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Research about Alaska North Slope

Source-linked reports with geographic coverage including Alaska North Slope.

11 recordsLinked to original sources
USGS2026

Production of secondary microbial methane from a gas hydrate-bearing reservoir at the HYDRATE P1 Production Test Well (PTW-1) on the Alaskan North Slope

Gas hydrate in the Alaskan North Slope (ANS) is believed to contain as much methane as the known conventional gas accumulations in the Prudhoe Bay field. The JOGMEC-DOE-USGS Collaborative Gas Hydrate R&D Project conducted an extended-duration production test from the sub-permafrost, gas-hydrate saturated B1 sand reservoir (unit B) at the Kuparuk State 7-11-12 Site in the Prudhoe Bay Unit of the ANS. Using compositional and stable isotopic data measured on gas produced from well cuttings and pressure cores collected from the HYDRATE 02 Geo Data Well (GDW), we differentiate primary microbial, secondary microbial, and trace thermogenic gas sources. The upper part of the well contained predominantly primary microbial methane from near the surface to the SV6 stratigraphic horizon at 1133 ft (345.3 m) measured depth (MD). Below that, the gas composition transitioned to a mixture of mostly primary and secondary microbial methane to near the base of ice-bearing permafrost at 1968 ft (599.8 m) MD. With greater depth to 3558 ft (1084.5 m) MD, which includes the D1 sand (unit D), the B1 sand (unit B), and the base of gas hydrate stability at 3113 ft (948.8 m) MD, the gas composition was greater than 98% secondary microbial methane with the remainder being oil-associated thermogenic gas migrated from the deep Sadlerochit Formation. The unit B vertical gas profile derived from degassed pressure cores demonstrated that gas dissolved in the clay-rich sediment intervals bounding the B1 sand reservoir was distinct from dissolved and hydrate-caged gases in the sand-rich hydrate-bearing reservoir. The HYDRATE P1 Production Test Well (PTW-1) targeted and successfully extracted gas dissociated from hydrate gas in the B1 sand for 151 days when using an electrical submersible pump to depressurize the reservoir with subsequent depressurization achieved through the use of a jet pump. Gas produced from PTW-1 was mostly indistinguishable from the gas compositional profile measured through the B1 sand and generally distinct from dissolved gas in the bounding clay-rich sediments, confirming that the upper and lower bounding units limited infiltration into the reservoir during production. Isolation of the bounding units from the reservoir contributed to the unexpectedly high ratio of production gas to water observed during the extended-duration gas hydrate production test at PTW-1.

Alaska↗
USGS2026

Depositional environment and diagenetic history of gas hydrate-bearing sediments of the Alaska North Slope (HYDRATE 02 Geo Data Well)

We characterized the lithological, solid-phase geochemical, and rock magnetic properties of sediment cores from subpermafrost strata on the Alaska North Slope collected as part of the U.S. Department of Energy (DOE), the Japan Organization for Metals and Energy Security (JOGMEC), and the U.S. Geological Survey (USGS) Collaborative Gas Hydrate Research and Development (R&D) Project in Alaska. Pressure cores were recovered from the HYDRATE 02 Geo Data Well (GDW) at the Kuparuk State 7-11-12 site through two hydrate-bearing sand reservoirs, the B1 and D1 sands, and their finer-grained bounding sediments. Both the B1 and D1 sands are quartz-rich, chert-bearing, very fine litharenite sands. These submature to immature sands are poorly to moderately sorted and angular with local fine-scale cross-stratification. The B1 sand has larger grains and a lower clay content as compared to the D1 sand. These sands are the upper portions of upward coarsening progradational sequences. The clay- and silt-rich bounding muds exhibit fine-scale wavy and lenticular laminations, suggesting episodic high energy deposition events. Overall, these sediments were deposited in a shoreface to nearshore marine environment during the Paleogene, modulated by changing depositional energy associated with sea level variation. Organic matter δ 13 C and C/N composition of these sediments indicate a source mixture of land plants and freshwater plankton, with possible minor presence of oil within the B1 sand. These sediments contain high and variable total sulfur (TS) content, suggesting porewater conditions influenced by variable salinity over time. Rock magnetic analyses indicate precipitation of greigite in the mud beneath the D1 sand, in the basal C shale overlying the B1 sand, and the mud beneath the B1 sand, likely due to intervals of sulfate limitation during periods of lower Arctic Ocean salinity. Based on pyrite abundance, TS, and δ 34 S-TS composition, the D1 sand and bounding sediments experienced more substantial sulfide precipitation. The unit E basal shale overlying the D1 sand contains a 0.25 m thick pyrite-dominant sand, indicating local bottom water anoxic conditions. X-ray fluorescence scanning and discrete measurements provide additional supporting interpretation of the depositional and diagenetic processes that have occurred at this site and track the relative amount of drilling fluid contamination with barium abundance in the core samples.

