The potential response of the hydrate reservoir in the South Shetland Margin, Antarctic Peninsula, to ocean warming over the 21st century

In the South Shetland Margin (SSM), Antarctic Peninsula, a bottom-simulating reflector indicates the presence of hydrate between ca. 500 and 3000 m water depth (mwd). The cold seabed temperatures allow hydrate stability at shallower water depths. During the past five decades, the Antarctic Peninsula has been warming up faster than any other part of the Southern Hemisphere, and long-term ocean warming could affect the stability of the SSM hydrate reservoir at shallow waters. Here, we model the transient response of the SSM hydrate reservoir between 375 and 450 mwd to ocean warming for the period 1958–2100. For the period 1958–2010, seabed temperatures are given by oceanographic measurements in the area, and for 2010–2100 by two temperature scenarios represented by the observed trends for the periods 1960–2010 (0.0034°C y−1) and 1980–2010 (0.023°C y−1). Our results show no hydrate-sourced methane emissions for an ocean warming rate at the seabed of 0.0034 °C y−1. For a rate of 0.023°C y−1, emissions start in 2028 at 375 mwd and extend to 442 mwd at an average rate of about 0.91 mwd y−1, releasing ca. 1.13×103 mol y−1 of methane per metre along the margin by 2100. These emissions originate from dissociation at the top of the hydrate layer, a physical process that steady-state modelling cannot represent. Our results are speculative on account of the lack of direct evidence of a shallow water hydrate reservoir, but they illustrate that the SSM is a key area to observe the effects of ocean warming-induced hydrate dissociation in the coming decades

A quick-look method for initial evaluation of gas hydrate stability below subaqueous permafrost

Many studies demonstrated the coexistence of subaqueous permafrost and gas hydrate. Subaqueous permafrost could be a factor affecting the formation/dissociation of gas hydrate. Here, we propose a simple empirical approach that allows estimating the steady-state conditions for gas hydrate stability in the presence of subaqueous permafrost. This approach was derived for pressure, temperature, and salinity conditions typical of subaqueous permafrost in marine (brine) and lacustrine (freshwater) environments

Spatial and temporal evolution of rifting and continental breakup in the Eastern Black Sea Basin revealed by long‐offset seismic reflection data

The age and distribution of the synrift and early postrift infill records the spatial and temporal distribution of extension and breakup processes in a rift basin. The Eastern Black Sea Basin (EBSB) is thought to have formed by back‐arc extension during Cretaceous to Early Cenozoic time. However, a lack of direct constraints on its deep stratigraphy leaves uncertainties over the time, duration, and location for rifting and breakup processes in the basin. Here we use the enhanced imaging provided by 2‐D long‐offset seismic reflection profiles to analyze the deep structural and stratigraphic elements of the EBSB. Based on these elements, we infer the presence of two distinct Late Cretaceous synrift units, recording initial extension (rift stage 1) over the continental highs (Shatsky Ridge and the Mid Black Sea High), followed by strain localization along the major basin‐bounding faults and rift migration toward the basin axis (rift stage 2). Overlying these units, Palaeocene(?)‐Eocene and Oligocene units show a synkinematic character in the NW, with evidence for ongoing extension until Oligocene time. Toward the SE, these sequences are instead postkinematic, directly overlaying a basement emplaced during breakup. We interpret the Palaeocene(?)‐Oligocene units to record the time spanning from the initiation of breakup (Late Cretaceous‐Palaeocene, in the SE) to the end of extension (Oligocene, in the NW). The first ubiquitously postrift infill is the Lower Miocene Maykop Formation. Our results highlight the along‐strike temporal variability of extension and breakup processes in the EBSB

Geophysical early warning of salt precipitation during geological carbon sequestration

Sequestration of industrial carbon dioxide (CO2) in deep geological saline aquifers is needed to mitigate global greenhouse gas emissions; monitoring the mechanical integrity of reservoir formations is essential for effective and safe operations. Clogging of fluid transport pathways in rocks from CO2-induced salt precipitation reduces injectivity and potentially compromises the reservoir storage integrity through pore fluid pressure build-up. Here, we show that early warning of salt precipitation can be achieved through geophysical remote sensing. From elastic P- and S-wave velocity and electrical resistivity monitoring during controlled laboratory CO2 injection experiments into brine-saturated quartz-sandstone of high porosity (29%) and permeability (1660 mD), and X-ray CT imaging of pore-scale salt precipitation, we were able to observe, for the first time, how CO2-induced salt precipitation leads to detectable geophysical signatures. We inferred salt-induced rock changes from (i) strain changes, (ii) a permanent ~ 1.5% decrease in wave velocities, linking the geophysical signatures to salt volume fraction through geophysical models, and (iii) increases of porosity (by ~ 6%) and permeability (~ 7%). Despite over 10% salt saturation, no clogging effects were observed, which suggests salt precipitation could extend to large sub-surface regions without loss of CO2 injectivity into high porosity and permeability saline sandstone aquifers

