The Producers magazine preview: Pursuing two fronts at Point Thomson
Operator ExxonMobil’s ultimate goal at eastern North Slope unit is marketing the eastern North Slope field’s 8 tcf of natural gas
One of the earliest explorers in Alaska and one of the primary working interest owners on the North Slope, ExxonMobil did not embark on the $4 billion Point Thomson development just to produce 10,000 barrels of condensate a day. Production of the technically challenged condensates was the result of a settlement agreement between the state of Alaska and ExxonMobil and its minority partners to allow the companies to retain the leases. ExxonMobil’s ultimate goal was to develop and market Point Thomson’s 8 trillion cubic feet of stranded natural gas.
The future export of natural gas from the eastern North Slope field has always been the cornerstone of the state of Alaska’s vision for a North Slope gas export project.
The Point Thomson unit condensates, a liquid hydrocarbon akin to very light oil, were particularly difficult and expensive to produce because of the exceptionally high reservoir pressure of the Thomson sands, and in part because it was a retrograde field in which condensate in the reservoir tended to liquefy as the pressure was drawn down. The need for directional drilling to reach the offshore reservoir sands from onshore drilling pads compounded the difficulties.
2012 settlementFollowing efforts by the state to terminate the Point Thomson unit because of the lack of condensate field development, in 2012 the state and the field’s working interest owners signed a court-approved settlement agreement, specifying terms under which the unit and its leases could be retained.
That settlement agreement spelled out a commitment by ExxonMobil and the other owners to move forward with the Point Thomson initial production system, or IPS, in which natural gas would be continuously cycled through the reservoir to enable the extraction of up to 10,000 barrels per day of condensate for export along with crude from the North Slope.
The purpose of the IPS was to test the viability of the gas cycling process. Reinjecting produced natural gas into the reservoir maintained pressure for future gas production
In 2016, ExxonMobil put the Point Thomson unit online, the only field the mega major operated in Alaska. (The $4 billion was invested through the end of 2015.)
The Point Thomson unit West Pad facilities were designed to eventually produce 10,000 barrels per day of condensate a day, whereas Central Pad facilities were designed to reinject 200 million cubic feet per day of recycled gas, although each began with half of that amount.
The Point Thomson startup was a long-awaited culmination of a process that began with initial leasing in 1965, oil pool discovery in 1977 (by ExxonMobil at the Point Thomson Unit No. 1 wildcat exploration well) and confirmation in 1978 and 1979 (Point Thomson Unit No. 2 and No. 3 wells), with unitization in 1977.
By 1983, ExxonMobil and other companies had drilled 17 PTU wells.
There were technical, economic, legal and regulatory challenges to development, but the issue came down to prioritizing condensate vs. prioritizing natural gas production.
For years the state deferred pressure on the Point Thomson owners to develop the field because there was no way to get condensate or natural gas to market - Prudhoe Bay and Pump Station 1 of the trans-Alaska oil pipeline were 60 miles to the west.
The Badami field came online in 1998, providing an oil pipeline covering approximately half the distance. A connecting line from Badami to Point Thomson was then built by ExxonMobil as part of its 2012 through 2017 plan of development with the state.
There was still no gas pipeline to take the field’s major resource, natural gas, to market. Its problem has always been the ability to compete internationally on price given the very costly 800-mile gas pipeline that would have to be built and the easy availability of cheaper sources of gas near tidewater.
Three alternativesThe 2012 settlement had included three alternatives for expansion beyond the 10,000 bpd of condensate.
The first alternative was the sanctioning of major gas sales by June 2016, which timewise the parties agreed could not be done.
The second option was expanding liquids production to at least 30,000 bpd by 2019.
The third option was integrating Point Thomson and Prudhoe Bay operations to improve recovery, which involved building a gas line to Prudhoe for reinjection.
When ExxonMobil applied to the Alaska Oil and Gas Conservation Commission for pool rules for Point Thomson the company said it would prefer to transition from the present phase, the IPS, directly into exporting natural gas.
The company told the commission it was skeptical about increasing condensate production because of major technical challenges and the high cost of the facilities and wells.
As for integrating Point Thomson and Prudhoe Bay, ExxonMobil said while that would accelerate Point Thomson natural gas sales by two years, the acceleration would be unlikely to justify the cost of implementation.
Settlement deadline deferredThe 2012 settlement had required a plan for expansion of Point Thomson production by the end of 2019 if a major gas sale hadn’t been sanctioned by June 2016.
Late in 2017, the state and ExxonMobil reached agreement on the expansion.
The settlement required either increasing production to 30,000 barrels per day of condensate or moving natural gas to Prudhoe Bay for injection there and construction of a gas pipeline between the fields. Moving natural gas to Prudhoe was ExxonMobil’s choice in the 2017 agreement, but the thing that made that challenging was it would require a commercial agreement with all the Prudhoe Bay owners. Gas balancing would have been part of the challenge, especially since Point Thomson natural gas was higher quality than Prudhoe gas.
