Producing inlet gas
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Cook Inlet natural gas producers describe issues, production, plans for future
Kristen Nelson Petroleum News
What is being done to offset declining natural gas production in Alaska’s Cook Inlet? Three Cook Inlet operators, including the two largest and a company with a significant but undeveloped natural gas field, talked to the Alaska House Special Committee on Energy on Feb. 21.
Hilcorp Alaska is Cook Inlet’s major natural gas producer, operating more than 90% of Cook Inlet gas by volume in December; Furie Operating Alaska operated some 5% of inlet natural gas production in that month, the most recent for which Alaska Oil and Gas Conservation Commission data by field is available; and BlueCrest, primarily an oil producer with associated gas, accounted for less than 1% of inlet gas production.
Hilcorp Asked about Hilcorp’s warning to Cook Inlet utilities about long-term contracts, Luke Saugier, Hilcorp’s senior vice president Alaska, said the utilities are Hilcorp’s customers and the company wants to give them as much transparency as possible. All fields decline, he said, and over the past 5 years, Hilcorp has been the only company drilling wells in Cook Inlet.
Hilcorp is maintaining its supplies, he said, but hasn’t seen other companies drilling, which is not an ideal situation, because without drilling the gas supply will decline.
Hilcorp is doing everything it can, he said, but if the market needs more, there isn’t an infinite supply and Hilcorp has contracted for all the gas it has.
Redundancy is important for deliverability of gas, Saugier said, and Hilcorp maintains three of the four gas storage operations in the inlet. The Kenai gas field is the company’s largest storage facility, with one reservoir dedicated to storage with 540 billion cubic feet of storage available and 12 bcf in storage today, stored at low pressure and sent through compressors when the company wants to remove it.
At Swanson River, Hilcorp maintains high-pressure gas storage, with a 3 bcf capacity. Think of this, Saugier said, as an emergency supply which would flow naturally even if there was no power.
The smallest, and the only storage on the west side, is Pretty Creek. He said this is very small, almost 1 bcf, and typically empties every winter.
The company also has redundant compressors and multiple delivery points to pipelines, Saugier said.
Hilcorp in Alaska Hilcorp began operating in Cook Inlet in 2012 and has spent more than $750 million on capital projects in the inlet since then, with those projects directed to production of natural gas, Saugier said.
Over the next 10 years the company plans to spend that much or more, he said.
In addition to drilling and doing workovers, Saugier said Hilcorp has brought new and innovative technologies to the inlet, including new drilling rigs, new offshore and onshore pulling units and new vendors. It has also applied modern technology, 3D seismic, improved stimulation and horizontal drilling. The company owns two rigs, he said, one working on the west side and one working on the Kenai Peninsula, rigs which have been used by other operators.
Looking ahead, Saugier said the company is investing in new wells, wellwork to add production rates and exploration and drilling, and plans to invest hundreds of millions of dollars per year in Kenai and Cook Inlet, with four rigs operating in 2023, 18 wells planned and 41 wells to be plugged and abandoned.
Furie John Hendrix, president and CEO of Furie Operating Alaska, said the company’s goal is to increase its gas production. Furie produces natural gas only from its platform in Cook Inlet at the Kitchen Lights unit.
Hendrix told the committee HEX Cook Inlet purchased Furie in July 2020. Since then, he said, they have stabilized production, providing natural gas to Enstar, Marathon Petroleum, Matanuska Electric Association, Homer Electric Association, Chugach Electric Association and the Interior Gas Utility.
In 2023, he said, the company plans to finalize re-processing of 3D seismic and well data and mobilize a new workover rig to Alaska to work over and repair two wells, 50% of the unit’s four producing wells. Hendrix said the goal is to increase production for the winter of 2023-24.
But there is uncertainty, he said, over the cost and the duration of the work, with issues including mobilization of the new rig to Cook Inlet, potential difficulties in performing the work and the impacts of weather, especially later in the season.
Hendrix urged the state to reduce royalties and provide production tax relief, as well as releasing seismic data, providing a just and fair property tax, reducing bonding obligations and eliminating duplicative bonding requirements.
BlueCrest BlueCrest President and CEO Benjamin Johnson told the committee that BlueCrest, which produces oil with associated gas at its Cosmopolitan field on the Kenai Peninsula, has a separate gas field. The Tyonek gas sands, which lie above the oil reservoirs the company is currently producing, are too shallow to be reached from onshore wells, he said.
Multiple wells have been drilled through the gas zones, which have a proved but undeveloped volume of 234 billion cubic feet with flow tests confirming high productivity, and the size and shape of the structure documented by 3D seismic.
Johnson said the gas zones are similar to the Ninilchik field, some 15 miles to the north and currently the largest Cook Inlet gas producer.
The gas at Tyonek was discovered in the Starichkof State 1 drilled in 1967 and confirmed in the Cosmopolitan State 1 drilled in 2013, both drilled by jack-up rigs, with flow tests done at the 2013 well.
Johnson said there are 12 gas sands at the Cosmopolitan Tyonek gas field, which is “proved” but undeveloped.
Because of the requirement for a platform, it will cost hundreds of millions to develop that resource, Johnson said, but it could produce up to 50 million cubic feet per day.
Johnson said this is dry gas, with no liquid hydrocarbons. It would require a 3-mile subsea pipeline to the company’s onshore facility, and he said recent seafloor surveys confirm a safe pipeline route, while the onshore facility is already connected to the Enstar pipeline system.
The design of platform and facilities and cost estimates are largely completed, he said, with the platform gas wells to be done with standard Cook Inlet drilling and completion.
From funding to first gas would be 30 to 40 months, Johnson said.
He said the critical path is finding investors.
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