Project Overview of the 2023–2024 Production Test of Gas Hydrate on the Alaska North Slope

Abstract A 10-month gas production test from a gas hydrate-bearing sand reservoir was successfully conducted on the Alaska North Slope to better understand reservoir depressurization-based gas production. The JOGMEC-DOE-USGS Collaborative Gas Hydrate R&D Project in Alaska was implemented collaboratively by Japan Organization for Metals and Energy Security (JOGMEC) under the MH21-S R&D consortium, U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL), and U.S. Geological Survey (USGS), continuing over a quarter century of joint research. Using findings from the “Stratigraphic Test Well” drilled in 2018, a testing program was designed with two production wells and a geoscience data acquisition well supported by “built-for-purpose” surface production test facilities. During the operations, testing was conducted in only one of the dedicated production test wells, with production monitoring being conducted in the other three test site wells. Lessons from past field tests in Japan, the U.S., and Canada informed key system designs such as sand control, artificial lift, and sensor installations (temperature, pressure, strain, and acoustic). Production testing began on September 19, 2023. Despite periodic disruptions due to artificial lift system problems, the tested gas hydrate-bearing reservoir was subjected to depressurization for a total of 216 days, which included a period of stable borehole pressure drawdown of ∼400 psi (from an initial in situ pressure of 1250 psi) that was maintained for over two months, allowing continuous data collection. In the test’s final phase, an alternative artificial lift system was installed to achieve lower bottom-hole pressures. Key findings from the 2-month continuous production period at constant bottom-hole pressure include (1) stable production, showing no indication of either increases or declines in production rates; (2) pressure and temperature impacts were observed in all monitoring wells, indicating the rate and nature of hydrate dissociation; and (3) gas–water ratio (GWR) averaging around 600 m3/m3─far exceeding values from previous short duration tests or from numerical simulations.