That work was deferred in the Point Thomson Unit Letter Agreement dated Sept. 10, 2018, from then-commissioner of the Alaska Department of Natural Resources Andy Mack after meetings with ExxonMobil and BP (a major Point Thomson working interest owner).
Mack said the 2019 deadline was stayed for as long as the Alaska LNG Project was progressing. The extension was to end when the Alaska LNG Project reached final investment decision or when DNR notified the parties that the project was no longer progressing.
At the end of the extension the Point Thomson owners would have 30 months to reach a final investment decision on either of the expansion projects or lose acreage in the field.
Gas sales agreementAlso Sept. 10, 2018, the Alaska Gasline Development Corp. announced that ExxonMobil and AGDC had agreed to what the state-owned corporation called “certain key terms including price and a volume basis for a Gas Sales Agreement,” captured in an unbinding “Gas Sales Precedent Agreement.”
AGDC and BP, with a 32% working interest in the Point Thomson unit, had agreed to key terms of a gas sales agreement four months earlier, including price and volume.
AGDC had not reached agreement with ConocoPhillips, the other significant North Slope leaseholder with a 5% interest in Point Thomson, and a company with major natural gas interests at the BP-operated Prudhoe Bay. (ConocoPhillips, which is very focused on oil development and production farther west on the North Slope, is still trying to pull out of Point Thomson. Petroleum News sources say the unit owners are still in negotiations.)
In a Sept. 10, 2018. statement on the ExxonMobil agreement AGDC said the parties anticipated finalizing long-term gas sales agreements for ExxonMobil’s share of both Prudhoe Bay and Point Thomson gas. (ExxonMobil had a 62.75% share of Point Thomson and a 36.4% share of Prudhoe Bay.)
“This precedent agreement is good for Alaska and ExxonMobil and represents a significant milestone to help advance the state-led gasline project,” said ExxonMobil Alaska President Darlene Gates at the time. “As the largest holder of discovered gas resources on the North Slope, ExxonMobil has been working for decades to tackle the challenges of bringing Alaska’s gas to market,” she said.
Then-AGDC President Keith Meyer was equally upbeat, as was then-Alaska Gov. Bill Walker, who had made a gas export project a priority of his administration.
Agreement detailsThe Point Thomson Unit Letter Agreement said that for purposes of the settlement agreement an Alaska LNG Project meant a fully integrated natural gas project producing LNG for export and natural gas for in-state delivery being advanced by the state, a state-owned entity such as AGDC “or an entity in which a state owned entity holds a controlling equity share.”
The letter said the June 30, 2017, plan of development, or POD, for Point Thomson, as supplemented in October of that year and approved in August and December 2017, would remain in place until the effective date of a major gas sale POD, an expansion project POD or Dec. 31, 2019, “if an MGS POD or Expansion Project POD has not been submitted.”
The agreement called for submittal of Point Thomson PODs on a biennial basis beginning with the 2020-21 period. Those PODs would address IPS work or other exploration or development, including activities in support of the Alaska LNG Project.
Regarding the extension period, a final investment decision was defined as “a decision by the Alaska LNG Project owners to construct the Alaska LNG Project, following securing the necessary financing arrangements to construct and operate the Alaska LNG Project.”
In the meantimeExxonMobil continues working on the technical challenges at Point Thomson.
From the start in April 2016, condensate output from the IPS has fluctuated from less than 100 bpd to a high of 10,725 bpd in December 2018, although something closer to 5,000 bpd is more common.
In its 2017 POD, ExxonMobil told the state that “production to date has been impacted by gas injection compressor availability and reliability,” referring to the compressors as “industry-first,” which likely explains their serial numbers, 001 and 002.
Development of the Point Thomson field requires handling reservoir pressures upwards of 10,000 pounds per square inch, a pressure corresponding to “the effect of an elephant standing on the end of someone’s thumb,” an ExxonMobil executive said right after the field came online.
Advanced technology, the company has said from early on, has been key to producing the field.
Since each compressor allows the field to produce 5,000-6,000 bpd, one is presumably often offline for maintenance.
Hans Neidig, ExxonMobil’s public and government affairs manager for Alaska, told Petroleum News in late July 2018 while the field was in a warm shut down for maintenance, that the “advanced equipment at the facility requires rigorous inspection and maintenance protocols to ensure safe operation.”
Without referring directly to the compressors, he said, because of “the equipment’s unique nature, more time is needed to replace some components compared with standard, off-the-shelf equipment.”
A state official who asked not to be identified told Petroleum News that summer, “Point Thomson would be tough for any other major to deal with, but ExxonMobil keeps whittling away at the problem. We’re fortunate they’re operating that field. I doubt it would ever have been developed otherwise,” he said, citing “ExxonMobil’s deep pockets and technical savvy.”