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Martin J. Blunt - One of the best experts on this subject based on the ideXlab platform.

  • Pore-Scale Imaging and Analysis of Wettability Order, Trapping and Displacement in Three-Phase Flow in Porous Media with Various Wettabilities
    Transport in Porous Media, 2021
    Co-Authors: Abdulla Alhosani, Branko Bijeljic, Martin J. Blunt
    Abstract:

    Three-phase flow in porous media is encountered in many applications including subsurface Carbon Dioxide Storage, enhanced oil recovery, groundwater remediation and the design of microfluidic devices. However, the pore-scale physics that controls three-phase flow under capillary dominated conditions is still not fully understood. Recent advances in three-dimensional pore-scale imaging have provided new insights into three-phase flow. Based on these findings, this paper describes the key pore-scale processes that control flow and trapping in a three-phase system, namely wettability order, spreading and wetting layers, and double/multiple displacement events. We show that in a porous medium containing water, oil and gas, the behaviour is controlled by wettability, which can either be water-wet, weakly oil-wet or strongly oil-wet, and by gas–oil miscibility. We provide evidence that, for the same wettability state, the three-phase pore-scale events are different under near-miscible conditions—where the gas–oil interfacial tension is ≤ 1 mN/m—compared to immiscible conditions. In a water-wet system, at immiscible conditions, water is the most-wetting phase residing in the corners of the pore space, gas is the most non-wetting phase occupying the centres, while oil is the intermediate-wet phase spreading in layers sandwiched between water and gas. This fluid configuration allows for double capillary trapping, which can result in more gas trapping than for two-phase flow. At near-miscible conditions, oil and gas appear to become neutrally wetting to each other, preventing oil from spreading in layers; instead, gas and oil compete to occupy the centre of the larger pores, while water remains connected in wetting layers in the corners. This allows for the rapid production of oil since it is no longer confined to movement in thin layers. In a weakly oil-wet system, at immiscible conditions, the wettability order is oil–water–gas, from most to least wetting, promoting capillary trapping of gas in the pore centres by oil and water during water-alternating-gas injection. This wettability order is altered under near-miscible conditions as gas becomes the intermediate-wet phase, spreading in layers between water in the centres and oil in the corners. This fluid configuration allows for a high oil recovery factor while restricting gas flow in the reservoir. Moreover, we show evidence of the predicted, but hitherto not reported, wettability order in strongly oil-wet systems at immiscible conditions, oil–gas–water, from most to least wetting. At these conditions, gas progresses through the pore space in disconnected clusters by double and multiple displacements; therefore, the injection of large amounts of water to disconnect the gas phase is unnecessary. We place the analysis in a practical context by discussing implications for Carbon Dioxide Storage combined with enhanced oil recovery before suggesting topics for future work.

  • pore scale characterization of Carbon Dioxide Storage at immiscible and near miscible conditions in altered wettability reservoir rocks
    International Journal of Greenhouse Gas Control, 2021
    Co-Authors: Abdulla Alhosani, Branko Bijeljic, Qingyang Lin, Alessio Scanziani, Edward Andrews, Kaiqiang Zhang, Martin J. Blunt
    Abstract:

    Abstract Carbon Dioxide Storage combined with enhanced oil recovery (CCS-EOR) is an important approach for reducing greenhouse gas emissions. We use pore-scale imaging to help understand CO2 Storage and oil recovery during CCS-EOR at immiscible and near-miscible CO2 injection conditions. We study in situ immiscible CO2 flooding in an oil-wet reservoir rock at elevated temperature and pressure using X-ray micro-tomography. We observe the predicted, but hitherto unreported, three-phase wettability order in strongly oil-wet rocks, where water occupies the largest pores, oil the smallest, while CO2 occupies pores of intermediate size. We investigate the pore occupancy, existence of CO2 layers, recovery and CO2 trapping in the oil-wet rock at immiscible conditions and compare to the results obtained on the same rock type under slightly more weakly oil-wet near-miscible conditions, with the same wettability order. CO2 spreads in connected layers at near-miscible conditions, while it exists as disconnected ganglia in medium-sized pores at immiscible conditions. Hence, capillary trapping of CO2 by oil occurs at immiscible but not at near-miscible conditions. Moreover, capillary trapping of CO2 by water is not possible in both cases since CO2 is more wetting to the rock than water. The oil recovery by CO2 injection alone is reduced at immiscible conditions compared to near-miscible conditions, where low gas-oil capillary pressure improves microscopic displacement efficiency. Based on these results, to maximize the amount of oil recovered and CO2 stored at immiscible conditions, a water-alternating-gas injection strategy is suggested, while a strategy of continuous CO2 injection is recommended at near-miscible conditions.

