ExxonMobil Alaska Inc. is sometimes described as a silent partner in Alaska.
Even though the company was not operating any producing assets in the state when 2015 began, and hasn’t for years, the company has been around a long time. It opened its first Alaska field office in 1921 and drilled its first Alaska well in 1926. Since then, it has drilled exploration and development wells on the North Slope and in Cook Inlet, and has explored almost every frontier basin in the state: the Gulf of Alaska, the Arctic Ocean, the Bering Sea, Bristol Bay, the Copper River basin and the Brooks Range foothills.
Exxon helped discover the Kuparuk River unit, the Point Thomson unit, the Duck Island unit and several smaller prospects across the North Slope still awaiting development. In Cook Inlet, Exxon played a role in discovering Ninilchik, Granite Point and Moquawkie.
ExxonMobil was created through a 1999 merger. Since the merger, the company in Alaska has primarily focused on the North Slope, although it became a Cook Inlet operator after its parent acquired the independent XTO Energy Inc. in 2010. The acquisition made Exxon the ultimate owner of the XTO-operated Middle Ground Shoal field, although XTO recently sold the offshore Cook Inlet field to Hilcorp Alaska LLC.
Along the way, Exxon was also at the center of the largest oil-related disaster in Alaska with the 1989 grounding of the Exxon Valdez tanker and one of the largest political controversies with the ongoing disputes over how to develop the Point Thomson field.
Today, Exxon is primarily concerned with two Alaska ventures. The first is its effort to bring the Point Thomson unit into production. The other is the Alaska LNG project.
The Point Thomson unit
As the Producers went to print, ExxonMobil Alaska Production Inc. was in the final stages of bringing condensate production online from the Point Thomson unit.
Over the past few years, the local subsidiary of the global energy giant has been drilling development wells and building production facilities at the eastern North Slope natural gas and condensate field. And over the past few months, the company has been filing some of the final permits required to bring the long-awaited field into operation.
In late August, the Alaska Oil and Gas Conservation Commission approved a request from Exxon to inject natural gas into the field reservoir, which is a crucial technical requirement for the “Initial Production System” Exxon has planned for Point Thomson.
Also, Exxon applied for AOGCC pool rules at the field and applied to the Regulatory Commission of Alaska for permission to connect the Point Thomson production facilities to the Point Thomson Export Pipeline System, which would carry supplies to market.
As part of those filings, Exxon said it expects the system to be operational by December 2015, although the regulatory process might push the actual startup into January 2016.
Either way, the event will mark a milestone in the history of the North Slope. Point Thomson is one of the oldest and largest undeveloped fields in northern Alaska and has been a point of contention between the company and state officials for decades. Given the importance of the field for any future major natural gas sales from the North Slope, the start of condensate production from Point Thomson marks an “end of the beginning” rather than a “beginning of the end.” If plans for a large-diameter natural gas pipeline come to fruition, Exxon and state officials will have to decide when and how to phase out gas-cycling for condensate production and phase-in gas production to feed the pipeline.
50 years in the making
The original leases at Point Thomson were issued around 1965. Exxon discovered oil in the area in 1975 and natural gas in 1977 and formed the Point Thomson unit later that same year. Although Exxon and other companies had drilled 17 wells by 1983, a series of technical, economic, legal and regulatory challenges delayed development for decades.
Those delays eventually tried the patience of state officials, setting off a complex legal and regulatory battle. The debate largely concerned two competing development strategies for the field: Was it economically and technically wiser to prioritize condensate production or gas production? The two strategies involved two very different timelines.
Believing Point Thomson was ready to be developed, the Alaska Department of Natural Resources put the unit into default in 2005 and terminated the unit in late 2006. Exxon and its partners appealed the decision, and an Alaska Superior Court judge sided with the companies and sent the matter back to the state in December 2007. The state ultimately rejected a new plan of development for the unit in April 2008 and the producers appealed the decision to Superior Court, which sided with the companies. The Alaska Supreme Court granted a petition from the state for review, halting the Superior Court litigation.
