Geology topics

Akihiro Hiruta

Publications and source records attributed to Akihiro Hiruta.

4 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

Permeability and compressibility of “seal” sediment overlying the B1 sand gas hydrate reservoir: Hydrate 02 Geo Data Well, Prudhoe Bay unit, Alaska North Slope

An important element in evaluating the viability of extracting methane from a gas hydrate-bearing reservoir is establishing the effectiveness of the overlying bounding sediment as a seal to prevent gas loss, to enable effective depressurization, and to prevent fluid from entering the reservoir during production. This laboratory study presents results for index properties (e.g., grain density, grain size, and liquid limit), compressibility and swelling indices, and permeability measurements on sediment overlying the gas hydrate-bearing reservoir that was the target of the recent JOGMEC-DOE-USGS collaborative gas hydrate production testing project on the Alaska North Slope (ANS). Sediment analyzed in this study was collected during pressure coring operations in the HYDRATE 02 Geo Data Well (GDW). The ∼6.1 m sediment interval recovered in Cores 13P and 14P (878.74–884.88 m measured depth, MD) exhibited heterogeneous sedimentologic characteristics at the centimeter scale, with sediments ranging from clay to thin silty-sand lithologies. Permeability measurements and index-property correlations indicate the interval’s overall in situ vertical permeability ranges from 0.2 to 3.6 microdarcy (μD). Results for compressibility ( C C = 0.255 ± 0.02) and swelling index ( C S = 0.04 ± 0.01) are consistent with estimates based on mineralogy and liquid limit correlations. Based on the measured compressibility, the ∼3 MPa increase in effective stress during the stable phase of depressurization-induced production is anticipated to have imposed 2.43 cm of compaction per meter in the reservoir overburden, reducing permeability by ∼36%. The overburden sediment’s low in situ permeability (3 to 4 orders of magnitude below permeabilities measured in the gas hydrate-bearing part of the B1 sand (unit B)) suggests the B1 sand′s overburden provides an effective seal. Such a seal promotes efficient production by limiting fluid flow into the reservoir during depressurization-induced gas hydrate dissociation.

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↗