Laboratory observations of frequency-dependent ultrasonic P-wave velocity and attenuation during methane hydrate formation in Berea sandstone

Knowledge of the effect of methane hydrate saturation and morphology on elastic wave attenuation could help reduce ambiguity in seafloor hydrate content estimates. These are needed for seafloor resource and geohazard assessment, as well as to improve predictions of greenhouse gas fluxes into the water column. At low hydrate saturations, measuring attenuation can be particularly useful as the seismic velocity of hydrate-bearing sediments is relatively insensitive to hydrate content. Here, we present laboratory ultrasonic (448–782 kHz) measurements of P-wave velocity and attenuation for successive cycles of methane hydrate formation (maximum hydrate saturation of 26 per cent) in Berea sandstone. We observed systematic and repeatable changes in the velocity and attenuation frequency spectra with hydrate saturation. Attenuation generally increases with hydrate saturation, and with measurement frequency at hydrate saturations below 6 per cent. For hydrate saturations greater than 6 per cent, attenuation decreases with frequency. The results support earlier experimental observations of frequency-dependent attenuation peaks at specific hydrate saturations. We used an effective medium rock-physics model which considers attenuation from gas bubble resonance, inertial fluid flow and squirt flow from both fluid inclusions in hydrate and different aspect ratio pores created during hydrate formation. Using this model, we linked the measured attenuation spectral changes to a decrease in coexisting methane gas bubble radius, and creation of different aspect ratio pores during hydrate formation

Reactive transport modelling insights into CO2 migration through sub-vertical fluid flow structures

Sub-vertical geological structures that cut through the overburden, usually called chimneys or pipes, are common in sedimentary basins. Chimneys behave as conduits that hydraulically connect deep strata with the overburden and seabed. Hence, if stored CO2 migrates to a sufficiently high permeability chimney the risk of CO2 leakage at the seabed increases. Despite the possible negative effects these structures may have on the integrity of CO2 storage sites, little is known about (i) their effective permeability distribution, controlled by the combined role of fractures and matrix, and (ii) feedback mechanisms between porosity-permeability, CO2 reactivity and mineralogy within them. Reactive transport modelling is used to perform 2D axisymmetric radial simulations of geological systems containing chimneys. CO2 saturations of 10%, 30% and 50% are imposed on a cell located next to the symmetry axis at the base of the model. Under hydrostatic conditions, CO2 reaches the seabed, at 500 m above the injection point, in less than 100 yr using injected CO2 saturations at or above 30% and with overburden isotropic permeabilities and chimney vertical permeabilities above 10−14  m2. Vertical fractures with apertures larger than 0.05 mm for volume fractions below 1% are sufficient to sustain such high vertical permeabilities in the chimney with a relatively high cap rock matrix permeability of 10−16 m2. Over 100 yr of CO2 injection, changes in porosity and permeability due to mineral precipitation/dissolution are negligible. For this time scale, in systems containing chimneys sufficiently far away from the injection well, the risk of CO2 leakage at the seabed is primarily controlled by the pre-existing hydrogeological state of the system

Core-scale geophysical and hydromechanical analysis of seabed sediments affected by CO2 venting

Safe offshore Carbon Capture Utilization and Storage (CCUS) includes monitoring of the subseafloor, to identify and assess potential CO2 leaks from the geological reservoir through seal bypass structures. We simulated CO2-leaking through shallow marine sediments of the North Sea, using two gravity core samples from ∼1 and ∼2.1 m below seafloor. Both samples were subjected to brine−CO2 flow-through, with continuous monitoring of their transport, elastic and mechanical properties, using electrical resistivity, permeability, P-wave velocity and attenuation, and axial strains. We used the collected geophysical data to calibrate a resistivity-saturation model based on Archie’s law extended for clay content, and a rock physics for the elastic properties. The P-wave attributes detected the presence of CO2 in the sediment, but failed in providing accurate estimates of the CO2 saturation. Our results estimate porosities of 0.44 and 0.54, a background permeability of ∼10−15 and ∼10-17 m2, and maximum CO2 saturation of 18 % and 10 % (±5 %), for the sandier (shallower) and muddier (deeper) sample, respectively. The finer-grained sample likely suffered some degree of gas-induced fracturing, exhibiting an effective CO2 permeability increase sharper than the coarser-grained sample. Our core-scale multidisciplinary experiment contributes to improve the general interpretation of shallow sub-seafloor gas distribution and migration patterns

Experimental assessment of pore fluid distribution and geomechanical changes in saline sandstone reservoirs during and after CO2 injection

