suggested.
During a presentation to the House Energy Committee on Feb. 6, Arthur Miller, CEO of Anchorage-based Chugach Electric Association, commented that his utility is investigating the possibility of developing a gas storage facility in the Beluga River gas field and is conducting preliminary engineering to establish a potential storage capacity. The Railbelt electricity utilities make extensive use of gas fired power generation for reliable power supplies, although Chugach Electric and Matanuska Electric Association have some capability for more expensive diesel fueled generation.
Furie and the Kitchen Lights unit During the joint House and Senate Resources Committee meeting Mark Slaughter, chief commercial officer for Hex and Furie Operating Alaska, talked about his company's efforts to sustain the delivery of gas from its offshore Kitchen Lights unit. The gas is produced from the company's Julius R offshore platform and delivered to an onshore processing facility through a subsea pipeline. The field first went into production in 2015, Slaughter said. Hex acquired the field in 2020 and since then has been active in purchasing additional leases in the basin.
And the company recently purchased from the state some additional seismic data, to help refine potential drilling targets in the unit.
John Hendrix, who purchased the field in 2020, sees a vision for the Cook Inlet and for producing resources in the state, Slaughter said.
Last year the company conducted workovers on two of the four wells at the platform at a cost of $10 million. Unfortunately, however, one well remains incapable of production, so that only three wells are producing gas. But, with three wells producing, the company was able to increase production by 20% ahead of the recent winter cold snap.
One issue that the company has encountered results from the fact that two of the four production wells were developed without sand control -- this factor limits production from those wells. However, wells with sand control are much more complex and costly to drill, Slaughter said.
Potential drilling Looking forward, the company is reprocessing seismic data and reviewing well logs, with a view to identifying new drilling targets. Potential targets under the platform could double production. The company also has plans to sidetrack one of its wells.
However, it is only possible to drill from a jack-up rig, and that has to happen during the summer. There is only one jack-up rig in the inlet and Hilcorp currently has that rig under contract. Furie has been working on the permits needed to move the rig, presumably with a view to coming to some commercial agreement with Hilcorp for the use of the rig. Hex Furie has the capability to self-finance the drilling this year, Slaughter said. But there are long lead time items needed for the drilling. It could be possible to bring new gas to the market within 60 days of starting drilling, Slaughter said.
The company has also acquired some onshore leases with gas potential on the west side of the Kenai Peninsula. This is an exploration play, with first gas production perhaps 15 to 24 months into the future, Slaughter said.
Overriding royalty interests Slaughter commented that a particular problem with investing in the Kitchen Lights unit arises from the fact that the unit is subject to 12.5% overriding royalty interests in addition to the state's 12.5% royalties. Moreover, a 10% carried working interest for the unit owners increases Hex Furie's portion of the capital cost of any development. This all degrades the economics of further development in the unit.
Slaughter said that the company has sought royalty relief from the state, so far without success. The company has also unsuccessfully tried to buy out the owners of the overriding royalty interests.
But a new drilling program at Kitchen Lights could easily double field production, Slaughter said.
Undeveloped gas resources at Cosmopolitan Benjamin Johnson, CEO of BlueCrest Energy, talked about major, undeveloped gas resources in the Cosmopolitan oil and gas field offshore the southern Kenai Peninsula. BlueCrest is producing oil and a small amount of natural gas from the field using directional drilling from an onshore well pad. However, there are major gas resources in sand reservoirs above the oil reservoirs. Unfortunately the gas reservoirs are too shallow to enable development by drilling wells from onshore. An offshore platform is required, together with a subsea gas pipeline to transport gas to the onshore gas infrastructure.
In addition, if there were an offshore platform, BlueCrest could use a well from the platform to pump water into the oil zones below the gas reservoirs, to improve oil production, Johnson said.
There are 235 bcf of proven gas reserves in the field -- gas production from the field could support 24% of Cook Inlet gas demand, Johnson said. The gas resource has been demonstrated through more than 25 well penetrations and the evaluation of 3D seismic, he said.
BlueCrest has carried out preliminary permitting work for a potential development, as well as most of the engineering and design work for the placement of a platform and associated pipeline. Detailed construction design remains to be done.
The missing piece is the required investment funding, estimated at around $400 million. Upon the receipt of funding, the gas field could be online in around 30 to 40 months, Johnson said.
|
