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.

1. Introduction

Gas hydrates have been confirmed to exist on the Alaska North Slope since the initial testing conducted at the Eileen State #2 well within the western Prudhoe Bay Unit in the 1970s. Following the initiation of the gas hydrate R&D program by the U.S. Department of Energy (DOE) in 2001, Alaska has hosted a series of gas hydrate research projects (Figure ) all focused on the goal of leveraging the high-quality sandstone reservoirs, established infrastructure, and onshore setting to enable efficient evaluation of the potential of producing gas from gas hydrates. In parallel, research efforts within the Research Consortium for Methane Hydrate Resources in Japan (MH21) program discovered high-saturation and sand-hosted gas hydrate reservoirs at large scale in the deepwater offshore Japan, and led an international collaboration that demonstrated the technically viability of gas production from gas hydrates by reservoir depressurization at the Mallik site in Canada. A series of gas hydrate exploration programs were conducted in subsequent years by various parties, confirming the existence of marine gas hydrate reservoirs in the Gulf of America, the Bay of Bengal, and the South China Sea Field tests of marine gas hydrate production potential have included two tests conducted in the South China Sea which assessed silt- and clay-rich reservoirs, , and two conducted offshore Japan that tested sand-rich reservoirs. − These tests have further documented the gas hydrate response to reservoir depressurization, enabled refinements of various production approaches, and revealed new information on gas hydrate reservoir responses. However, the short duration of these tests has not provided sufficient data to assess either existing numerical simulation capabilities or long-term production behavior.

1.

Gas hydrate research locations on the Alaska North Slope. The location of the test site for this study, the Kuparuk St. 7-11-12 pad, is shown in detail on the upper right. This figure was modified with permission from ref . Copyright 2022 American Chemical Society.

In Alaska, initial scientific drilling focused on reservoir characterization and short-duration pressure testing conducted at the Mount Elbert location within the Milne Point Unit. Focus then shifted to the Prudhoe Bay Unit (PBU) and ultimately led to a test sponsored by the DOE, ConocoPhillips, and JOGMEC to assess the feasibility of CO₂–CH₄ exchange and associated CH₄ gas production. In November 2014, the DOE’s NETL and JOGMEC formalized an international research and development (R&D) collaboration through the signing of a Memorandum of Understanding. Since then, the two organizations have jointly undertaken a range of R&D activities focused on gas hydrates, with the shared objectives of enabling an extended-duration gas production test in the Alaska North Slope (ANS). This collaborative framework was further strengthened by the conclusion of a Cooperative Research and Development Agreement (CRADA) between JOGMEC and NETL. The international R&D collaboration among DOE/NETL, USGS, and JOGMEC aimed to advance the scientific and technical understanding of gas hydrate production and its commercial potential. Initially, this effort, driven by a decline in industry interest in collaborative gas hydrate R&D on the ANS, focused on geophysical review of potential sites for field testing outside the existing leased and operating areas. However, it was determined that effective testing could only be conducted where infrastructure could be leveraged, and, with assistance from the Alaska Department of Natural Resources, industry was again engaged to enable research. As part of the preparatory efforts for an extended-duration gas production test, potential test sites were evaluated through a comprehensive review of available seismic data sets and feasibility studies addressing both technical and economic considerations. By 2016, a gravel pad, located in the western portion of the PBU and no longer in routine use by industry but with full road access, was identified as a potential testing location.

This site, known as the Kuparuk State 7-11-12 site for an industry exploration well that had been drilled in the 1970s, became the focus of the JOGMEC-DOE-USGS Collaborative Gas Hydrate R&D Project in Alaska. The objectives of this project include (1) to understand long-term gas hydrate production behavior through the integrated evaluation of extended duration (multiple months to a year) test results, system performance, monitoring data, and geologic data acquired from cores and well logs, (2) to verify mitigation plans against production interruptions, (3) to identify the most effective production systems to achieve stable long-term gas hydrate production, and (4) to obtain data to enable the calibration and validation of numerical codes. A better understanding of the long-term production of gas from a well-characterized gas hydrate accumulation would be indispensable for the commercialization of gas hydrate development. Thus, this production test in Alaska aimed to acquire extended-duration production test data and information to help document the production response of gas hydrate to depressurization and to aid in the development of simulation capabilities required to better constrain the potential for future production.

The HYDRATE 01 Stratigraphic Test Well (STW) was drilled in December 2018 to verify the occurrence and characteristics of gas hydrate-bearing reservoirs at the selected location and to determine its suitability for an extended-duration gas production test. The data and information acquired through drilling, logging, pressurized side-wall core sampling, and associated analyses facilitated extensive evaluations of reservoir conditions. These evaluations confirmed that the selected site possessed the necessary geological and operational attributes to support the proposed gas production test.

Based on the data acquired through STW drilling, a decision was made to proceed with an extended-duration gas production test. The primary target of the testing operation was selected as the B1 sand, located at a depth of approximately 3,000 ft at the top of the informal unit B interval within the Tertiary Sagavanirktok Formation. The B1 sand was assessed as an outstanding reservoir for scientific testing given its relatively high reservoir quality and high temperature, proximity to the base of gas hydrate stability, lack of any known connection to zones of mobile water, and occurrence of an overlying fine-grained “seal” layer. A secondary target was identified as the shallower D1 sand; however, that unit was at a lower temperature and would require greater pressure drawdowns to enable gas hydrate dissociation. In addition, in the STW, the D1 sand contained a zone of high-water content at its base.

In order to implement the extended-duration gas production test, a Third-Party Operator (TPO) who assumed the role of the project operator was engaged by the project partners. The TPO’s roles include implementation of the production test, and all preparatory work (detailed design, arrangement and procurement of equipment and materials, obtaining all permits, and engaging subcontractors, drilling contractors, and service providers). In January 2021, ASRC Energy Services Alaska, Inc. (AES) was selected as the TPO through JOGMEC’s public offering, and project planning was initiated after the award. JOGMEC, DOE/NETL, and USGS worked closely with AES to finalize the project implementation plan.

The primary objective of the extended-duration gas production test was to acquire a broad spectrum of data to enhance understanding of gas hydrate production behavior and to evaluate well designs, production approaches, and technologies to support future commercialization of gas hydrate development. In particular, the test aimed to evaluate trends in gas production rates over timewhether production would increase, stabilize at a plateau, or declineunder constant long-term pressure conditions. To increase the likelihood that this reservoir response would be clearly observed, it was proposed that the well be depressurized to a significant level, and that level held continuously (constant bottom-hole pressure) for extended time periods with minimal operational upsets. Another major objective was to assess the operational performance of the well design and the planned production test facilities under field conditions.

Drawing from experience gained in previous onshore and offshore production tests, specific focus was placed on critical elements required for sustained gas production. These included challenges such as accurate measurement of solids, water, and gas production, water production, effective artificial lift to enable effective depressurization, management of solids production, as well as the potential for hydrate formation within production facilities (both subsurface and surface). Consequently, key elements of the test design included selection and placement of monitoring and measurement devices, sand control, artificial lift, and downhole heating equipment, as well as selection and optimal deployment of downhole sensors. Addressing these issues was deemed essential for enabling continuous operations with data acquisition over a duration previously unattainable in hydrate production field trials.

To conform with agreements between the project operator and the leaseholders, the production test system was designed as a stand-alone facility. Therefore, produced gas was used to the extent feasible as a fuel source to operate essential equipment such as power generators. Produced water was planned to be primarily disposed of on-site through gas-fired evaporation. To ensure uninterrupted operations even in cases where the produced gas was insufficient to power the production testing operations, a supplemental fuel gas supply was secured from the Oliktok pipeline, operated by ConocoPhillips Alaska, Inc., which was located adjacent to the test site.