Alaska↗
USGS2026

Lithological control of gas hydrate saturation determined by pressure core analysis in sub-permafrost reservoirs of the Alaska North Slope (HYDRATE 02 Geo Data Well)

Quantitatively degassing pressure cores by controlled depressurization is a key approach to characterizing gas hydrate reservoirs by measuring the gas hydrate saturation (S h ) of sediments. We measured S h for 53 core sections from the Alaska North Slope during the JOGMEC-DOE-USGS Collaborative Gas Hydrate R&D Project in Alaska, from subpermafrost sediments that were later subjected to an extended-duration gas production test. We characterized lithologic influences on S h using physical property core scans (P-wave velocity, gamma ray attenuation density, and X-ray computed tomography) and grain size measurements. Pressure cores were recovered from the Hydrate-02 Geo Data Well (GDW) at the Kuparuk State 7-11-12 site through two hydrate-bearing sand reservoirs, the B1 and D1 sands, and their finer-grained bounding sediments. S h reaches very high values (68 to 91% of the pore space) in silty fine sands within the B1 sand, which also contains two lower P-wave velocity intervals (one measured at 30% S h ) within the main reservoir. S h and grain sizes of the B1 sand are generally higher than the D1 sand, which hosts high S h (53 to 73%) within its sandy silt to silty fine sands. The heterogeneous silty clay to silt “seal” sediments directly overlying both reservoirs have low S h (0 to 13%) even in thin, coarser beds, suggesting minimal methane transport between the reservoir and seal. S h decreases with depth downward toward the base of both the D1 and B1 sands, corresponding to decreasing grain size. These transitions are underlain by silty clay to clayey silt sediments with low S h (<10%), similar to the seal sediments. Slow depressurization was used to estimate a brackish salinity based on the pressure and temperature of the onset of hydrate dissociation for two core sections within the B1 sand. We show that S h increases with median grain size, sand content, and porosity but exhibits some variation within the sand beds that is not directly explained by lithology.

Alaska↗
USGS2026

Oil in the Alaska North Slope gas hydrate reservoir: Micro-CT and flow simulation insights into permeability

Gas hydrate-bearing sands on the Alaska North Slope (ANS) host minor volumes of crude oil whose impact on formation permeability has never been quantified relative to a gas hydrate reservoir system. Here, we combine in situ pressure-core microcomputed-tomography (μ-CT), thermogravimetric analysis (TGA), gas-chromatography–mass-spectrometry (GC–MS), scanning-electron microscopy coupled with energy-dispersive spectroscopy (SEM-EDS), and Stokes-flow simulation to (i) quantify oil saturation, (ii) infer its source, and (iii) evaluate its influence on permeability after gas-hydrate dissociation. μ-CT and SEM-EDS imaging identify the host sediment as silty, with some grain-coating clay present. Eight representative 300 3 -voxel subvolumes extracted from a preserved pressure core (Core 15P-3c, from the B1 sand (unit B), HYDRATE 02 Geo Data Well (GDW), 886.96–887.29 m measured depth, MD) exhibit porosities of 0.34–0.37 and an average oil saturation of 0.09 ± 0.03, in comparison to an independent TGA-based estimate of 0.16. GC-MS fingerprints obtained from an adjacent depressurized core (Core 17P-1, 891.37–891.44 m MD), together with oil pore habit revealed by μ-CT, suggest that the oil is partly native but also includes contributions from mineral oil-based drilling fluid contamination. Further analysis of oil–porewater interactions and flushing tests confirms that native oil saturation in the analyzed samples ranges from 0.04 to 0.08 with an average of approximately 0.06, and the oil is highly immobile. Flow simulations demonstrate that the native oil saturation of ≈0.06 reduces permeability by approximately 50% due to both pore blockage and increased flow-path tortuosity. These findings reveal the potential presence of native oil within the ANS gas hydrate reservoir and suggest that future simulation models may need to account for its impact on permeability to improve long-term performance predictions of gas and water production.

