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Federal Register / Vol. 86, No. 148 / Thursday, August 5, 2021 / Rules and Regulations
correspond with first oil and the rampup in drilling capacity.
Onsite facility installation would commence in August of Year 2 and be completed by the end of Year 4 May to accommodate the overall construction and production ramp-up schedule. Some facilities that are required early would be barged in the third quarter of Year 2 and would be installed and operational by the end of the fourth quarter of Year 2. Other modules would be delivered as soon as the ice road from SDI is in place. The drilling unit and associated equipment would be transferred by barge through Dutch Harbor or from West Dock to the LDPI during the open-water season in Year 2 using a seagoing barge and ocean class tug. The seagoing barge is 30.5 m 100 ft wide and 122 m 400 ft long, and the tug is 30.5 m 100 ft long.
Although the exact vessels to be used are unknown, Crowley lists Ocean class tugs at <1,600 gross registered tonnage.
The weight of the seagoing barge is not known at this time.
Hilcorp would install a pipe-in-pipe subsea pipeline consisting of a 30.5-cm 12-in-diameter inner pipe and a 40.6cm 16-in-diameter outer pipe to transport oil from the LDPI to the existing Badami pipeline. Pipeline construction is planned for the winter after the island is constructed. A
schematic of the pipeline can be found in Figure 23 of BOEMs Final EIS
available at https www.boem.gov/
Hilcorp-Liberty/. The pipeline would extend from the LDPI, across Foggy Island Bay, and terminate onshore at the existing Badami Pipeline tie-in location.
For the marine segment, construction would progress from shallower water to deeper water with multiple construction spreads.
To install the pipeline, a trench would be excavated using ice-roadbased long-reach excavators with pontoon tracks. The pipeline bundle would be lowered into the trench using side booms to control its vertical and horizontal position, and the trench would be backfilled by excavators using excavated trench spoils and select backfill. Hilcorp intends to place all material back in the trench slot. All work would be done from ice roads using conventional excavation and dirtmoving construction equipment. The target trench depth is 2.7 to 3.4 m 9 to 11 ft with a proposed maximum depth of cover of approximately 2.1 m 7 ft.
The pipeline would be approximately 9
km 5.6 mi long.
At the pipeline landfall where the pipeline transitions from onshore to offshore, Hilcorp would construct an approximately 0.6-ha 1.4-ac trench to
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protect against coastal erosion and ice ride-up associated with onshore sea ice movement and to accommodate the installation of thermosiphons heat pipes that circulate fluid based on natural convection to maintain or cool ambient ground temperature along the pipeline. The onshore pipeline would cross the tundra for almost 2.4 km 1.5
mi until it intersects the existing Badami pipeline system. The single wall 30.5-cm 12-in pipeline would rest on 150 to 170 VSMs, spaced approximately 15 m 50 ft apart to provide the pipeline a minimum 2.1-m 7-ft clearance above the tundra. Hydrotesting pressure testing using sea water of the entire pipeline would be required to complete pipeline commissioning.
The final drill rig has yet to be chosen but has been narrowed to 2 options and would accommodate drilling of 16
wells. The first option is the use of an existing platform-style drilling unit that Hilcorp owns and operates in the Cook Inlet. Designated as Rig 428, the rig has been used recently and is well suited in terms of depth and horsepower rating to drill the wells at Liberty. A second option that is being investigated is a new build drilling unit that would be built not only to drill Liberty development wells but would be more portable and more adaptable to other applications on the North Slope.
Regardless of drill rig type, the well row arrangement on the island is designed to accommodate up to 16 wells. While Hilcorp is proposing a 16-well design, only 10 wells would be drilled. The six additional well slots would be available as backups or for potential in-fill drilling if needed during the project life.
Drilling would be done using a conventional rotary drilling rig, initially powered by diesel, and eventually converted to fuel gas produced from the third well. Gas from the third well would also replace diesel fuel for the grind-and-inject facility and production facilities. A location on the LDPI is designated for drilling a relief well, if needed.
Process facilities on the island would separate crude oil from produced water and gas. Gas and water would be injected into the reservoir to provide pressure support and increase recovery from the field. A single-phase subsea pipe-in-pipe pipeline would transport sales-quality crude from the LDPI to shore, where an aboveground pipeline would transport crude to the existing Badami pipeline. From there, crude would be transported to the Endicott Sales Oil Pipeline, which ties into Pump Station 1 of the TAPS for eventual delivery to a refinery.

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North Slope Gas Development The AOGA Request discusses two projects currently submitted for approval and permitting that would transport natural gas from the North Slope via pipeline. Only a small fraction of this project would fall within the 40km 25-mi inland jurisdiction area of this ITR. The two projects are the Alaska Liquified Natural Gas Project Alaska LNG and the Alaska Stand Alone Pipeline ASAP. Both of these projects are discussed below and their effects analyzed in this ITR, but only one project could be constructed during the 20212026 period.
Alaska Liquefied Natural Gas Project Alaska LNG
The Alaska LNG project has been proposed by the Alaska Gasline Development Corporation AGDC to serve as a single integrated project with several facilities designed to liquefy natural gas. The fields of interest are the Point Thomson Unit PTU and PBU
production fields. The Alaska LNG
project would consist of a Gas Treatment Plant GTP; a Point Thomson Transmission Line PTTL to connect the GTP to the PTU gas production facility; a Prudhoe Bay Transmission Line PBTL to connect the GTP to the PBU gas production facility; a liquefaction facility in southcentral Alaska; and a 1,297-km 807-mi-long, 107-cm 42-in-diameter pipeline called the Mainline that would connect the GTP to the liquefaction facility. Only the GTP, PTTL, PBTL, a portion of the Mainline, and related ancillary facilities would be located within the geographic scope of AOGAs Request. Related components would require the construction of ice roads, ice pads, gravel roads, gravel pads, camps, laydown areas, and infrastructure to support barge and module offloading.
Barges would be used to transport GTP modules at West Dock at Prudhoe Bay several times annually, with GTP
modules being offloaded and transported by land to the proposed GTP facility in the PBU. However, deliveries would require deep draft tug and barges to a newly constructed berthing site at the northeast end of West Dock. Additionally, some barges would continue to deliver small modules and supplies to Point Thomson. Related activities include screeding, shallow draft tug use, sea ice cutting, gravel placement, sea ice road and sea ice pad development, vibratory and impact pile driving, and the use of an offshore barge staging area.

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