The test site included four wells. The STW drilled in 2018 (and was instrumented as a monitoring well) and three wells drilled in 2022 and 2023. All wells were drilled directionally from the gravel pad to bottom hole locations to the east. The first of the three new test site wells to be drilled was the HYDRATE 02 Geo Data well (GDW) that was designed to provide comprehensive reservoir characterization data, including a full logging-while-drilling (LWD) program and collection of whole-round pressure cores. Subsequently, the HYDRATE P1 Production Test well-1 (PTW-1) was drilled, logged, and completed for production. The HYDRATE P2 Production Test Well-2 (PTW-2) was similarly drilled and logged but left uncompleted. All three of the new wells were instrumented to serve as monitoring wells.

The acquired log data at GDW, PTW-2, and PTW-1 enabled the extended evaluation of the physical properties of the B1 sand and surrounding formations throughout the test site, both in real time, and through subsequent analysis. , These data were integrated with data obtained from the evaluation of pressured and conventional core samples − to enable refined estimation of the porosity, gas hydrate saturation, and intrinsic and effective permeability throughout the test site. , Given the volume of data acquired and the complexity of evaluating pressured core samples, further refinements to the full-site geologic model are ongoing.

Geophysical survey data were also acquired by a three-dimensional Vertical Seismic Profile (3D VSP) conducted in March 2019 and again in March 2025, and by Cross Well Seismic (CWS) conducted in June 2023 and in August 2024.

Subsurface monitoring data were acquired in the STW before, during, and after the production test, covering a span of 66 months (May 2019 to October 2024). Data were acquired in the GDW, PTW-2, and PTW-1 from just after drilling was completed at each well (GDW from November 2022, PTW-2 from December 2022, PTW-1 from March 2023). The Production Test was conducted between September 19, 2023 and July 30, 2024, and included multiple phases of pressure drawdown and intervening shut-ins using a downhole ESP and a Jet Pump (JP). , This report provides an overview of the production testing project conducted in the ANS, including preparatory efforts and the methods employed during execution of the test. For detailed review of operations, readers are directed to the primary operational review papers. − For a detailed review of scientific analyses and findings derived from data collected before, during, and after the production phase, readers are directed to other published studies as summarized in the Introduction.

2. Selection of Geologic Targets

To support a detailed determination of well paths, a 3D VSP survey was conducted in March 2019. This survey confirmed the orientation of a small fault observed in log data at the B1 sand level in the STW and revealed the presence of additional minor faults within the area designated for potential well trajectories. As with the STW-fault, these small-offset faults were not identifiable through conventional surface seismic data. Consequently, the borehole locations for GDW, PTW-2, and PTW-1 were carefully selected to ensure maximum distance from the newly identified fault structures.

In support of the well placement and drilling strategy, the acoustic impedance map generated from surface seismic and focused on the reflector associated with the top of the hydrate-bearing B1 sand served as a critical input for both structure and predicted gas hydrate occurrence. The penetration point of the B1 sand in the PTW-1 was accordingly placed in an area of high structural elevation and strong seismic impedance. The PTW-2 was placed in a similarly favorable location along with the other test site wells to optimize the well positions to monitor the progression of a test conducted in the B1 sand in the PTW-1. The trajectory of PTW-2 was planned so that (1) the well was a close offset of the PTW-1 to enable monitoring and to ensure it was in a good position to serve as a test of the B1 should that necessity arise; and (2) the penetration point of D1 sand in the PTW-2 was located in an area of high structural elevation and strong seismic impedance should the option of testing in the D1 sand be exercised. Also, the distance between faults and PTW-2 and GDW was key to planning the bottomhole locations of these wells, as was the consideration to avoid interference between all the boreholes.

3. Test Design

The implementation plan called for drilling a primary test well (PTW-1); a contingent test well (PTW-2) that could be converted into a production well should PTW-1 be unable to proceed with production testing due to unforeseen circumstances; and a Geo Data well (GDW) for collecting sediment specimens and detailed logging data in support of reservoir modeling and the interpretations of in situ monitoring data. Both the GDW and PTW-2 wells were fully instrumented for monitoring purposes.

As illustrated in Figure , the PTW-1 featured a design optimized for operations in the B1 sand, while the PTW-2 well was designed to enable gas production from either the B1 or D1 sand. The locations of the target reservoir sand penetrations in each well were determined through a comprehensive evaluation of available geologic and geophysical data, including assessments of the structural position, approximate degree of inferred hydrate saturation, potential lateral continuity of the B1 and D1 sands (including potential fault locations), production forecasts based on a 2D geological model, and sensitivity analyses regarding production performance (e.g., the potential impact of free gas and/or free water in the lower hydrate zone). These considerations informed the finalization of the well trajectory plan.

2.

Test site well configurations for the extended-duration gas production test. Gas hydrate-bearing sands (B1 and D1 sands) are shown in green. Shown in blue is a water-bearing sand in contact with the D1 gas hydrate occurrence. Optical fiber monitoring systems are also indicated in each well: DTS/DAS (Temperature/acoustic data) in yellow; DSS (strain) in purple. Pressure and temperature gauges are shown as circles on the red monitoring lines, and the Resistance Temperature Detector (RTD), which concentrated nearly 60 sensors around the B1 and D1 sands with a 2-m vertical spacing, is shown in green. GDW pressure coring intervals around the B1 and D1 sands are shown in brown. STW sidewall core intervals are shown in blue arrows , Zones where the PTW-1 and PTW-2 could be perforated to run production test activities are shown as red-spiked regions.

4. Drilling of Monitoring Wells and Production Test Wells

The targeted locations of the B1 sand and D1 sand penetrations are northeast of the Kuparuk State 7-11-12 well pad. The well trajectories were designed as directional deviated wells to reach the target reservoir intervals.

Drilling and well planning for gas hydrate development differ significantly from those applied to conventional oil and gas fields. Given that this program is an R&D initiative aimed at acquiring data to better understand gas hydrate production behavior, particular care was taken to minimize thermal disturbance of the B1 and D1 sands by employing a mud chilling system during drilling of all wells. This system maintained drilling fluid temperatures as close as possible to in situ conditions, thereby preserving the natural state of the hydrate-bearing formations in the vicinity of the boreholes.

The targeted well penetrations are in the shallow subsurface just below the base of permafrost and are embedded within unconsolidated geological formations, which presents specific operational challenges. Consequently, the well deviation “kick-off” operations for the GDW and PTW-2 wells took longer than originally anticipated. To enhance the efficiency of drilling activities for PTW-1, a 12-1/4-in. pilot hole was initially drilled and subsequently enlarged to the planned diameter of 20 inches. This approach resulted in the successful and efficient completion of the drilling phase of the project.

The STW (Figure ) was drilled in December 2018 to confirm the occurrence of gas hydrate, and distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) cables were deployed for data acquisition (3D vertical seismic profile (VSP) data acquisition was conducted in March 2019 using DAS cable as a receiver), and so STW could serve as a monitoring well.

The GDW (Figure ) was drilled in October to November 2022, where full-round pressure core samples were collected to obtain core analysis data to help with the development of the geological model for better simulation of production behavior. In addition to the DTS/DAS cables, resistance temperature detectors (RTD), Pressure/Temperature (PT) gauges, and an optical fiber-based strain sensor were deployed to enable GDW as a monitoring well.

The PTW-2 (Figure ) was drilled from November to December 2022, where DTS/DAS cables, Pressure/Temperature (PT) gauges, and optical fiber-based strain sensor were deployed so PTW-2 could serve as monitoring well during production test in the PTW-1. PTW-2 was designed to be able to be converted to a production well when needed and could produce from either B1 sand or D1 sand as a contingent production test well.