The debate was as much a public relations battle as a legal or a regulatory one, as shown by an odd fact: while the two sides were arguing in court, the state gave Exxon permission to drill the first two wells at the unit in several decades: PTU-15 and PTU-16.
Through a court-ordered settlement reached in early 2012, the state and Exxon created a timetable for bringing Point Thomson online by early 2016 and subsequently expanding development. The Initial Production System is the first part of that timetable and aims to produce some 10,000 barrels per day of liquid condensate while cycling some 200 million cubic feet per day of residual gas into the field. Originally, the system was envisioned as having two injection wells and one production well. In May 2015, the company said it might initiate production from the two existing wells, using PTU-15 as a producer and PTU-16 as an injector. Once the PTU-17 well is completed, it would become a producer and the entire operation would revert to the original specifications.
The AOGCC approved a drilling permit for PTU-17 on Aug. 4, which may or may not provide enough time to complete the well and establish the system by project startup.
While the settlement allowed Point Thomson operations to continue, some challenges remained. In 2012, prior to being elected governor, Bill Walker sued to prevent the settlement from proceeding, calling it “a giveaway of historic proportions” and claiming that state officials had exceeded their authority and had violated state regulations.
In early 2015, after taking office, Walker agreed to drop the suit but filed legislation designed to regulate future settlements related to oil and gas activity in the state.
What comes next?
Once the field is operational, the next issue to address is expansion.
The current expansion plans present three alternatives: sanctioning major gas sales by June 2016, expanding liquids production to at least 30,000 barrels per day by 2019 or integrating Point Thomson and Prudhoe Bay operations to mutually improve recovery.
If the Initial Production System is successful at producing condensate from the high-pressure Point Thomson reservoir, focus will likely shift to the role of the field in major gas sales. The field is generally considered to hold 25 percent of the known natural gas reserves on the North Slope and is likely to be crucial for making a pipeline economic.
In its pool rules application, Exxon said it would prefer to transition from the Initial Production System directly into exporting natural gas, rather than expanding condensate production. Under its proposed scenario, Exxon would produce some 820 million cubic feet per day from Point Thomson with peak production of 920 million cubic feet per day during winter. The company is asking regulators to approve an annual average rate of 1,100 million cubic feet per day to allow for operational and engineering flexibility.
Even under that scenario, Point Thomson would continue to produce small amounts of condensate, although much less than if condensate production was given priority.
Exxon is skeptical about the economic viability of expanding condensate production. In its pool rules applications the company wrote: “Major impediments were the limited amount of condensate that could be recovered, the high cost of the facilities and wells, and the significant risks associated with a gas cycling development.” While acknowledging that the Initial Production System would provide useful information about the reservoir, “no scenarios have been identified in which this information would materially improve the current outlook for the viability of expanded gas recycling,” the company said.
As far as the prospect of integrating Prudhoe Bay and Point Thomson, Exxon believes that strategy depends largely on progress of the larger AK LNG project. While using Point Thomson gas for Prudhoe Bay field operations could accelerate Point Thomson gas sales by two years, the acceleration is unlikely to justify the cost of implementation.
Under the current proposal for the AK LNG project, 75 percent of the natural gas supplies for the pipeline would come from Prudhoe Bay with the remaining volumes coming from “other sources,” of which Point Thomson is one likely candidate.
Generally, the state would prefer expanded condensate production because condensate is currently a more valuable commodity than natural gas and because natural gas is stranded without a pipeline. At an AOGCC hearing earlier this year, Commissioner Cathy Foerster noted that the success of the Initial Production System would determine future development plans. “So it’s critically important to this agency that you’ve done your best job of trying to ensure that you’ve given cycling every chance to succeed,” she said.
While a major gas sale is the most important development hinging on Point Thomson, the field will also likely become important to oil development on acreage farther to the east, which is why Exxon built the Point Thomson Export Pipeline to carry as much as 70,000 barrels per day, far larger than current needs. The RCA certified the pipeline in November 2012 and approved its connection to the neighboring Badami unit in August 2013. Exxon installed the 22-mile along the Beaufort Sea coastline during 2014. The final administrative requirement is connecting the pipeline to the Point Thomson facilities.