  • design of foam assisted Carbon Dioxide Storage in a north sea aquifer using streamline based simulation
    International Journal of Greenhouse Gas Control, 2015
    Co-Authors: Siriwat Vitoonkijvanich, Abdulkareem M Alsofi, Martin J. Blunt
    Abstract:

    Abstract Carbon capture and Storage (CCS) – the collection of CO2 from industrial sources and its injection underground – could potentially contribute to the reduction of atmospheric emissions of greenhouse gases. In this paper, we investigate the sequestration of CO2 in aquifers with the co-injection of surfactants for foam generation. This is equivalent to the use of foam for conformance control in enhanced oil recovery applications. To study foam-assisted sequestration, we extend an in-house streamline-based simulator to model foam flow. We use two foam models that have been previously suggested in the literature. In both models foam hinders gas mobility through increasing its apparent viscosity. The modified simulator is validated by comparison to analytical solutions. We then investigate the performance of CO2 sequestration with the co-injection of surfactants. We look at CO2 sequestration in a North Sea aquifer. We study both simultaneous and alternating surfactant-gas injection at different fractional flows (i.e. water:gas ratios). For cases where a seal provides a reliable trapping mechanism, the simulation results suggest that the use of surfactants to generate foam significantly improves the Storage efficiency at a marginal increase in water consumption. In this setting, CO2/surfactant simultaneous injection at a 0.5 CO2 fractional flow was found to be the optimum injection strategy for the case investigated. To the contrary, if the seal is unreliable or not present at the first place, CO2/brine simultaneous injection at a 0.85 CO2 fractional flow was found to be the optimum injection strategy. Although foam-assisted sequestration in this case further improves the Storage efficiency, it does that at a significant increase in water consumption. This is since, although foam generation improves the sweep during the sequestration phase, it significantly hinders the sweep during the chase-brine injection phase. Based on that, having a design where the surfactant will degrade just before or during the chase-brine injection phase would provide the optimum sequestration strategy—without reliance on the presence or integrity of the seal.

  • pore scale imaging of trapped supercritical Carbon Dioxide in sandstones and Carbonates
    International Journal of Greenhouse Gas Control, 2014
    Co-Authors: Matthew Andrew, Branko Bijeljic, Martin J. Blunt
    Abstract:

    Abstract Geological Carbon Dioxide Storage must be designed such that the CO 2 cannot escape from the rock formation into which it is injected, and often simple stratigraphic trapping is insufficient. CO 2 can be trapped in the pore space as droplets surrounded by water through capillary trapping. X-ray microtomography was used to image, at a resolution of 6.6 μm, the pore-scale arrangement of these droplets in three Carbonates and two sandstones. The pressures and temperatures in the pore space were representative of typical Storage formations, while chemical equilibrium was maintained between the CO 2 , brine and rock phases to replicate conditions far away from the injection site. In each sample substantial amounts of CO 2 were trapped, with the efficiency of trapping being insensitive to pore-morphology and chemistry. Apart from in one extremely well connected sample, the size distribution of residual ganglia larger than 10 5  voxel 3 obey power law distributions with exponents broadly consistent with percolation theory over two orders of magnitude. This work shows that residual trapping can be used to locally immobilise CO 2 in a wide range of rock types.

  • pore scale imaging and modelling
    Advances in Water Resources, 2013
    Co-Authors: Martin J. Blunt, Branko Bijeljic, Hu Dong, Oussama Gharbi, Peyman Mostaghimi, Adriana Paluszny, Stefan Iglauer, Christopher H. Pentland
    Abstract:

    Abstract Pore-scale imaging and modelling – digital core analysis – is becoming a routine service in the oil and gas industry, and has potential applications in contaminant transport and Carbon Dioxide Storage. This paper briefly describes the underlying technology, namely imaging of the pore space of rocks from the nanometre scale upwards, coupled with a suite of different numerical techniques for simulating single and multiphase flow and transport through these images. Three example applications are then described, illustrating the range of scientific problems that can be tackled: dispersion in different rock samples that predicts the anomalous transport behaviour characteristic of highly heterogeneous Carbonates; imaging of super-critical Carbon Dioxide in sandstone to demonstrate the possibility of capillary trapping in geological Carbon Storage; and the computation of relative permeability for mixed-wet Carbonates and implications for oilfield waterflood recovery. The paper concludes by discussing limitations and challenges, including finding representative samples, imaging and simulating flow and transport in pore spaces over many orders of magnitude in size, the determination of wettability, and upscaling to the field scale. We conclude that pore-scale modelling is likely to become more widely applied in the oil industry including assessment of unconventional oil and gas resources. It has the potential to transform our understanding of multiphase flow processes, facilitating more efficient oil and gas recovery, effective contaminant removal and safe Carbon Dioxide Storage.

Bernhard M. Krooss - One of the best experts on this subject based on the ideXlab platform.