PTW-1 (Figure ) was drilled from December 2022 to February 2023, where DTS/DAS cables, PT gauges, optical fiber-based strain sensor were deployed. PTW-1 was designed to produce gas from only the B1 sand (Figures and ).

3.

Overview of the test site (Late October 2022 during GDW drilling) Ⓐ Drilling rig; Ⓑ mud chiller unit; Ⓒ housing for the pressure core processing during the GDW drilling. During subsequent production activities, this facility was used to protect on-site water evaporators (Photo courtesy: ASRC Energy Services, Alaska, Inc. This photo was permitted for this paper by ASRC Energy Services, Alaska, Inc..).

4.

Wellhouses (dark green units) on the test site as of June 2023: Ⓐ: HYDRATE 01 (Stratigraphic Test Well (STW)), Ⓑ: HYDRATE P1 (Production Test Well-1 (PTW-1)), Ⓒ: HYDRATE P2 (Production Test Well-2 (PTW-2)), Ⓓ: HYDRATE 02 (Geo Data Well (GDW)).

The drilling campaign was conducted from October 2022 to February 2023, and involved the completion of three wells: GDW, PTW-2, and PTW-1. During GDW drilling operations, from October 9 to November 20, 2022, whole-round pressure core sampling was conducted using the High Pressure–Temperature Corer IV (HPTC IV), a pressure core sampling tool developed by JOGMEC. This effort resulted in the successful recovery of 11 core samples from the D1 sand and 13 from the B1 sand, including bounding sediments from both the D1 and B1 sands. The total core recovery rate reached 90%, with individual recovery efficiencies of 77.5 and 98.2% for the D1 and B1 sands, respectively. Following the GDW, the PTW-2 and PTW-1 wells were drilled. Both production wells were completed using a vacuum-insulated casing (VIC) to protect permafrost from melting during the production of warm fluids.

5. Installation of Monitoring Devices (All Wells)

A key component of the project was the installation of downhole sensors and gauges, to provide continuous and reliable data acquisition. An array of sensors and gauges were deployed in all three wells (GDW, PTW-1, PTW-2). The instrumentation included distributed temperature sensing (DTS), distributed acoustic sensing (DAS), distributed strain sensing (DSS) cables, and pressure/temperature gauges, all of which were successfully deployed without loss of functionality. PTW-1 was equipped not only with sensor cables and gauges but also with power and control cables for a downhole heater and an electrical submersible pump (ESP), along with a wellbore heat trace systemall of which were also successfully installed.

6. PTW-1 Well Completion

The completion of the PTW-1 included the installation of an ESP, a downhole electrical heater (DHEH), a downhole heat trace (DHHT), and sand control equipment to ensure operational stability during the production phase. As previously noted, PTW-2 was ultimately used only as a monitoring well, and therefore, well completion as a production test well was not performed.

To mitigate the risk of operational interruption caused by blockages in the PTW-1 tubulars due to gas hydrate reformation, the subsurface production system incorporated a DHHT and a DHEH to maintain thermal stability and prevent hydrate formation in the well. A comprehensive flow assurance study was conducted for the PTW-1, through which potential locations for hydrate formation were identified under several expected operational scenarios. The findings from this study were incorporated into the well design to enhance reliability and safety. To address the potential reformation of hydrate, the facilities plan incorporated chemical injection systems consisting of injection lines and a chemical pump. One injection tubing of 3/8 in. diameter (with an injection port located at 833 m measured depth (MD), equivalent to 2,733 feet) and one 5/8 in. diameter (with an injection port at 917 m MD, equivalent to 3,009 feet) were installed. These tubings were originally designed to enable chemical injection (such as methanol) to address flow assurance in the event of hydrate reformation or other wellbore issue. Subsequently, the same injection lines were repurposed to introduce water into the wellbore during depressurization operations, which became necessary due to an unexpectedly low rate of produced water.

Given the uncertainty and high expected variability in produced water rates, an ESP was selected as the primary artificial lift method as ESPs can cover a wide range of water production rates compared to other artificial lift methods. Produced water rates were expected to vary significantly during the test, beginning as a low rate during the initial phase of production, then potentially increasing to much higher rates as production continued. Accordingly, the production facilities were designed to cover a wide range of potential produced water rates. Four ESP strings were prepared to accommodate the range of water production scenarios. These replacement ESP strings were designed to allow for rigless (i.e., no drilling rig required) pump replacements, thereby reducing downtime associated with maintenance and intervention operations. A water injection pump was incorporated into the initial operational plan due to pretest predictions indicating that the produced water rate might periodically be insufficient to sustain normal pump operation, potentially resulting in cavitation-induced interruptions.

Produced sand management was implemented through an integrated strategy combining subsurface and surface measures. For the subsurface, a system including a polymer filter intended to stop sand particles larger than 44 μm, wrapped around a steel screen, in turn wrapped around an inner pipe with bead-filled ports, was deployed at the lower completion. This system (known as GeoFORM) was selected to maximize exclusion of sand and coarse-silt from the wellbore. Surface solids management was achieved via a suite of equipment, including a wellhead desander positioned downstream of the wellhead choke, an inlet separator to gravitationally separate not only gas and fluid but also solids, a desander located downstream of the inlet separator employing centrifugal separation, and a settling tank designed to capture solids within the water handling stream for manual disposal. The selection of sand control equipment for the Alaska program was based on its demonstrated efficacy during Japan’s second offshore field test. That test involved two production test wells. The AT1-P3 well was tested for 12 days with intermittent sand production events, and the AT1-P2 continued for 24 days without sand production problems. − Considering the results of the second offshore Japan field test and the Alaska project decision to exclude sand to the greatest extent possible, the sand control equipment was selected. The maximum sand production rate that could be managed by the surface facilities was estimated at 6.2 cubic yards per day, corresponding to a water production rate of 4,500 barrels of water per day (bwpd), based on benchmark data from the Iġnik Sikumi Field Experiment conducted in 2012.

PTW-1 was equipped with a barrier valve (BV) designed to hydraulically isolate the artificial lift system in the upper completion from the perforated interval below. The artificial lift system initially deployed in the PTW-1 included an ESP, which was subsequently replaced with a JP. The ESP was installed at a position 300 feet above the perforation and the sand production control system. This configuration was designed to facilitate maintenance and intervention activities during the production test, including the replacement of the artificial lift pump, without disturbing the integrity of the lower completion.

To preserve the functionality of the measurement systems, including optic fiber sensor cables (temperature/acoustic/strain) and pressure/temperature gauges, planning was undertaken to prevent mechanical damage to the gauges and cable systems during casing perforation. For PTW-1, oriented perforation technology ensured that the perforation charges did not compromise the integrity of the installed sensors and cables. This approach was successfully implemented, thereby safeguarding the data acquisition infrastructure essential to the production test’s objectives (Figures and ).

5.

PTW-1 Well Schematic – Electrical Submersible Pump (ESP) installation. ESP operation continued from September 2023 to April 2024. Depth indications for the sensors (Pressure/Temperature gauges, DTS/DAS cables, DSS cable), downhole heat trace, downhole heater, ESP, and sand control equipment are shown. The completion design was chosen to minimize both the sand production and the intervention time required to perform a rigless ESP replacement if needed. MD: Measured Depth, TVD: True Vertical Depth.

6.

