The only field ExxonMobil operates on the North Slope is one of the most challenging in Alaska.
Since the global giant discovered Point Thomson in the eastern North Slope in the mid-1970s, the field has presented technical, economic, legal and regulatory challenges.
Those challenges eased enough in 2013 for Exxon to begin the first significant construction at the largest proven undeveloped oil and gas field in the state, and perhaps the country. The work is aimed at bringing the field into production by May 2016.
The work completed this year focused on infrastructure development.
Exxon and its contractors built gravel roads, an airstrip and a pier, installed a permanent work camp at an expanded pad and turned on the lights of their new telecommunications and power systems. The crews also installed more than 2,200 vertical support members, which will hold the 22-mile insulated Point Thomson Pipeline being built this winter.
This work, though, is only the beginning of the beginning.
2012 settlement
Through a settlement reached in early 2012, the State of Alaska and the working interest owners agreed to a schedule for starting and expanding Point Thomson production.
The first step is called the Initial Production System, in which Exxon would produce some 10,000 barrels per day of liquid condensate from two existing wells and cycle some 200 million cubic feet per day of residual natural gas production back into the field.
Only then does the settlement address full field development, which would include a major gas sale, expanded liquids production, or both (depending on the markets).
Under a plan of operations filed soon after the settlement, Exxon proposed drilling a disposal well and up to five producers or injectors — a total which includes the two wells completed in recent years — from west, central and east pads. The three gravel pads would allow Exxon to reach all sections of the reservoir with extended-reach drilling.
The two recent wells are on the central pad. Exxon proposed drilling one well each on the west and east pad, and would site the fifth well based on the results of the previous four.
The Point Thomson unit currently covers 93,291 acres over 38 leases along the Beaufort Sea coastline some 60 miles east of Prudhoe Bay. The long list of working interest owners includes operator-ExxonMobil, BP and ConocoPhillips. In early 2013, Exxon and the state-owned Russian oil giant Rosneft announced a partnership including “potential participation by Rosneft (or its affiliate) in the Point Thomson project in Alaska.”
Technical and economic challenges
The state issued the Point Thomson leases in 1965.
The Alaska State A-1 well in 1975 found oil and gas in the lower Tertiary Flaxman sand, and the Point Thomson Unit No. 1 well in 1977 found oil and gas in the Lower Cretaceous Thomson sand. The state approved the formation of the Point Thomson unit in 1977, as Prudhoe Bay oil began flowing down the 800-mile trans-Alaska oil pipeline.
A delineation effort over the following seven years discovered two additional reservoirs.
Today, Point Thomson is understood to be a high-pressure retrograde gas-condensate reservoir with a viscous oil rim in the Thomson sands, and a smaller oil pool in the shallower Brookian sands. The challenge is how to maximize production of all resources.
The 8 trillion cubic feet of gas at Point Thomson constitute some 25 percent of the known reserves on the North Slope, making the field crucial for the success of a gas pipeline.
Even without the gas resources, though, the hundreds of millions of barrels of liquids at Point Thomson would constitute a major discovery almost anywhere in the world.
Issue of what’s produced first
By producing the gas first, an operator could recover some of the condensate, but the resulting drop in reservoir pressure would liquefy the remaining condensate underground, which would challenge future production. Cycling the gas would maintain reservoir pressure, but would challenge the economics of the project by requiring more complex technology and by delaying gas sales until after the liquids had been suitably depleted.
By cycling gas for 20 years, Point Thomson could yield 620 million to 850 million barrels of oil and condensate, followed by 4.8 trillion to 5.9 trillion cubic feet of gas, according to a June 2008 state-commissioned study by PetroTel Inc. By comparison, the firm estimated, producing the gas first would yield between 210 million to 305 million barrels of liquids and between 6 trillion and 7 trillion cubic feet of gas.
The difference in liquids production represented another Alpine, the report concluded.
At the time, Exxon challenged those figures.
The company said the report made optimistic assumptions about recovery rates in a thin, discontinuous rim of viscous oil. It also questioned the feasibility of gas cycling, which would only maintain reservoir pressure if production and injection wells “communicated,” and would make any gas unavailable to a pipeline for 20 years.
What’s the prize?
The complex technical debate boiled down to a simple question: What’s the prize?
The state argued for the benefits of the liquids resources, which could move to market immediately through the trans-Alaska oil pipeline. The companies argued for the benefits of the gas resources, which required construction of a multibillion-dollar gas pipeline.