Alaska↗
USGS2026

Consolidation and permeability of the B1 and D1 gas hydrate bearing sands and associated seal sediments of the extended-duration gas production test site on the Alaska North Slope

Gas hydrate, a solid combination of gas (mostly methane in nature) and water molecules stable at low temperatures and elevated pressures, occurs naturally in marine and permafrost-associated environments. Gas hydrate reservoirs, such as those in the Alaska North Slope, have been considered potential energy resources for gas production. To understand the petrophysical and geo-mechanical characteristics of the reservoir, core samples retrieved from the site of the JOGMEC-DOE-USGS collaborative gas hydrate R&D project have been analyzed in the laboratory for their hydraulic and mechanical properties. This paper focuses on both seal and reservoir samples associated with the B1 and D1 sands, which are evaluated for index properties (including porosity, grain size distribution, liquid and plastic limits, specific surface area, and specific gravity), consolidation, permeability, and water retention. Furthermore, the reservoir core samples were tested with pore-filling, laboratory-grown tetrahydrofuran hydrate, in order to assess reservoir behavior during gas production from hydrates. Under simulated in situ stress conditions, the seal and hydrate-free reservoir cores had a permeability anisotropy ratio of k h / k v = 3.0–5.0, and k h / k v = 2.4–3.0 for the reservoir tetrahydrofuran hydrate-bearing cores. The data suggest that depressurizing the reservoir to induce hydrate dissociation alters the reservoir effective permeability in three ways: permeabilities decrease due to porosity lost (e.g., the initial reservoir thickness can decrease by up to 5% upon 7 MPa depressurization), permeability increases due to the loss of solid hydrate in the pore space, and permeability anisotropy k h / k v decreases in response to the evolving pore-space geometry. We show that given the simulated in situ gas hydrate saturations (i.e., S h = 32% in core 7P-2E and S h = 21% in core 20P-4), gas production from the dissociation of tetrahydrofuran hydrate in the two tested cores results in a net increase in effective permeability and a decrease in k h / k v . This study highlights the importance of investigating seal and reservoir sediments and the impacts of depressurization on the porosity and permeability responses during production.

Alaska↗
USGS2022

Alaska North Slope terrestrial gas hydrate systems: Insights from scientific drilling

A wealth of information has been accumulated regarding the occurrence of gas hydrates in nature, leading to significant advancements in our understanding of the geologic controls on their occurrence in both the terrestrial and marine settings of the Arctic. Gas hydrate accumulations discovered in the Alaska North Slope have been the focus of several important geoscience and production testing research programs. The Mount Elbert Gas Hydrate Stratigraphic Test Well of 2007 yielded one of the most complete geologic datasets on Arctic gas hydrate systems and important reservoir engineering data. The 2011/2012 field test of the Iġnik Sikumi gas hydrate production test well provided important insight into gas hydrate production technologies, yielding additional information on the petrophysical properties of gas hydrate reservoir systems. The Hydrate-01 Stratigraphic Test Well, drilled late in 2018, confirmed the geologic conditions at an Alaska North Slope drill site that was selected for an extended gas hydrate production test. In 2018, the US Geological Survey used information derived from previous scientific drilling programs to assess the volume of undiscovered, technically recoverable gas resources at a mean estimate of about 54 trillion cubic feet (~1.5 trillion cubic meters) within the gas hydrates in the North Slope of Alaska. This assessment has shown that the amount of gas stored as gas hydrates in this area is equal to about half of the known volume of conventional natural gas resources in the region.

Alaska↗
USGS2011

Permafrost-associated natural gas hydrate occurrences on the Alaska North Slope

In the 1960s Russian scientists made what was then a bold assertion that gas hydrates should occur in abundance in nature. Since this early start, the scientific foundation has been built for the realization that gas hydrates are a global phenomenon, occurring in permafrost regions of the arctic and in deep water portions of most continental margins worldwide. In 1995, the U.S. Geological Survey made the first systematic assessment of the in-place natural gas hydrate resources of the United States. That study suggested that the amount of gas in the gas hydrate accumulations of northern Alaska probably exceeds the volume of known conventional gas resources on the North Slope. Researchers have long speculated that gas hydrates could eventually become a producible energy resource, yet technical and economic hurdles have historically made gas hydrate development a distant goal. This view began to change in recent years with the realization that this unconventional resource could be developed with existing conventional oil and gas production technology. One of the most significant developments was the completion of the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well on the Alaska North Slope, which along with the Mallik project in Canada, have for the first time allowed the rational assessment of gas hydrate production technology and concepts. Almost 40 years of gas hydrate research in northern Alaska has confirmed the occurrence of at least two large gas hydrate accumulations on the North Slope. We have also seen in Alaska the first ever assessment of how much gas could be technically recovered from gas hydrates. However, significant technical concerns need to be further resolved in order to assess the ultimate impact of gas hydrate energy resource development in northern Alaska.