PTW-1 Well Schematic – Jet Pump (JP) installation. JP operation continued from May 2024 to July 2024. Sensors (Pressure/Temperature gauges, DTS/DAS cables, DSS cable), downhole heat trace, downhole heater, and sand control equipment depth are unchanged from the ESP installation (Figure ). Taking the operation data into consideration, a JP nozzle diameter was selected. This nozzle continued operation until end of gas production test and with it, the JP could reduce pressure inside tubing to 250 psi, more than 1000 psi below the initial pressure of 1,290 psi.

7. Production Test Facilities

The production test facilities were designed to accommodate gas production rates ranging from 0 to 1.7 million standard cubic feet per day (MMscfd) and water production rates up to 4,500 bwpd. These specifications were informed by pretest numerical simulations , and considerations of water handling and disposal capabilities, which included up to 2,700 bwpd through operation of three onsite gas powered evaporators as well as onsite storage and potential intermittent trucking for disposal offsite as needed. Produced gas was designed to be utilized as fuel for key components, including microturbine generators and water evaporators. Flaring was to only be used when needed to ensure safe operations.

Produced solids were to be trucked from the test site and disposed by subsurface injection at the PBU grinding and injection well facility. To ensure operational continuity under potential fluctuations in production, a backup fuel gas supply system was integrated into the facility design, enabling supplemental gas to be sourced from the nearby Oliktok pipeline.

The actual produced water rate from the test of the PTW-1 remained below the anticipated threshold. Consequently, the water injection pumporiginally intended for provisional usewas required to operate continuously throughout the entire duration of the ESP-supported operations.

For gas flow measurements, the surface test facilities employed a dual-train configuration comprising a low-flow and a high-flow gas train. This configuration was adopted due to the limited turndown ratio of individual gas meters, which made it impractical to rely on a single meter to span the entire expected flow range. ,

8. Data Monitoring and Acquisition

To achieve the objectives outlined for the extended-duration gas production test, a comprehensive, phased approach to data acquisition was implemented. Data monitoring was structured into three distinct phases: pretest, during-test, and post-test. The pretest phase was subdivided into two intervals: one immediately after drilling the STW and another after drilling the GDW, PTW-2, and PTW-1. During the production test, production data were also acquired from both the surface and subsurface facilities. A three-month post-test monitoring period followed the completion of the production test.

8.1. Downhole Data Monitoring

Downhole data were obtained by deploying sensors in all four wells, as summarized in Table . In addition to temperature and pressure sensors installed behind the casing, strain sensors were positioned in GDW, PTW-2, and PTW-1, also on the casing’s outer surface. Furthermore, temperature and pressure sensors associated with the downhole equipment deployed at PTW-1, as well as acoustic sensors deployed across all wells, were utilized. High accuracy resistance temperature detector (RTD) was deployed at GDW as a reference to other temperature measurements. Data relevant to ESP operation, including inlet and discharge pressures, downhole heater temperature, and heat trace temperature, were also collected to facilitate a comprehensive understanding of methane hydrate production behavior. DSS data were acquired for the first time at field scale for gas hydrate development.

1. Overview of Downhole Sensors Deployment, This Table Shows Which Sensors Were Deployed in Each Well.

	GDW	PTW-1	PTW-2	STW
DTS	√	√	√	√
DAS	√	√	√	√
Resistance Temperature Detector (RTD)	√
BPT (Behind Casing P/T)	√	√	√
DSS (Strain sensor array)	√	√	√
UPT (Upper Completion P/T)		√
Start of data acquisition	Nov. 2022	Feb. 2023	Dec. 2023	May 2019

In order to obtain early indications of sand production, the downhole monitoring systems of the production wells were configured to measure pressure at multiple locations: within the production tubing, in the annulus between the production tubing and casing, and behind (outside) the casing (i.e., approximate formation pressure). These measurements enabled the evaluation of pressure differentials (ΔP) around the sand control equipment. An increasing ΔP in these regions was considered indicative of the development of “skin” near the perforated intervals. This skin could be related to various factors, including plugging of perforations or sand control equipment by sediment, and/or plugging between the casing and tubing. In such cases, appropriate countermeasuressuch as reducing the water-pumping rate of the ESP or JPcould be implemented to avoid formation damage or operational interruption due to significant sand production, as experienced in the first offshore production field test in Japan.

8.2. Surface Testing Facilities Data Monitoring

Production data obtained from surface testing facilities were systematically monitored to optimize operational control and characterize gas and water production behavior. Key parameters acquired during monitoring included the gas and water production rates, sand sampling at the wellhead choke skid, the water injection rate used to support the ESP operation, and the power fluid rate when the JP was operated. Additional measurements included the volumes of chemical injectionsmost notably methanolas well as pressure and temperature data recorded for each piece of equipment. A Distributed Control System (DCS) was employed to control the surface testing facilities and record key data on the flow rates of water and gas, temperature, and pressure at designated equipment.

8.3. Elevation Survey and Geophysical Surveys

8.3.1. 3D VSP, March 2019 and March 2025

Following the deployment of DTS and DAS cables at STW in December 2018, a 3D VSP survey was conducted in March 2019 to evaluate subsurface conditions. This survey utilized the DAS cable installed at STW and vibroseis equipment, which were operated only during the winter season due to the necessity of adequate ice cover on the Alaska North Slope.

Following completion of the production test, an additional 3D VSP survey was conducted in March 2025. The objective of this follow-up survey was to detect variations in subsurface properties and to assess the extent of dissociation progression by comparing pre- and postproduction test 3D VSP data sets. The data acquired in March 2025 are currently undergoing processing and analysis.

8.3.2. Cross Well Seismic, June 2023/August 2024

CWS operations were conducted both before (June 2023) and after (August 2024) production testing. An acoustic source was deployed in the GDW well, while DAS cables installed at all four wells functioned as receivers to capture the CWS signals. These data sets were collected to assess changes in subsurface reservoir properties (most significantly, gas hydrate and free gas saturations) associated with production-induced changes. Analysis of these CWS data is being conducted.

8.3.3. Elevation Survey

There was no baseline elevation data for the test site had been collected prior to start of this testing program. Therefore, an elevation survey was initiated in October 2018 to establish baseline measurements and assess any changes in pre- and postproduction testing. Elevation data collection was successfully conducted throughout all seasons from October 2018 to April 2021. Subsequently, elevation surveys were performed in August 2023, July 2024, and October 2024, corresponding to the before, during, and after phases of the gas production test. Comparative analysis revealed negligible variation between the initial measurements in October 2018 and those acquired in October 2024. These data were collected to assess potential changes in surface elevation associated with production testing activities. Due to the absence of baseline data from before this Alaska program within the test site and its surrounding area, the survey was designed to infer any changes by comparing available post-test measurements to pretest conditions reconstructed through indirect methods and observations. Data were acquired via GPS-based geolocation and elevation mapping and then evaluated against the inferred pretest conditions to identify significant variations.

9. Gas Production Test

The following is a high-level summary of the testing operations. For a complete description, please see the companion paper in this VSI by Nakatsuka et al. For a discussion of technical findings, please see the report by Ohtsuki et al.

9.1. Overview

The gas production test commenced with the startup of the ESP on September 19, 2023, and concluded with the shutdown of the JP on July 30, 2024. The effective gas production period was recorded as 280 days, from October 24, 2023, when the borehole pressure was first reduced to the threshold for hydrate dissociation and gas release, to July 30, 2024, upon termination of JP operations.

During the gas production period, 64 days of nonproductive time occurred, and there were 216 total gas production days. Key information for the JOGMEC-DOE-USGS Collaborative Gas Hydrate R&D Project in Alaska is summarized in Table . Table compares key information of the past field tests in which the US and Japan were involved, including gas production duration, and cumulative volume of produced gas.