In the 2012 settlement, the parties agreed to a gas cycling program. The program starts with limited condensate production, but gives the lessees three alternatives for the future.
Under Alternative A, the producers would sanction a “major” gas sale by June 2016.
With “major” being defined as more than 500 million cubic feet per day, the decision is really about whether the producers are willing to commit to building a gas pipeline.
Under Alternative B, the producers would commit to expanding liquids production to 30,000 bpd or more by 2019. The decision depends largely on whether the Initial Production System proves the feasibility of gas cycling at Point Thomson, but increasing production would also require drilling more wells and expanding processing capacity.
Under Alternative C, the producers would integrate Point Thomson and Prudhoe Bay to increase recovery at both fields. The scheme involves injecting Point Thomson gas into Prudhoe Bay to enhance oil recovery at the aging field, expanding Point Thomson liquids production and dedicating significantly gas volumes for in-state use no later than 2019.
The settlement also requires development of the Brookian oil reservoir by 2018.
Legal challenges
A settlement was required because the technical challenges spawned a legal challenge.
Exxon drilled numerous wells at Point Thomson over the decade following its discovery, but in the early 1980s the company decided it had sufficiently delineated the field, and said any future drilling should promote gas development, which depended on a pipeline.
The Alaska Department of Natural Resources approved development plans without drilling commitments into the 1990s, but grew increasingly impatient with the lack of progress.
The gas cycling option changed the outlook by removing the necessity of a gas pipeline.
Exxon outlined a plan in 2002 to use gas cycling to produce up to 75,000 bpd of liquids, but decided the idea was uneconomic and submitted a development plan in 2005 that called for gas production first. The department rejected the plan, placed the unit in default in 2005 and subsequently terminated the unit in 2008.
Those moves set off a major court battle.
While the case unfolded, though, the state gave Exxon permission to start drilling at Point Thomson, work the company proposed to prove its commitment to bringing the field online by 2014. By late October 2010, Exxon had competed both wells — PTU-15 and PTU-16.
The Alaska Superior Court ultimately reversed the termination of the unit, but as the case went to the Alaska Supreme Court the state and the lessees ramped up settlement talks.
To mollify the state, the April 2012 settlement contains consequences.
If Exxon misses certain early work deadlines, the unit would contract in 2015.
If Exxon fails to bring the Initial Production System online or sanction a major gas sale by 2019, the unit would terminate and all the leases — including those hosting wells capable of producing in commercial quantities — would return to the state. If Exxon fails to expand production beyond the Initial Production System, the unit would contract.
And Exxon would lose its Brookian acreage unless it sanctions development by 2018.
In all these instances, Exxon waived its right to appeal any termination or contraction.
The other challenges
Even with a settlement, though, Point Thomson is far from settled.
By April 2011, the U.S. Army Corps of Engineers was running a year behind schedule on its environmental impact statement for the gas cycling project. The series of delays came from additional studies, and later from revisions Exxon made to the project description.
The delays made it difficult, if not impossible, for Exxon to meet its 2014 deadline for bringing the field online, which is why the settlement gave the company until May 2016.
The Corps released the final EIS in August 2012, and issued a crucial wetlands permit in October 2012, but Exxon acknowledged in late 2012 that it would be a “challenge” to meet the deadline. “We are on schedule, but it is very tight,” Jeff Ray of the Exxon transportation subsidiary PTE Pipeline LLC told the Regulatory Commission of Alaska, which subsequently gave Exxon approval to build the Point Thomson Export Pipeline.
Another challenge came in early 2013, when Exxon encountered high levels of hydrogen sulfide in the PTU-15 and PTU-16 wells. The discovery required Exxon to initiate mitigation measures to keep the acidic gas from damaging well materials, but the company insisted the issue “does not impact the overall schedule” of the development.
The eastern North Slope
Where there are challenges, there are usually opportunities, too.
The 70,000-bpd Point Thomson Export Pipeline is much bigger than Exxon requires for the Initial Production System or its expansion. The big capacity is meant to accommodate the “string of pearls.” The “string” is the pipeline, and the “pearls” are several known oil fields between the BP-operated Endicott field and the Arctic National Wildlife Refuge.
The first of those pearls is Badami, which BP brought online in 1998 and Savant Alaska is currently operating. The associated 35,000-bpd Badami Pipeline is the first string.
The Point Thomson field and its 22-mile pipeline are the second pearl and second string.
The other pearls on the string include the Red Dog, Telemark, Kuvlum-Lonestar, Stinson and Yukon Gold prospects. The final and most difficult pearl to string would be ANWR.