Responsible CO2 geosequestration requires a comprehensive assessment of the geomechanical integrity of saline reservoir formations during and after CO2 injection. We assessed the geomechanical effects of CO2 injection and post-injection aquifer recharge on weakly cemented, synthetic-sandstone (38% porosity) sample in the laboratory under dry and brine-saturated conditions, before and after subjecting the sample to variable pore pressure brine-CO2 flow-through tests (∼170 h). We measured ultrasonic P- and S-wave velocities (Vp, Vs) and attenuations, electrical resistivity and volumetric strain (εv). Vs was found to be an excellent indicator of mechanical deformation during CO2 injection; Vp gives mechanical and pore fluid distribution information, allowing quantification of the individual contribution of both phenomena when combined with resistivity. Abrupt strain recovery during imbibition suggests that aquifer recharge after ceasing CO2 injection might affect the geomechanical stability of the reservoir. Static and dynamic parameters indicate the sample experienced minor geomechanical changes during CO2 exposure, with an increase of Δεv <3% and a drop in ΔVs ∼1%. In contrast, due to brine-induced hydro-mechanical alteration, Δεv increased by ∼10% and ΔVs by ∼6%. This study provides a multiparameter, thermo-hydro-mechanical-chemical database needed to validate monitoring tools and simulators, for prediction of the geomechanical behaviour of CO2 storage reservoirs

Seismic characterization and modelling of the gas hydrate system in the northern Bay of Bengal, offshore Bangladesh

The offshore Bangladesh includes the northern Bengal fan, where sediment supply from the Ganges and Brahmaputra rivers has resulted in the accumulation of up to 20 km of shallow-marine, fluvio-deltaic and slope sediments that have accumulated during rapid tectonic subsidence since the late Miocene. The high sedimentation rates, along with high organic matter content, make this area favorable for the formation of natural gas from both microbial and thermogenic sources. Here we use multichannel seismic reflection profiles and modelling of the gas hydrate stability zone (GHSZ) to present the first evidence for the occurrence of natural gas hydrate in the offshore Bangladesh. First, we analyze the sediments of the shelf and slope areas, which are characterized by downslope sediment transport features and by the presence, in places, of faults/fractures as well as widely distributed amplitude anomalies and seismic facies that we relate to the presence of gas. A high-amplitude reversed polarity reflection of variable continuity that mimics the seafloor and cross-cut stratigraphy is interpreted as a Bottom Simulating Reflector (BSR). The BSR is observed in several areas that are predominantly located in the E-SE of the study area, in water depths of 1300–1900 m and at depths below seafloor of 250–440 m. Sediments above BSR locations generally show higher seismic interval velocities reaching values of ∼1920–1940 m/s, which are consistent with the presence of gas hydrate in shallow marine sediments. Furthermore, the BSR lies at approximately the same depth as the theoretical base of the gas (methane) hydrate stability zone (BGHSZ), calculated assuming a 3.5 % wt pore water salinity and using existing geothermal gradient and seafloor temperature data from the study region. However, in places, the BSR lies deeper or shallower than the base of the modelled BGHSZ. These discrepancies include areas where faults/fractures and seismic evidence linked to fluid flow from deeper reservoirs reach the GHSZ disrupting its stratigraphic continuity. At these locations, we suggest that faults/fractures act as fluid migration pathways causing localized heat-flow perturbations and/or changes in the hydrate-forming gas composition both likely affecting the depth of the GHSZ. Our results provide the first evidence of the gas hydrate potential in the offshore Bangladesh and should drive future research and data acquisition aiming to understand the composition, saturation and thickness of the gas hydrate-bearing sediments in this region

Marine CSEM synthetic study to assess the detection of CO2 escape and saturation changes within a submarine chimney connected to a CO2 storage site.

Carbon capture and storage (CCS) within sealed geologic formations is an essential strategy to reduce global greenhouse gas emissions, the primary goal of the 2015 United Nations Paris Agreement. Large-scale commercial development of geological CO2 storage requires high-resolution remote sensing methods to monitor CO2 migration during/after injection. A geologic formation containing a CO2 phase in its pore space commonly exhibits higher electrical resistivity than brine-saturated (background) sediments. Here, we explore the added value of the marine controlled-source electromagnetic (CSEM) method as an additional and relevant geophysical tool to monitor moderate to significant changes in CO2 saturation within a fluid conduit breaking through the seal of a CCS injection reservoir, using a suite of synthetic studies. Our 2D CSEM synthetic models simulate various geologic scenarios incorporating the main structural features and stratigraphy of two North Sea sites, the Scanner Pockmark and the Sleipner CCS site. Our results show significant differentiation of leakage through the seal with CO2 saturation (SCO2 ⁠) ranging between 20 and 50 per cent, while our rock physics model predicts that detection below 20 per cent would be challenging for CSEM alone. However, we are able to detect with our 2D inversion models the effects of saturation with 10 and 20 per cent CO2 within a chimney with 10 per cent porosity. We demonstrate that simultaneous inversion of Ey and Ez synthetic electric field data facilitates a sharper delineation of a CO2 saturated chimney structure within the seal, whereas Ez synthetic data present higher sensitivity than Ey to SCO2 variation, demonstrating the importance of acquiring the whole 3D electric field. This study illustrates the value of incorporating CSEM into measurement, monitoring, and verification (MMV) strategies for operating marine CCS sites optimally