2. Summary of Gas Production Test for Alaska Program.

Duration of Gas Produdtion Test	Over 10 months (315 days) September 19, 2023 - July 30, 2024
Duration of Gas Production	280 days (October 24, 2023 - July 30, 2024)
Gas Production Days (Duration of gas production - NPT)	216 days
Non Productive Time (NPT)	64 days

3. Comparison with the Past Production Tests in Which US and Japan Were Involved^a .

Production Tests	Locations	Duration of Production	Production Interval (meters)	Volume of Produced Gas (cubic meters)
Mallik 2002	McKenzie Delta, Canada	5 days	N.A.	470
Mallik 2007	McKenzie Delta, Canada	12.5 h	12	830
Mallik 2008	McKenzie Delta, Canada	6 days	12	13,000
Ignik Sikumi 2012	North Slope, Alaska, USA	30 days	9.1	24,000
Nankai 2013	Nankai Trough, Japan	6 days	39	119,000
Nankai 2017	Nankai Trough, Japan	P2 well: 24 days; P3 well: 12 days	P2 well: 45.4; P3 well: 41	P2:222,600; P3:40,850
Alaska extended-duration gas production test 2023–24	North Slope, Alaska, USA	216 days	7.8	319,800

^aData from reference .

During the gas production test, a wide range of data and information were acquired. These include gas and water production rates, as well as pressure and temperature measurements at various borehole locations across all project wells. Strain measurements were obtained at PTW-1, PTW-2, and GDW. Data were also collected from surface production test facilities. Furthermore, acoustic sensors (DAS cables) deployed at all four wells were used to detect early indications of sand production ,,

The initial reservoir conditions in the B1 sand were characterized by a pressure of 8.89 MPa (1,290 psi) and a temperature of 11.2 °C (52.2 °F). The anticipated pressure at which gas hydrate in the B1 sand would begin dissociation is therefore estimated at 8.62 MPa (1,250 psi)

The depressurization strategy for the B1 sand was to reduce the formation pressure gradually in a stepwise manner (see Figure ). This methodology was adopted to enable initial monitoring of surface systems function and to mitigate the risk of excessive sand production, which could potentially disrupt gas production operations. The strategy was informed by operational insights gained from Japan’s first offshore field test conducted in 2013, during which substantial sand production was encountered, ultimately leading to the premature termination of the production test. ,,

8.

Nominal Depressurization Plan, illustrating the pretest depressurization plan. (A) Slight drawdown to 1,250 psi from initial bottom hole pressure of 1,290 psi, to check performance and safety of the production test facilities, before further drawdown to produce gas from gas hydrate. Estimation of initial effective water permeability was one of objectives of this initial drawdown (B) After initial drawdown, 1st target of drawdown level was 900 psi. This stage is preparatory stage for further drawdown. Drawdown was slowly conducted to avoid massive sand production and skin development to interrupt the operation. (C) 2nd target of drawdown level was ∼700 psi, to assess reservoir response. (D) 3rd target of drawdown level was ∼435 psi. Plan was to hold each pressure level as long as feasible and to observe reservoir response, including the rate of gas and water production, and whether those rates would tend to increase, plateau, or decrease with time under constant pressure conditions. This reflects the project’s goal of maximizing the scientific understanding of gas hydrate production behavior to help future development, as opposed to simply seeking to maximize gas rate.

In accordance with this strategy, the depressurization process entailed lowering the reservoir pressure at a rate of 5 psi/hour and maintaining that pressure for a sufficient duration to ensure operational stability. A secondary objective was to gather data on the reservoir properties (primarily effective permeability) prior to the disturbance of the gas hydrate. Upon confirmation of stable conditions, the drawdown was continued. This process was repeated until a preselected pressure-hold level was met, at which time the goal was to hold pressure constant as long as feasible with the intent of observing whether production rate would stabilize, steadily increase, or steadily decline. The nominal plan was to conduct testing at two bottom-hole pressure levels: one reflecting moderate drawdown (to a BHP of ∼700 psi), and a second at significant drawdown (to BHP of ∼435 psi).

As shown in Figure , constant bottom-hole pressure conditions were successfully maintained during two distinct periods for the ESP operations: from November 7 to November 21, 2023, at a pressure level of 900 psi (approximately 2 weeks), and from January 18 to March 21, 2024, (more than two months) at 850 psi recorded at the BPT_PTW1_P03 gauge located at inside of casing above the sand control equipment.

7.

PTW-1 production chart, showing overall production history for the entire duration of the extended-duration gas production test, including (a) borehole pressure and (b) borehole temperature at the B1 sand, (c) produced gas rate, and (d) produced water rate. Gray periods indicate nonproductive intervals spent mitigating mechanical failures in the ESP or JP pump or managing sand control issues. For full discussion, see ref .

The gas and water production rates during stable operation at 850 psi demonstrated a plateauing behavior, indicating sustained productivity over the course of approximately two months with no evidence of increase or decrease in production rates. These rates are approximately 60–70 mscf/d for gas and approximately 15–20 bwpd for water.

The gas production test can be characterized as follows:

• 1.Depressurization by ESP (October 24, 2023 – April 15, 2024)

  Duration of normal depressurization by ESP includes stable operation period at 900 psi (November 7 – November 21, 2023) and stable operation period at 850 psi (January 18, 2024 – March 21, 2024)

• 2.ESP intermittent depressurization operation (April 16, 2024 – April 19, 2024)
• 3.Depressurization by JP (May 23, 2024 – July 30, 2024)

There were three primary intervals of nonproductive time (shown as shaded regions in Figure ): (1) gas lock event (November 27, 2023 – December 5, 2023), (2) maintenance of gas line (April 3, 2024 – April 11, 2024), (3) ESP maintenance and BV trouble (April 19, 2024 – May 22, 2024) (Table ).

4. Overview of Extended-Duration Gas Production Test, Showing Operational Modes with Artificial Lift Methods.

Artificial Lift Method	Operation Mode	Term
ESP	Overall	September 19, 2023 - April 19, 2024
	Start-up operation	September 19, 2023 - October 23, 2023
	Normal Depressurization	October 24, 2023 - April 15, 2024
	Bottomhole pressure of 900 psi	November 7, 2023 - November 21, 2023
	Bottomhole pressure of 850 psi	January 18, 2024 - March 21, 2024
	Intermittent Depressurization	April 16, 2024 - April 19, 2024
JP	Overall	May 23, 2024 - July 30, 2024
	Depressurization	May 23, 2024 - July 14, 2024

9.2. Depressurization by ESP

9.2.1. Depressurization by ESP

Operations were controlled and drawdown targets were set, based on pressure readings from the BPT_PTW1_P03 gauge located inside the casing and above the sand control system. This pressure was not equated with the drawdown imposed on the formation, as best represented by the readings taken at BPT_PTW-1_P02, located outside the casing above the sand control equipment. For operational control purposes, the project operator determined that the BPT_PTW1_P03 gauge better monitored the performance of the well, rather than the sensor outside the casing (BPT_PTW1_P02), since it was considered that the gauge inside the casing would give more direct information on how to control the well and surface testing facilities (Figure ).

9.2.1.1. Start-Up Operation (September 19 – October 23, 2023)

To suppress convective disturbances that could compromise the accuracy of subsurface data acquisition, the PTW-1 was filled with water-based insulation fluid after drilling and completion activities. In preparation for the production test, removal of the fluid was required; therefore, the ESP was activated on September 19, 2023, to facilitate its extraction and to circulate water for cleaning the inside of the wellbore.

