Crustal fingering facilitates free-gas methane migration through the hydrate stability zone.

Widespread seafloor methane venting has been reported in many regions of the world oceans in the past decade. Identifying and quantifying where and how much methane is being released into the ocean remains a major challenge and a critical gap in assessing the global carbon budget and predicting future climate [C. Ruppel, J. D. Kessler. Rev. Geophys. 55, 126-168 (2017)]. Methane hydrate ([Formula: see text]) is an ice-like solid that forms from methane-water mixture under elevated-pressure and low-temperature conditions typical of the deep marine settings (>600-m depth), often referred to as the hydrate stability zone (HSZ). Wide-ranging field evidence indicates that methane seepage often coexists with hydrate-bearing sediments within the HSZ, suggesting that hydrate formation may play an important role during the gas-migration process. At a depth that is too shallow for hydrate formation, existing theories suggest that gas migration occurs via capillary invasion and/or initiation and propagation of fractures (Fig. 1). Within the HSZ, however, a theoretical mechanism that addresses the way in which hydrate formation participates in the gas-percolation process is missing. Here, we study, experimentally and computationally, the mechanics of gas percolation under hydrate-forming conditions. We uncover a phenomenon-crustal fingering-and demonstrate how it may control methane-gas migration in ocean sediments within the HSZ.

Wellbore Cement Porosity Evolution in Response to Mineral Alteration during CO2 Flooding.

Mineral reactions during CO2 sequestration will change the pore-size distribution and pore surface characteristics, complicating permeability and storage security predictions. In this paper, we report a small/wide angle scattering study of wellbore cement that has been exposed to carbon dioxide for three decades. We have constructed detailed contour maps that describe local porosity distributions and the mineralogy of the sample and relate these quantities to the carbon dioxide reaction front on the cement. We find that the initial bimodal distribution of pores in the cement, 1-2 and 10-20 nm, is affected differently during the course of carbonation reactions. Initial dissolution of cement phases occurs in the 10-20 nm pores and leads to the development of new pore spaces that are eventually sealed by CaCO3 precipitation, leading to a loss of gel and capillary nanopores, smoother pore surfaces, and reduced porosity. This suggests that during extensive carbonation of wellbore cement, the cement becomes less permeable because of carbonate mineral precipitation within the pore space. Additionally, the loss of gel and capillary nanoporosities will reduce the reactivity of cement with CO2 due to reactive surface area loss. This work demonstrates the importance of understanding not only changes in total porosity but also how the distribution of porosity evolves with reaction that affects permeability.

Pre-site characterization risk analysis for commercial-scale carbon sequestration.

This study develops a probability framework to evaluate subsurface risks associated with commercial-scale carbon sequestration in the Kevin Dome, Montana. Limited knowledge of the spatial distribution of physical attributes of the storage reservoir and the confining rocks in the area requires using regional data to estimate project risks during the pre-site characterization analysis. A set of integrated Monte Carlo simulations are used to assess four risk proxies: the CO2 injectivity, area of review (AoR), migration rate into confining rocks, and a monitoring strategy prior to detailed site characterization. Results show a reasonable likelihood of reaching the project goal of injecting 1 Mt in 4 years with a single injection well (>58%), increasing to >70% if the project is allowed to run for 5 years. The mean radius of the AoR, based on a 0.1 MPa pressure change, is around 4.8 km. No leakage of CO2 through the confining units is seen in any simulations. The computed CO2 detection probability suggests that the monitoring wells should be located at less than 1.2 km away from the injection well so that CO2 is likely to be detected within the time frame of the project. The scientific results of this study will be used to inform the detailed site characterization process and to provide more insight for understanding operational and technical risks before injecting CO2.

Experimental evaluation of wellbore integrity along the cement-rock boundary.

Leakage of CO(2) and brine from geologic storage reservoirs along wellbores is a major risk factor to the success of geologic carbon sequestration. We conducted multiphase [supercritical (sc)CO(2)-brine] coreflood experiments that simulate a leakage pathway along the cement/rock interface. A composite core constructed of oil-well cement and siltstone separated by a simulated damage zone (defect) containing ground cement and siltstone was flooded with brine + scCO(2) at 10 MPa and 60 °C parallel to the defect. During coinjection of scCO(2), the effective brine permeability decreased from ~200 to 90 mD due to transition to two-phase flow and then further declined to 35 mD. CO(2) injection resulted in a pH drop from 11 to 4 and carbonate-undersaturated conditions in the produced brine. Microscopy revealed leaching and erosion along the defect, a carbonation front extending 5 mm into the cement, parallel to the damage zone, and no change in the dimensions of the defect. Carbonation of cement does not appear to explain the permeability drop, which is attributed to the migration and reprecipitation of alteration products derived from cement within the defect. This study shows the potential for self-limiting flow along wellbore defects despite flow of aggressive scCO(2)-brine mixtures.

A machine learning framework for rapid forecasting and history matching in unconventional reservoirs.