Alaska↗
USGS2011

The characteristics of gas hydrates recovered from the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope

Systematic analyses have been carried out on two gas hydrate-bearing sediment core samples, HYPV4, which was preserved by CH 4 gas pressurization, and HYLN7, which was preserved in liquid-nitrogen, recovered from the BPXA-DOE-USGS Mount Elbert Stratigraphic Test Well. Gas hydrate in the studied core samples was found by observation to have developed in sediment pores, and the distribution of hydrate saturation in the cores imply that gas hydrate had experienced stepwise dissociation before it was stabilized by either liquid nitrogen or pressurizing gas. The gas hydrates were determined to be structure Type I hydrate with hydration numbers of approximately 6.1 by instrumentation methods such as powder X-ray diffraction, Raman spectroscopy and solid state 13 C NMR. The hydrate gas composition was predominantly methane, and isotopic analysis showed that the methane was of thermogenic origin (mean δ 13 C = −48.6‰ and δ D = −248‰ for sample HYLN7). Isotopic analysis of methane from sample HYPV4 revealed secondary hydrate formation from the pressurizing methane gas during storage.

Alaska↗
USGS2011

Gas geochemistry of the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: implications for gas hydrate exploration in the Arctic

Gases were analyzed from well cuttings, core, gas hydrate, and formation tests at the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well, drilled within the Milne Point Unit, Alaska North Slope. The well penetrated a portion of the Eileen gas hydrate deposit, which overlies the more deeply buried Prudhoe Bay, Milne Point, West Sak, and Kuparuk River oil fields. Gas sources in the upper 200 m are predominantly from microbial sources (C 1 isotopic compositions ranging from −86.4 to −80.6‰). The C 1 isotopic composition becomes progressively enriched from 200 m to the top of the gas hydrate-bearing sands at 600 m. The tested gas hydrates occur in two primary intervals, units D and C, between 614.0 m and 664.7 m, containing a total of 29.3 m of gas hydrate-bearing sands. The hydrocarbon gases in cuttings and core samples from 604 to 914 m are composed of methane with very little ethane. The isotopic composition of the methane carbon ranges from −50.1 to −43.9‰ with several outliers, generally decreasing with depth. Gas samples collected by the Modular Formation Dynamics Testing (MDT) tool in the hydrate-bearing units were similarly composed mainly of methane, with up to 284 ppm ethane. The methane isotopic composition ranged from −48.2 to −48.0‰ in the C sand and from −48.4 to −46.6‰ in the D sand. Methane hydrogen isotopic composition ranged from −238 to −230‰, with slightly more depleted values in the deeper C sand. These results are consistent with the concept that the Eileen gas hydrates contain a mixture of deep-sourced, microbially biodegraded thermogenic gas, with lesser amounts of thermogenic oil-associated gas, and coal gas. Thermal gases are likely sourced from existing oil and gas accumulations that have migrated up-dip and/or up-fault and formed gas hydrate in response to climate cooling with permafrost formation.

Alaska↗
USGS2011

Downhole well log and core montages from the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope

The BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well was an integral part of an ongoing project to determine the future energy resource potential of gas hydrates on the Alaska North Slope. As part of this effort, the Mount Elbert well included an advanced downhole geophysical logging program. Because gas hydrate is unstable at ground surface pressure and temperature conditions, a major emphasis was placed on the downhole-logging program to determine the occurrence of gas hydrates and the in-situ physical properties of the sediments. In support of this effort, well-log and core data montages have been compiled which include downhole log and core-data obtained from the gas-hydrate-bearing sedimentary section in the Mount Elbert well. Also shown are numerous reservoir parameters, including gas-hydrate saturation and sediment porosity log traces calculated from available downhole well log and core data.

Alaska↗