In the initial stage of the production test, depressurization was conducted to a level slightly above the estimated gas hydrate dissociation pressure (8.62 MPa/1,250 psi). This procedure successfully verified system operability. However, the measurement of initial effective permeability was not accomplished due to the inability to obtain the requisite data. This limitation arose because the circulation of water unexpectedly elevated the wellbore temperature sufficiently to induce dissociation of gas hydrates in the vicinity of the wellbore within the B1 sand prior to depressurization. ,

On September 29, 2023, the downhole heat trace was activated, and the BV was opened to evaluate the stability and functionality of the production test facilities under operational conditions. Although gas production from the hydrate-bearing B1 sand reservoir at this early stage of the gas production test was not originally intended, thermal energy was introduced into the formation via two primary sources: (1) the downhole heat trace, which had been activated to prevent hydrate reformation within the subsurface production system, and (2) the operation of the ESP motor. These heat sources contributed to near-wellbore hydrate dissociation and the release of a small quantity of methane gas. This methane was first detected through vapor-phase gas sampling at the surface water tank. At that time, the temperature within the B1 sand was approximately 14 °C (57.2 °F). In response, the heat trace was deactivated; however, no appreciable decrease in temperature was observed within the B1 sand reservoir. Accordingly, system operations were suspended on October 4, 2024, to facilitate monitoring of subsequent thermal behavior within the formation, and the BV was closed. It is considered that the Vacuum Insulated Casing, installed in the permafrost section to prevent thawing during operations, together with heat generated by the ESP motor, effectively contributed to thermal retention. This heating increased temperatures within the borehole at the B1 sand interval. Once the approximate original borehole temperature at the B1 sand was reestablished, the BV was reopened, and depressurization operations aimed at inducing gas production from the B1 sand were initiated on October 24, 2023.

9.2.1.2. Depressurization Operation (October 24, 2023 – April 15, 2024)

Depressurization operations utilizing the ESP commenced with a controlled drawdown rate of 5 psi/h. The heat trace was kept on to avoid potential hydrate formation inside production systems. This modest rate was selected to mitigate the risk of excessive sedimental mobilization in the reservoir production that could result from rapid pressure reduction and potentially interrupt the production test.

To operate, an ESP requires a minimum constant volume of water. When the water volume relative to the gas volume is insufficient, the ESP will cease to function (a state referred to as “gas lock”) and borehole pressures will begin to rise. On October 27, upon lowering to a borehole pressure of 950 psi, it was inferred that the ESP was gas locked, necessitating a temporary shutdown of less than 2 h until operability was restored. In an attempt to prevent recurrence of gas lock events, the initial target pressure range was provisionally adjusted to 1,050–1,100 psi.

Following confirmation of stable ESP operation at approximately 1,000 psi, further depressurization to 900 psi was initiated on November 6, 2023, to acquire data characterizing gas hydrate production behavior under stable operating conditions. Stable production at 900 psi was successfully maintained for approximately 2 weeks, from November 7 to November 21, 2023.

On November 21, 2023, a trial depressurization toward 700 psi was initiated with the goal of obtaining production data under conditions of greater pressure drawdown. Although the borehole pressure at the B1 sand interval reached 738 psi on November 25, 2023, the ESP was unable to achieve further depressurization. While a gas lock event was initially suspected, subsequent investigations identified a damaged O-ring in the ESP’s standing valve as the root cause. Replacement of the O-ring resolved the operational issue, and the ESP resumed its original pumping functionality on December 5, 2023.

The well was designed to minimize intervention requirements, and the ESP component replacement was executed by rigless operation using a slickline unit, allowing completion within a single day. ESP-driven depressurization toward a target of 700 psi was resumed on December 9, 2023. Notably, when the borehole pressure of the B1 sand reached 950 psi on December 7, 2023, the produced gas rate became equivalent to the gas consumption rate of the production facilities. However, further pressure reduction was constrained, as it remained impossible to achieve higher drawdowns due to the persistent occurrence of gas locking at operating pressures around 800 psi.

On the same date, approximately 1% by volume of fine sand was observed at the choke skid, subsequently increasing to approximately 4% by volume. On December 13, 2023, depressurization was initiated at a controlled drawdown rate of 2 psi per hour. By December 18, the borehole pressure at the B1 sand layer had decreased to 840 psi, with sand production remaining below 1% by volume.

On December 20, 2023, a pressure increase was observed at both the inner annulus and the ESP intake, suggesting the onset of slug flow. The drawdown pressure reached 760 psi; however, the borehole pressure outside the casing at the B1 sand began to no longer respond to pressure changes inside the borehole. By December 21, 2023, estimated formation pressure was at 940 psi. This large and growing pressure differential suggested potential skin development around the sand control and indicated an increase in the potential for sand production into the wellbore and surface facilities. To monitor potential erosion of surface testing facilities, ultrasonic inspection was initiated on December 20, 2023.

On December 22, 2023, further pressure drawdown within the wellbore could not be performed, and a gas lock event was suspected. As previously, the gas lock was triggered by high GWR. Such events may be caused by very short duration surges of gas rate that are not readily predicted or measured, and hence difficult to avoid. Produced solid content during this period remained below 1% by volume. The borehole pressure at the B1 sand increased to 995 psi on December 23. Upon restart of the ESP, pressure was again decreased to 815 psi by December 29. However, another gas lock event was suspected on December 30, prompting shutdown of the ESP. Subsequently, pressure rose to 998 psi on December 31, and gas production continued by natural flow.

Although the ESP was restarted on December 31, 2023, it was shut down within 1 h due to the recurrence of the gas lock event. The BV was closed to initiate water circulation and later reopened to stabilize the pressure at approximately 1100 psi on January 1, 2024. Depressurization was resumed on January 3, and the borehole pressure reached 858 psi by January 11.

To maximize the potential for stable uninterrupted operations, and noting that gas surges triggering gas lock seemed more common at drawdown to ∼800 psi or lower, a pressure hold was initiated at a borehole pressure of 850 psi at B1 sand on January 18. 2024. This level was successfully held through March 21, 2024. During this period, the rate of produced gas and water remained virtually constant (Figure ). During this stable production phase, pressure and temperature monitoring data from PTW-2, GDW and STW indicate a progressively expanding region in which the B1 sand reservoir pressure is reduced, indicating pressure communication between the wells. Additionally, reservoir temperature decreases were also measured at the monitoring well locations, indicating a progressively expanding region in which gas hydrate was dissociating.

9.

PTW-1 (a) pressure and (b) gas rate during stable operation at 850 psi. The production rate was observed as plateau-like, with a constant bottom hole pressure maintained at ≈850 psi. For further discussion of the inferred nature of reservoir response during this period, please see the companion paper in this SVI by Ohstuki et al. Reproduced with permission from the companion paper 2026 American Chemical Society.

Figure shows that the gas–water ratio exceeded 600 m³/m³, which is the highest value reported among previous production tests. The flat-like gas and water production rates are also unexpected, as prior simulations consistently show a gradual increase in those rates with time and with advance of the dissociation front. The flat production rates, together with the high GWR, cannot be readily explained by reservoir properties using current best reservoir characterization and existing numerical simulation tools, rather, the production behavior likely reflects the combined influences of multiple factors, including the formation of complex high-permeability zones, sand production and near-wellbore skin effects, and wellbore flow behavior.

10.

Comparison of (a) gas production rate, (b) water production rate, and (c) gas–water ratio as a function of test duration from gas hydrate field tests conducted to date, which includes the extended-duration gas production test in Alaska as well as the 2007/2008 Malik test, the 2012 Iġnik Sikumi test, the 2013 and 2017 Nankai Trough tests, and the 2017 South China Sea test. For the Alaska Hydrate P1 data, the elapsed time interval from 86 to 149 days represents the stable production period (January 18 – March 21, 2024) shown in Figure . Note that the time scale is logarithmic. Reproduced with permission from the companion paper 2026 American Chemical Society.