We present a novel workflow for forecasting production in unconventional reservoirs using reduced-order models and machine-learning. Our physics-informed machine-learning workflow addresses the challenges to real-time reservoir management in unconventionals, namely the lack of data (i.e., the time-frame for which the wells have been producing), and the significant computational expense of high-fidelity modeling. We do this by applying the machine-learning paradigm of transfer learning, where we combine fast, but less accurate reduced-order models with slow, but accurate high-fidelity models. We use the Patzek model (Proc Natl Acad Sci 11:19731-19736, https://doi.org/10.1073/pnas.1313380110 , 2013) as the reduced-order model to generate synthetic production data and supplement this data with synthetic production data obtained from high-fidelity discrete fracture network simulations of the site of interest. Our results demonstrate that training with low-fidelity models is not sufficient for accurate forecasting, but transfer learning is able to augment the knowledge and perform well once trained with the small set of results from the high-fidelity model. Such a physics-informed machine-learning (PIML) workflow, grounded in physics, is a viable candidate for real-time history matching and production forecasting in a fractured shale gas reservoir.

Magnesium sulphate salts and the history of water on Mars.

Recent reports of approximately 30 wt% of sulphate within saline sediments on Mars--probably occurring in hydrated form--suggest a role for sulphates in accounting for equatorial H2O observed in a global survey by the Odyssey spacecraft. Among salt hydrates likely to be present, those of the MgSO4*nH2O series have many hydration states. Here we report the exposure of several of these phases to varied temperature, pressure and humidity to constrain their possible H2O contents under martian surface conditions. We found that crystalline structure and H2O content are dependent on temperature-pressure history, that an amorphous hydrated phase with slow dehydration kinetics forms at <1% relative humidity, and that equilibrium calculations may not reflect the true H2O-bearing potential of martian soils. Mg sulphate salts can retain sufficient H2O to explain a portion of the Odyssey observations. Because phases in the MgSO4*nH2O system are sensitive to temperature and humidity, they can reveal much about the history of water on Mars. However, their ease of transformation implies that salt hydrates collected on Mars will not be returned to Earth unmodified, and that accurate in situ analysis is imperative.

3D particle transport in multichannel microfluidic networks with rough surfaces.

The transport of particles and fluids through multichannel microfluidic networks is influenced by details of the channels. Because channels have micro-scale textures and macro-scale geometries, this transport can differ from the case of ideally smooth channels. Surfaces of real channels have irregular boundary conditions to which streamlines adapt and with which particle interact. In low-Reynolds number flows, particles may experience inertial forces that result in trans-streamline movement and the reorganization of particle distributions. Such transport is intrinsically 3D and an accurate measurement must capture movement in all directions. To measure the effects of non-ideal surface textures on particle transport through complex networks, we developed an extended field-of-view 3D macroscope for high-resolution tracking across large volumes ([Formula: see text]) and investigated a model multichannel microfluidic network. A topographical profile of the microfluidic surfaces provided lattice Boltzmann simulations with a detailed feature map to precisely reconstruct the experimental environment. Particle distributions from simulations closely reproduced those observed experimentally and both measurements were sensitive to the effects of surface roughness. Under the conditions studied, inertial focusing organized large particles into an annular distribution that limited their transport throughout the network while small particles were transported uniformly to all regions.

Geo-material microfluidics at reservoir conditions for subsurface energy resource applications.

Microfluidic investigations of flow and transport in porous and fractured media have the potential to play a significant role in the development of future subsurface energy resource technologies. However, the majority of experimental systems to date are limited in applicability due to operating conditions and/or the use of engineered material micromodels. We have developed a high pressure and temperature microfluidic experimental system that allows for direct observations of flow and transport within geo-material micromodels (e.g. rock, cement) at reservoir conditions. In this manuscript, we describe the experimental system, including our novel micromodel fabrication method that works in both geo- and engineered materials and utilizes 3-D tomography images of real fractures as micromodel templates to better represent the pore space and fracture geometries expected in subsurface formations. We present experimental results that highlight the advantages of using real-rock micromodels and discuss potential areas of research that could benefit from geo-material microfluidic investigations. The experiments include fracture-matrix interaction in which water imbibes into the shale rock matrix from etched fractures, supercritical CO2 (scCO2) displacing brine in idealized and realistic fracture patterns, and three-phase flow involving scCO2-brine-oil.

Development of a hybrid process and system model for the assessment of wellbore leakage at a geologic CO2 sequestration site.

Sequestration of CO2 in geologic reservoirs is one of the promising technologies currently being explored to mitigate anthropogenic CO2 emissions. Large-scale deployment of geologic sequestration will require seals with a cumulative area amounting to hundreds of square kilometers per year and will require a large number of sequestration sites. We are developing a system-level model, CO2-PENS, that will predict the overall performance of sequestration systems while taking into account various processes associated with different parts of a sequestration operation, from the power plant to sequestration reservoirs to the accessible environment. The adaptability of CO2-PENS promotes application to a wide variety of sites, and its level of complexity can be increased as detailed site information becomes available. The model CO2-PENS utilizes a science-based-prediction approach by integrating information from process-level laboratory experiments, field experiments/observations, and process-level numerical modeling. The use of coupled process models in the system model of CO2-PENS provides insights into the emergent behavior of aggregate processes that could not be obtained by using individual process models. We illustrate the utility of the concept by incorporating geologic and wellbore data into a synthetic, depleted oil reservoir. In this sequestration scenario, we assess the fate of CO2 via wellbore release and resulting impacts of CO2 to a shallow aquifer and release to the atmosphere.