CO2 injection in hydrate-bearing sediments induces methane (CH4) production while benefitting from CO2 storage, as demonstrated in both core and field scale studies. CH4 hydrates have been formed repeatedly in partially water saturated Bentheim sandstones. Magnetic Resonance Imaging (MRI) and CH4 consumption from pump logs have been used to verify final CH4 hydrate saturation. Gas Chromatography (GC) in combination with a Mass Flow Meter was used to quantify CH4 recovery during CO2 injection. The overall aim has been to study the impact of CO2 in fractured and non-fractured samples to determine the performance of CO2-induced CH4 hydrate production. Previous efforts focused on diffusion-driven exchange from a fracture volume. This approach was limited by gas dilution, where free and produced CH4 reduced the CO2 concentration and subsequent driving force for both diffusion and exchange. This limitation was targeted by performing experiments where CO2 was injected continuously into the spacer volume to maintain a high driving force. To evaluate the effect of diffusion length multi-fractured core samples were used, which demonstrated that length was not the dominating effect on core scale. An additional set of experiments is presented on non-fractured samples, where diffusion-limited transportation was assisted by continuous CO2 injection and CH4 displacement. Loss of permeability was addressed through binary gas (N2/CO2) injection, which regained injectivity and sustained CO2-CH4 exchange. OPEN ACCESSEnergies 2015, 8 4074

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Here we show for the first time the combined positron emission tomography (PET) and computed tomography (CT) imaging of flow processes within porous rocks to quantify the development in local fluid saturations. The coupling between local rock structure and displacement fronts is demonstrated in exploratory experiments using this novel approach. We also compare quantification of 3‐D temporal and spatial water saturations in two similar CO2 storage tests in sandstone imaged separately with PET and CT. The applicability of each visualization technique is evaluated for a range of displacement processes, and the favorable implementation of combining PET/CT for laboratory core analysis is discussed. We learn that the signal‐to‐noise ratio (SNR) is over an order of magnitude higher for PET compared with CT for the studied processes.

Natural gas hydrate is a crystallized ice-like substance, consisting of water and natural gas, with methane as the most common gas. Water molecules form cages through hydrogen bonding and encapsulate gas molecules. Natural gas hydrates are found in the earth under high pressure and low temperature where water and gas co-exist, typically in permafrost and submarine environments. Hydrates have been considered a nuisance in the petroleum industry, creating barriers in pipe lines, and effort has mainly been put into preventing hydrate formation. However, natural gas hydrates are in recent decades acknowledged as a potential energy resource for the future; even conservative estimates suggest 10 15 m 3 CH 4 STP present within hydrate.Several methane production scenarios are proposed: thermal-, chemical-and pressure reduction induced dissociation is available, although depressurization is considered the least costly option. The University of Bergen has since 2002 worked on a fourth alternative: exchange of CH 4 molecules with CO 2 . Lab scale experiments have repeatedly shown CO 2 -CH 4 exchange within sediments. These experiments led to a field trial test in Alaska, operated by ConocoPhillips, by utilizing CO 2 injection as a production method. Similar procedures as in the field test were performed in the lab, creating repetitive data for analysis on lab scale. This paper reviews results from both the laboratory and field pilot and discusses challenges and mitigating measures related to production.

The flow of CO 2 in porous media is fundamental to many engineering applications and geophysical processes. Yet detailed CO 2 flow visualization remains challenging. We address this problem via positron emission tomography using 11 C nuclides and apply it to tight formations-a difficult but relevant rock type to investigate. The results represent an important technical advancement for visualization and quantification of flow properties in ultratight rocks and allowed us to observe that local rock structure in a layered, reservoir shale (K = 0.74 μdarcy) sample dictated the CO 2 flow path by the presence of high-density layers. Diffusive transport of CO 2 in a fractured sample (high-permeable sandstone) was also visualized, and an effective diffusion coefficient (D i = 2.2 • 10 À8 m 2 /s) was derived directly from the dynamic distribution of CO 2. During CO 2 injection tests for oil recovery from a reservoir shale sample we observed a recovery factor of R F = 55% of oil in place without fracturing the sample.