9.2.2. ESP Intermittent Operation (April 16, 2024 – April 19, 2024)

Following the achievement of stable operation through March 21, 2024, and no indication that gas or water rates were likely to change during the remaining time available for testing, an attempt was made to further depressurize the borehole pressure at the B1 sand interval below 850 psi. However, stable operation could not be maintained. It was inferred that an immediate cause was failure of the water injection pump to deliver its originally required performance due to mechanical troubles, specifically in terms of discharge pressure and flow rate. These parameters were essential for supplying supplemental water to the ESP to sustain continuous operation.

The ESP was restarted after completing water injection pump maintenance on March 28, 2024; however, stable operation remained unattainable. An attempt to maintain borehole pressure at approximately 800 psi and subsequently initiate gradual depressurization toward 700 psi was unsuccessful. Therefore, in light of persistent operational instability, an alternative depressurization strategy was implemented: the ESP intermittent operation.

The ESP intermittent trial was conducted from April 16 to April 19, 2024. This method involved intermittent operation of the ESP to lower the annulus fluid level (AFL), followed by cessation of pumping to allow gas production under reduced-pressure conditions. The distinctive feature of this approach is its cyclical operation, designed to reduce the likelihood of gas lock events. The operational concept consisted of the following sequence:

• 1.Impart pressure drawdown via reduction of AFL via ESP operation for a short time period (hours)
• 2.Continued gas production during suspension of ESP operation
• 3.Re-establishment of elevated fluid level
• 4.Repetition of the cycle

This methodology was intended to reduce the occurrence of high instantaneous GWR and thereby prevent gas locking. See ref for further details on the intermittent ESP operation. As a result of intermittent operation, the pressure differential between the outer and inner casings was significantly increased. This pressure differential indicates an accumulating “skin” that may be linked increased fines mobilization/agitation and sand control clogging driven by rapid pressure oscillations imposed during the intermittent operation. Consequently, the intermittent ESP operations approach trial failed to achieve sustained depressurization under stable operating conditions.

The BV was closed on April 19, 2024, following which maintenance was performed on the ESP. Upon completion of the ESP maintenance, efforts were made to reopen the BV. Multiple remedial actions were undertaken, including the application of high-pressure flow through the BV and activation of the DHEH system to mitigate potential hydrate reformation, as well as methanol injection. The prolonged inability to reopen the BV was ultimately attributed to the accumulation of fine sand within the borehole. The BV ultimately was opened on May 23, 2024.

9.3. Depressurization by Jet Pump

Depressurization utilizing the Jet Pump (JP) system commenced on May 23, 2024. The JP system was operated under two distinct modes: “normal JP operation” and “JP operation with chemical injection.” The transition between these modes was necessitated by a progressive increase in differential pressure between sensors within the tubing and behind the casing during sustained normal operation, which ultimately impeded effective borehole depressurization.

JP depressurization established tubing pressures as low as 200 psi, although bottom hole formation pressures were not affected, as indicated by the differential pressure reaching 800 psi just before the end of the test (Figure c).

11.

PTW-1 Jet Pump overall operation chart, with particular emphasis on borehole pressure (BHP), internal tubing pressure, and the differential pressure between the formation (behind the casing) and the tubing interior. As illustrated, a progressive increase in differential pressure was observed, which hindered further depressurization of the borehole pressure.

9.3.1. Normal Depressurization by JP (May 23, 2024 – July 30, 2024)

Depressurization using the JP system was initiated on May 23, 2024. However, the operation was suspended on June 3, 2024, to address the potential for hydrate reformation around the perforated interval, which was believed to have contributed to obstructed pressure communication through the sand control equipment. To mitigate this issue, methanol injection was carried out. JP operation resumed on June 5, 2024, and initial observations indicated that pressure drawdown within the wellbore had recommenced smoothly. Nevertheless, the operation was halted again on June 13, 2024, to perform maintenance on the power fluid pump.

Subsequently, slickline operations were conducted from June 14 to 15, 2024 to inspect and reinstall the JP nozzle, enabling the restart of JP operations on June 15. Observations on June 19, revealed that the pressure within the tubing had been successfully reduced. However, this pressure drawdown did not translate to depressurization at the B1 sand interval, likely due to the advanced development of skin on the surface of the sand control equipment. At that time, the differential pressure between the tubing interior and the annular space behind the casing exceeded 700 psi indicating no further ability to impact pressure drawdown on the reservoir.

To address the lack of pressure communication between the tubing and the B1 sand, a water injection from the wellbore into the B1 sand through the sand control equipment was conducted on June 21, 2024, with the intent of disrupting the suspected skin. However, no definitive indications were obtained regarding the effectiveness of this intervention. In parallel, an alternative approach was considered, involving the chemical dissolution of the polymer component of the sand control equipment, which required the procurement of appropriate chemical agents. Despite the pressure within the tubing reaching approximately 240 psi at the JP inlet, this depressurization remained ineffective in reducing the borehole pressure at the B1 sand interval, which was still at level of 1,100 psi.

Considering this fact, the JP remains a candidate for artificial lift to depressurize and produce methane gas from methane hydrate. Through the long-term gas production test, there was no clear sign of detection of Joule-Thompson effect around wellbore of PTW-1.

9.3.2. JP Depressurization with Chemical Injection (June 28, 2024 – July 14, 2024)

A chemical test was conducted with sand control equipment polymer samples at the site on June 25, 2024, to confirm if the polymer could be removed. After that, two chemical injections were conducted, with water injections through the perforations after each chemical injection. On July 19, slow depressurization was again attempted. While it was observed that pressure inside the tubing could be depressurized to around 200 psi, the pressure difference between inside the tubing and behind the casing continued to increase. On July 30, 2024, the gas production test was completed.

10. Discussion

The following provides further discussion on four general issues: (1) refinement of the geologic model of the initial conditions of the target “B1 sand” reservoirs and bounding sediments; (2) the nature of the production testing as conducted; (3) initial interpretations of the production response from efforts to history match the observed reservoir response to depressurization, and (4) initial insights with respect to the technologies and approaches for gas hydrate production technologies.

10.1. Geologic Model

Pretest attempts to predict reservoir behavior at the test site were informed only by log and side-wall core data gathered at the 2018 STW inferred across the site using surface seismic data. , A primary objective of the subsequent coring, logging, acoustic surveys and monitoring was to acquire new data to reduce the wide uncertainty in the initial condition of the reservoirs and to gauge the potential for reservoir heterogeneity across the test site. The addition of logging data for the GDW, PTW-1 and PTW-2 and the initial integration of these data with analyses of cores taken in the GDW, indicate the reservoir is laterally continuous across the site with only subtle changes in primary petrophysical properties when considered at the reservoir scale. Gas hydrate saturation was found to correlate well with primary petrophysical parameters such as grain size and porosity. , However, internal heterogeneities at very small spatial scales are evident, , and additional work is required to determine the nature of these heterogeneities and how best to represent them at reservoir scales.

