Vol. 25, No.44 Week of November 01, 2020
Providing coverage of Alaska and northern Canada's oil and gas industry

The Producers 2020 preview: Exxon takes two paths at Pt. Thomson

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Longtime Alaska player pursuing AGDC and Qilak LNG projects; remaining gas injection components from manufacturer coming this year

Eric Lidgi

for Petroleum News

For the past 43 years, the Point Thomson unit has been widely viewed as one of the saviors of the North Slope basin: a major field with resources that could help the State of Alaska shift from an oil-based economy to an industrial economy based on natural gas.

But to date, the story of the unit has been one of future promise.

Its first 35 years were consumed by inactivity and then by regulatory and legal debates between the State of Alaska and operator ExxonMobil Alaska Production Inc. Then came four years of construction, eventually leading to sustained production in early 2016.

Even with that milestone, Point Thomson is far from its full potential - an opinion held by ExxonMobil, the State of Alaska, nearby leaseholders, and the oil patch generally.

The Point Thomson unit is currently producing between 9,000 and 9,500 barrels per day of condensate. That is a shortcoming by two important measurements. First, it is below the 10,000 barrel per day minimum required by a settlement agreement with the state.

Second, condensate is not the ultimate goal of the unit. Point Thomson contains 8 trillion cubic feet of natural gas - a quarter of the known, recoverable resources on the North Slope. Those resources are currently constrained by the lack of a viable route to market.

The current Point Thomson Initial Production System produces natural gas entrained with condensate from the PTU-17 well. The natural gas is removed from the stream and injected back into the field using the PTU-15 and PTU-16 wells. The condensate is shipped through the Point Thomson Export Pipeline to the trans-Alaska oil pipeline. The system is designed to cycle as much as 200 million cubic feet of natural gas per day.

The unit produced 5,200 barrels per day during the 18 months ending July 31, 2019 - an average taken from various high and low swings. The unit hit a peak of 10,700 barrels per day in December 2018, exceeding the minimum rate required by the settlement.

During the same period, the unit produced 95.9 million cubic feet of natural gas per day, cycling 93 million back into the field. (The remaining 2.9 million cubic feet was used as field gas to support operations at the unit.) As with condensate production, average daily natural gas production peaked in December 2018, with 199.4 million cubic feet per day.

At issue are the extreme pressures found at the field. According to Exxon, the gas injection equipment has struggled in recent years, leading the company to work with its manufacturer on improvements. The first of those new components was installed in July 2019. The company said that it expected the remaining components to arrive this year.

Next steps

The 2012 settlement proposed three possible paths for Point Thomson after the start-up of the Initial Production System. ExxonMobil could either sanction a major gas sale by 2016, expand liquids production to 30,000 barrels per day by 2019, or integrate Point Thomson into the Prudhoe Bay unit by shipping gas supplies to improve oil recovery.

To date, none of those have occurred.

ExxonMobil insists that a major gas sale is the best of all possible options. Its most recent plan of development touts various efforts toward that goal in recent years. Even so, those efforts have not been enough to justify the sanctioning of the multibillion-dollar project.

A 2017 settlement allowed ExxonMobil to expand condensate production or to integrate the unit with Prudhoe Bay. ExxonMobil preferred the latter option but was delayed by the need for reaching a commercial agreement with the owners of the Prudhoe Bay unit.

In a September 2018 agreement, Alaska Department of Natural Resources Commissioner Andy Mack deferred the 2019 deadline for expanding liquids production while ExxonMobil was advancing the Alaska LNG project to bring gas to market. Whenever the project reaches a final investment decision or the state determines that the project has stalled, the Point Thomson owners will have 30 months to advance or will lose acreage.

ExxonMobil is involved in two possible projects to bring North Slope gas to market. The first is the Alaska LNG project being overseen by the Alaska Gasline Development Corp.

Under its previous plan of development, covering 2018 and 2019, ExxonMobil worked with the public corporation on financial and technical matters related to the project.

Alaska LNG received a final environmental impact statement from the Federation Energy Regulatory Commission in March 2020, a milestone years in the works. The Alaska Gasline Development Corp. later received a final order from federal regulators.

The Alaska Gasline Development Corp. is now looking for a private sponsor who could take over the $38.7 billion project to build a large diameter pipeline through the state to a new liquefaction facility in Nikiski. The goal is to step back sometime later this year.

ExxonMobil is also pursuing a second possibility for marketing Point Thomson supplies.

In October 2019, the company signed an agreement with Qilak LNG Inc. to supply at least 560 million cubic feet per day of natural gas to a newly proposed LNG project.

The gas supplies from Point Thomson would be used for Phase 1 of the Qilak LNG 1 Project, a proposed $5 billion nearshore liquefied natural gas facility that the Alaska subsidiary of Lloyds Energy of Dubai wants to build near Flaxman Island. Qilak LNG is looking to ship between 4 million and 6 million tons of LNG per year to customers in the Indo-Pacific region as soon as 2025 or 2026, using a fleet of icebreaking LNG tankers.

The full vision for the project would require additional producers. “The agreement at the moment is exclusively with Exxon; once we’re able to talk to Hilcorp, once they take over the BP interests, then we hope to have enough gas to increase that to at least 6 million tons,” Qilak President and COO David Clarke told Petroleum News at the time.

Hilcorp later closed on its acquisition of the remaining BP Exploration (Alaska) Inc. holdings on the North Slope, assuming 32% interest in the Point Thomson unit.

Qilak is now conducting an extensive feasibility study including preliminary permitting work this year with the goal of reaching a final investment decision sometime in 2021.

The Qilak project is smaller and cheaper than the state-backed Alaska LNG project. The advantage, according to Qilak, is cost. According to its figures, the Alaska LNG Project would cost some $2,150 per ton of LNG while the Qilak project would cost about $1,250 per ton of LNG. Given that the distance to Tokyo is roughly the same for both projects, the cost of Alaska-based infrastructure is a major factor for determining LNG prices.

Editor’s note: See this story in The Producers magazine, being released in the Nov. 22, 2020 edition of Petroleum News.

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