The Producers 2018: Exxon advancing two Point Thomson fronts
Company is working to reach immediate 10,000 barrel per day target while also negotiating with the state over expansion
for Petroleum News
Rare among the development plans filed with Alaska oil and gas officials, the plan of development for the Point Thomson unit includes two components. One component covers an existing development at the unit. The other covers a future expansion project.
The two components acknowledge the unusual state of Point Thomson: the development activity underway does not represent the full potential of the eastern North Slope unit.
The existing development is producing a small amount of condensate and cycling the resulting natural gas back into the reservoir. The future expansion would dramatically increase the amount of condensate production and ship gas to the Prudhoe Bay unit.
Complications underlie both of those efforts.
The existing development, or Initial Production System, was supposed to produce 10,000 barrels of condensate per day and recycle 200 million cubic feet of natural gas per day.
Since operator ExxonMobil Alaska Production Inc. brought the unit online in April 2016, average production has consistently fallen short of that target, often by a large amount.
Through the first half of 2018, for example, the unit was online for an average of 22 days per month, and condensate production ranged from 5,200 barrels to 9,100 barrels per day.
As of early August 2018, the unit was shut down for an undisclosed amount of time to conduct unspecified maintenance work. “The advanced equipment at the facility requires rigorous inspection and maintenance protocols to ensure safe operation,” Hans Neidig, public and government affairs manager for Exxon in Alaska, told Petroleum News.
The chief complication facing the Initial Production System is the high-pressure sands of the eastern North Slope - 10,000 pounds per square inch, according to ExxonMobil.
The company claims that the field pressure at Point Thomson is higher than any other field in its global portfolio and perhaps any producing field in the world. The situation required Exxon to commission special “industry first” compressors at Point Thomson.
The 10,000-barrel-per-day figure was included a plan of development covering Point Thomson unit activities from 2012 through 2017. Even though state Division of Oil and Gas Director Chantal Walsh noted that ExxonMobil failed to meet the production target and two other work commitments included in the plan - to propose debottlenecking activities and to address plans for a future East Pad - she ultimately approved a new plan of development addressing Initial Production System activities running through 2019.
The new plan focused on continuing Initial Production System operations and did not include plans for any additional wells or any advancement of the East Pad and only included a vague commitment to consider debottlenecking activities, according to Walsh.
In a long rebuttal from October 2017, the company maintained that its activities at the Initial Production System between 2012 and 2017 met the terms of the original plan.
Walsh ultimately decided that the benefits of the existing production at Point Thomson outweighed her concerns about ongoing production shortfalls and other shortcomings, and therefore she approved the newest plan of development through the end of 2019.
Expansion plansThe bigger challenge at Point Thomson is and always has been its future.
In her August 2017 ruling approving the Initial Production System plan of development, Walsh rejected the associated plan of development for the Point Thomson expansion.
Walsh was opposed to conditional clauses in the plan that would have allowed ExxonMobil to back out of the expansion project if its partners decided not to proceed.
In an October 2017 document released after a meeting with state officials, ExxonMobil provided “explanatory detail and clarification” about its plans for the expansion project.
The proposed project would expand condensate production to more than 50,000 barrels per day and to ship 920 million cubic feet of natural gas per day to the Prudhoe Bay unit.
The proposal also included plans to drill two production wells and one disposal well from the Central Pad and to convert the PTU-15 and PTU-16 injection wells to production.
According to the state, Exxon effectively eliminated the conditional clauses from its plans by noting that it “does not condition all planning work on agreement on terms for delivery of gas to Prudhoe Bay, and engineering and permitting work is ongoing.”
In her ruling approving the plan, Walsh wrote, “If the PTU Working Interest Owners do not fund the planning work or enter a commercial agreement with the Prudhoe Bay Unit working interest owners, those events will not in any way absolve Exxon from fulfilling its obligation to complete the planning work promised in the Revised Planning POD.”
The expansion was one of the conditions of a 2012 settlement between Exxon and the state over the nature of the development activities completed up to that point at the unit.
The condition required Exxon to either increase the Initial Production System to 30,000 barrels of condensate per day or to ship natural gas to the Prudhoe Bay unit for injection.
The expansion clause was triggered when Exxon and its partners failed to sanction a major gas sale by June 2016. The settlement required Exxon to submit a plan by the end of 2019 for expanding the Point Thomson development. But in a letter from September 2018, the state stayed the deadline so long as the Alaska LNG Project is progressing.
Eastern North SlopeFor decades, the conversation about Point Thomson has focused largely, and at times exclusively, on its importance to any future North Slope natural gas pipeline project.
In the years since the Point Thomson unit came online, an additional topic has become increasingly popular: the importance of the unit to other prospects in the vicinity.
By constructing pipeline infrastructure at the Point Thomson unit, Exxon changed the economics of adjacent and nearby lands and waters across the eastern North Slope.
The independent 88 Energy recently commissioned the 251-square-mile Yukon Gold 3-D seismic survey over its Yukon Gold prospect south of Point Thomson. The company acquired the property in late 2017 through a lease sale, attracted in part by the results of the Yukon Gold well drilled by BP Exploration (Alaska) Inc. in 1993 and 1994. The state has estimated that the prospect contains some 120 million barrels of recoverable oil.
The Point Thomson facilities would also be crucial to any future development activities at Area 1002 of the Arctic National Wildlife Refuge. Exploration activities in the area have been advancing in recent months after decades since the most recent drilling work.
The crucial infrastructure in both cases is the Point Thomson Export Pipeline connecting the Point Thomson unit to the Badami unit and onward to the trans-Alaska oil pipeline.
In August 2018, PTE Pipeline LLC proposed a rate of $20.84 per barrel for the 22-mile liquids pipeline, up from a rate of $12.09 per barrel that went into effect in April 2017.
The shipping rate is based on actual and estimated throughput on the 70,000-bpd pipeline.