Rising ocean temperatures and falling sea level are commonly cited as mechanisms of marine gas hydrate destabilization. More recently, uplift—both isostatic and tectonic—has been invoked. However, the effect of tectonic shortening and uplift on gas hydrate stability zone extent has not been validated via integrated computational modeling. Here, modeling along the Hikurangi margin of New Zealand illustrates the mechanism of tectonic uplift as a driver of gas hydrate destabilization. We simulate how tectonic uplift and shortening affect the presence and decrease the extent of a gas hydrate stability zone. We suggest that resultant gas hydrate destabilization in the marine realm may impact the global carbon cycle and oceanic chemistry over geologic time.

Analyses of a horizontal well drilled in the Shublik Formation within the southern part of the Prudhoe Bay field provide the first glimpse of the unit’s potential as an unconventional resource. Drilled in 1996, the 1450 ft (442 m) long well, PBU X-19B L1, targeted the 17 ft (5 m) thick Shublik Zone B. More than 70% of the lateral well path sampled that target, a feat of precise geosteering years before the unconventional revolution. The well operator’s drilling plan focused on the middle subzone of Zone B. The well history ascribes the focus on the middle subzone to its high silt content, open fractures, and significant hydrocarbon shows. Contrary to the drilling narrative, cuttings from 41 intervals indicate that siltstone monotonically decreases in Shublik Zone B, on average, from 50% to 40% to 30% in the three subzones from top to base. The limestone concentration inversely varies with the siltstone concentration through Zone B, steadily increasing from top to base (40%, 50%, and 60%). Hydrocarbon shows in the upper and middle subzones of Zone B range from good to fair, whereas the shows in the lower Zone B are weaker. Unfortunately, scant geochemical analyses of oil produced from the Shublik flow test combined with engineering difficulties prevent a definitive conclusion as to the source of the oil — the fractured Shublik Formation or the underlying Ivishak Sandstone. However, on the basis of favorable lithology, hydrocarbon shows, and fracture density, the upper and middle subzones of Zone B should be targeted as a potential unconventional accumulation if and when a well is drilled in the pod of active source rock downdip.

We have developed an approach integrating statistical rock physics with pressure and thermal history modeling for quantitative seismic interpretation (QSI). Extending the training data for lithofacies classification and deriving distributions for scenarios not available in the original training require knowledge about geologic processes affecting the elastic properties in the subsurface. We model pressure and thermal history and corresponding smectite to illite diagenesis with a basin model across Thunder Horse minibasin in the Gulf of Mexico. By comparing the mapped lithofacies with and without basin-modeling extrapolations against the results of a reference workflow, we found the value of integrating basin modeling results and statistical rock physics with QSI workflows. The reference workflow uses all available data from two wells in the QSI. The first workflow performs the same lithofacies classification with data from only a single well and does not account for spatial trends away from the well. In the second workflow, we use data from only a single well, the same well as in the first workflow, and bring in extrapolation from the basin and petroleum system modeling at the location of the second well. Results for the first workflow indicate significant differences with the reference workflow in the training data, the quality of the inverted impedance volumes, and the classified reservoir lithofacies. In the second workflow, the guided extrapolation of the training data accounts for spatial trends away from the well and the quality of the impedance inversion significantly improves. The predicted lithofacies map in this scenario shows only minor differences from the reference workflow, and the posterior probabilities of lithofacies show less uncertainty compared with the first workflow. The superiority of the second workflow demonstrates the added value of the integration workflow to QSI in cases of spatially limited well control.

Over the past 20 years, oil and gas companies have turned their attention to producing petroleum directly from organic-rich shale. Successful exploration, appraisal, and production strategies for source rocks critically depend on reliable identification of their organic components (kerogen, in particular) and their generation potential. There is mounting demand to evaluate organic richness in terms of quantity (i.e., total organic carbon) and quality (i.e., hydrogen index) from seismic data, which is usually the only source of information in the early development period of emerging shale plays. We have delineated major seismic lithofacies on the Alaska North Slope using elastic, seismic, and petrophysical properties. We performed a well-established quantitative seismic interpretation workflow to integrate geochemical data in the lithofacies definition. Rock-physics templates (RPTs) of seismic parameters, acoustic impedance, versus P-wave to S-wave velocity ratio (VP/VS), are constructed for each lithofacies to assess variations in pore fluid and lithology. We developed correlations between source rock properties (hydrogen index and total organic carbon) and petrophysical properties (bulk density, porosity, and sonic velocity ratio) of the major lithofacies. These correlations, together with facies-specific RPTs, can be used to predict organic richness and source rock properties away from drilled wells. The models are validated by training data from two regional wells to observe their applicability on the Alaska North Slope.

Natural hydrogen has generated great interest as a potential clean and renewable energy source. To understand the occurrence of natural hydrogen, 103 1-m deep soil gas samples were acquired near the San Andreas Fault at Jasper Ridge and Portola Valley, California, USA. The gas samples were analyzed for hydrogen, helium, carbon dioxide, light hydrocarbons, and fixed gas concentrations. Statistical data analysis was carried out to group samples, reveal their spatial distribution, and understand possible sources of the gases.High concentrations of hydrogen up to 20.3 ppmv and 17.3 ppmv occur in Jasper Ridge and Portola Valley, respectively, ~ 30-35 times greater than the atmospheric concentration. Most samples with high hydrogen concentrations fall on or near faults, suggesting an origin by serpentinization or geomechanical activation of catalytic sites in minerals, although a deep-seated primordial origin cannot be excluded. Elevated concentrations of carbon dioxide resulted from aerobic microbial degradation of organic matter and elevated concentrations of light hydrocarbons likely resulted from thermal cracking of organic matter.