10.2. Production Testing

The objective of the production testing phase of the project was to subject the reservoir to controlled and extended periods of pressure reduction, to observe the response, and to use these data to better understand the potential reservoir response of gas hydrates in various settings and under commercial scale operations. The test was successful in achieving sustained drawdown at constant bottom hole pressure over an extended period. Further, the test achieved full success in capturing comprehensive monitoring data within the test well and within three offset monitoring wells. These data reconfirm the potential for sustainable gas hydrate production; however, several factors will complicate the evaluation of these data. First, the test imparted unintended thermal perturbation to the reservoir through the interaction between the water circulation within the ESP and the insulating effects of the VIC. Second, bottom-hole pressures were generally limited to 850 psi or higher and did not achieve sub-500 psi levels as desired, and as such, reservoir response may be muted in comparison to what may have been observed at greater drawdowns. Third, the production response observed during the 60-day constant Bottom Hole Pressure (BHP) period at 850 psi was constant and unvarying. The project objective of holding pressure at one level to determine whether gas production rates would ultimately begin to increase (as expected given steadily expanding dissociation radius) or decrease (a possibility given potential limitations related to heat transfer or other processes), was not achieved. As time available for the testing was limited, it was determined that it would be more valuable to try a new artificial lift system with potential to achieve greater drawdowns, than to continue testing at 850 psi with the goal of ultimately seeing some change in reservoir response. Fourth, while the rate of gas production at a drawdown to 850 psi was generally in line with pretest predictions, the rate of water production was also remarkably constant and substantially below predictions. This lack of water contributed to the operational issues encountered with the ESP. Possible explanations of the high GWR are discussed in a companion paper, and are the subject of ongoing study. Fifth, acquired production test data indicated significantly lower water production rates through the test period than were predicted pretest. In addition, the ratio of gas to water produced exceeds that seen in prior tests or predicted in prior numerical simulations. Understanding this phenomenon is critical, and this issue will require additional time and effort to understand.

10.3. Initial Interpretation of Production Response

Initial efforts to history match the production test data have been only partially successful. It is complex to replicate the observed combination of gas rates (roughly as predicted at these drawdowns), minimal water rates (unexpected), and the vast volumes of data acquired that detail the timing, scale, and geometry of impacts observed in the monitoring wells. Ongoing efforts will continue to focus on (1) further refinements to the input geologic model, including full 3D models that capture the possible range of reservoir quality and heterogeneity as well as the degree of potential water contribution from bounding layers; and (2) incorporation of phenomenon not currently well integrated into the standard gas hydrate modeling platforms, including issues related to progressive geomechanical processes, as well as processes acting within the wellbore.

10.4. Gas Hydrate Production Technology

The test reconfirms the technical viability of gas production from gas hydrate by reservoir depressurization and has provided a valuable test of various key well components. The choice of ESP for artificial lift, which was based in part on the expectation of continuous and substantial water production, was not the best choice given this well configuration. Whether an ESP is appropriate in other settings may depend on the ultimate determination of the cause of the observed low water productionwas it driven by reservoir processes, or was it more a function of well design? The JP appeared very capable of achieving the desired drawdowns with slow drawdown, however, its use at the end of the test and the deteriorating condition of the sand control system, limited the effectiveness of the JP operation. These observations indicate the need to carefully match pump design and placement to reservoir geology and production concept. However, this may remain complex as the nature of reservoir geology/petrophysics continues to be a difficult to know precisely, as is the ultimate function of wellbore components such as sand control. As such, until more is learned, completion designs need to be flexible. Careful considerations on production system design including sparing philosophy how to prepare the spare equipment of such as artificial lift systems could lead minimizing Non Productive Time of the production activities, as well as preparing different artificial lift type systems.

The sand control system achieved the project priority of excluding most sediments from the borehole; however, it did so very aggressively and thus is likely to only be capable of such exclusion for relatively short periods. Clogging of the sand control ultimately fully blocked pressure communication between the wellbore and the formation. In order to understand what happened during JP operation at the perforated location, the sand control equipment was successfully pulled out in July 2025, and further analysis utilizing part of the sand control equipment is being conducted. As of issuance of this project summary paper, skin development on the surface of sand control device and/or plugging of the control device were considered to have blocked the transmission of changes in tubing pressure to the formation. Therefore, while this form of sand control may be very effective for short-duration tests, it may not be the ideal selection for long-term operations where less aggressive systems (for example, a custom screen) combined with completions designed to handle fines may be better suited. Finally, the test utilized a number of heating systems for wellbore flow assurance. These systems were generally not needed, given the high temperatures in the wellbore that were related to the circulation of large quantities of water through the ESP that was progressive heated by of the ESP motor and remained heated due to the use of VIC. Therefore, while flow assurance was not an issue in this test due to the heating issues encountered, it could be considered to remain as a potential challenge in future tests that use different designs.

11. Summary

Over a period exceeding 10 months of production testing, more than 20 months of data acquisition at GDW, PTW-1, and PTW-2, and the 66 months at STW since the commencement of STW DTS data acquisition, the JOGMEC-DOE-USGS Collaborative Gas Hydrate R&D Project in Alaska successfully obtained a wide range of valuable data. These data have and will continue to significantly contribute to the understanding of gas hydrate production behavior and are expected to support future development efforts toward the commercialization of gas hydrate resources.

The major findings and observations derived from this initiative are summarized as follows:

• (1)Three wells were successfully drilled, and log and core data acquired fully confirmed the pretest prediction of site geology and gas hydrate occurrence throughout the test site that had been inferred from the results of the earlier STW.
• (2)Sensors were successfully deployed across all wells, enabling the acquisition of extensive and valuable data before, during, and after the gas production test.
• (3)The rate of produced water was significantly lower than predicted by pretest simulation models, rendering the highest gas–water ratios (GWR) yet observed in a gas hydrate field trial. Clearly, low rates of water production are a positive finding with respect to potential commercial operations; however initial evaluations have not yet been successful in determining the cause for this discrepancy, which is necessary to enable confident in future modeling predictions. During the normal operation period of the ESP, production sampling of both produced gas and produced water was continuously conducted. Periodic analyses of the sampled gas and water were performed. The analytical results of the produced gas revealed that the gas originated exclusively from the B1 sand layer. This finding indicates the observed high GWR was not attributable to any additional gas sources beyond the B1 sand.
• (4)Both ESP and JP were employed as artificial lift. The lack of water production combined with surges in instantaneous gas rates contributed to the ESP experiencing gas lock events that hindered stable operation. The JP demonstrated sufficient depressurization capability within the production tubing.
• (5)A period of over 60 days of constant bottom-hole pressure was achieved at the level of 850 psi. This level was intended as an intermediate stage of drawdown prior to operations at lower pressures. At this level, gas production was constant and stable at a rate of ∼60–70 mcf/d and showed no tendency toward either increase or decrease over the 60 day period. Water levels were also stable during this test at ∼15–20 bwpd.
• (6)Depressurization achieved by the JP did not reach the borehole pressure at the B1 sand, likely due to degradation of permeability of the sand control. This degradation was indicated by an increase in pressure differential across the sand control that was initiated during the ESP operations and intensified during the ESP intermittent operation.
• (7)Although the particle size of sediment entering the production system was controlled to silts, these fine particles still resulted in minor disruptions to production operations. The produced fines caused erosion of various pump components, including the ESP standing valve, rods of the water injection pump, and the choke valve. As full exclusion of sediment is not practical, in the future, systems less vulnerable to issues with sediment will be desired.
• (8)To investigate the performance and condition of the sand control equipment during the production test, the PTW-1 sand control assembly was retrieved at the end of July 2025. The retrieved equipment will be subjected to detailed analysis by multiple laboratories to inform future gas hydrate development and operational strategies.

The JOGMEC-DOE-USGS Collaborative Gas Hydrate R&D Project in Alaska was conducted as part of the activity of MH21-S R&D consortium as planned by the Ministry of Economy, Trade and Industry, Japan, and as part of U.S. DOE Gas Hydrate R&D program. Authors would like to express our sincere appreciation for the support.

The authors declare no competing financial interest.

Published as part of Energy & Fuels special issue “Recent Advances on Gas Hydrates Scientific Drilling in Alaska - An Update from Production Testing Operations during 2023/2024 (Part I)”.