  • high pressure methane and Carbon Dioxide sorption on coal and shale samples from the parana basin brazil
    International Journal of Coal Geology, 2010
    Co-Authors: Philipp Weniger, Andreas Busch, W Kalkreuth, Bernhard M. Krooss
    Abstract:

    Abstract An experimental study has been conducted to assess the potential for coalbed methane production and Carbon Dioxide Storage in coals, Carbonaceous shales and source rocks in the Parana Basin in Brazil. High-pressure sorption tests with methane and Carbon Dioxide were performed on coal and Carbonaceous shales from the Santa Terezinha Coalfield and samples from two principal petroleum source rocks. Measured excess sorption capacities ranged from 0.03 to 0.47 mmol/g for methane and 0.14 to 0.81 mmol/g for Carbon Dioxide, showing a decrease with decreasing organic matter content. Linear regression lines for methane sorption capacity vs. TOC extrapolated to approximately zero, whereas for Carbon Dioxide the intercept of the regression line indicated a residual sorption capacity of ~ 0.2 mmol/g on the mineral matter. Present-day gas contents of coals collected from the first CBM well in the Santa Terezinha Coalfield correspond to 13–38% of the measured maximum sorption capacities. Carbon Dioxide sorption capacities exceed methane sorption capacities by a factor of 1.9 to 6.9 for these coals. Free sorption capacities of the under-saturated coals in combination with preferential sorption of Carbon Dioxide could favour CO 2 -enhanced methane recovery and CO 2 Storage in coals and shales of the study area. Based upon the calculated coal reserves, gas contents and measured sorption capacities, a total Storage potential of 15.4 Gt CO 2 was estimated for an area of 20 × 40 km 2 in the Santa Terezinha coal field, assuming a combined CO 2 enhanced coalbed methane (ECBM) production and CO 2 Storage operation. To fully evaluate the potential for Carbon Dioxide Storage and coalbed methane production, further studies are required to assess producibility of methane and efficiency of long-term CO 2 Storage in the study area.

  • Carbon Dioxide Storage potential of shales
    International Journal of Greenhouse Gas Control, 2008
    Co-Authors: Andreas Busch, Sascha Alles, Yves Gensterblum, Dirk Prinz, David N. Dewhurst, Mark D. Raven, Helge Stanjek, Bernhard M. Krooss
    Abstract:

    Abstract Options for the geologic Storage of Carbon Dioxide vary from saline aquifers and depleted oil and gas reservoirs to unminable coal seams and abandoned coal mines. Important aspects include the sealing integrity of the cap rock and potential changes in this integrity, owing to the interaction with CO2. In this study, diffusive transport and gas sorption experiments on one well characterised shale sample (Muderong Shale, Australia) and different clay minerals were performed to obtain information on the sealing integrity and the CO2 Storage potential of these materials. All measurements were performed under reservoir conditions relevant for CO2 Storage (T = 45–50 °C; p  Additionally, changes in specific surface areas before and after the sorption experiments and variations in the CO2 sorption and diffusion behaviour due to repetitive experiments on the identical sample were observed, possibly related to geochemical alteration of the Muderong Shale and the clay minerals. These could not be quantified however and seemed to occur only at high pressures. Results obtained in this study provide a more positive view on the sealing integrity of intact cap rock formations. Carbon Dioxide that migrates from a Storage reservoir into the cap rock through the pore network will be immobilised to a certain extent, hence minimising (slow, diffusion-driven) leakage and providing additional CO2 Storage potential.

Abdulkareem M Alsofi - One of the best experts on this subject based on the ideXlab platform.

  • design of foam assisted Carbon Dioxide Storage in a north sea aquifer using streamline based simulation
    International Journal of Greenhouse Gas Control, 2015
    Co-Authors: Siriwat Vitoonkijvanich, Abdulkareem M Alsofi, Martin J. Blunt
    Abstract:

    Abstract Carbon capture and Storage (CCS) – the collection of CO2 from industrial sources and its injection underground – could potentially contribute to the reduction of atmospheric emissions of greenhouse gases. In this paper, we investigate the sequestration of CO2 in aquifers with the co-injection of surfactants for foam generation. This is equivalent to the use of foam for conformance control in enhanced oil recovery applications. To study foam-assisted sequestration, we extend an in-house streamline-based simulator to model foam flow. We use two foam models that have been previously suggested in the literature. In both models foam hinders gas mobility through increasing its apparent viscosity. The modified simulator is validated by comparison to analytical solutions. We then investigate the performance of CO2 sequestration with the co-injection of surfactants. We look at CO2 sequestration in a North Sea aquifer. We study both simultaneous and alternating surfactant-gas injection at different fractional flows (i.e. water:gas ratios). For cases where a seal provides a reliable trapping mechanism, the simulation results suggest that the use of surfactants to generate foam significantly improves the Storage efficiency at a marginal increase in water consumption. In this setting, CO2/surfactant simultaneous injection at a 0.5 CO2 fractional flow was found to be the optimum injection strategy for the case investigated. To the contrary, if the seal is unreliable or not present at the first place, CO2/brine simultaneous injection at a 0.85 CO2 fractional flow was found to be the optimum injection strategy. Although foam-assisted sequestration in this case further improves the Storage efficiency, it does that at a significant increase in water consumption. This is since, although foam generation improves the sweep during the sequestration phase, it significantly hinders the sweep during the chase-brine injection phase. Based on that, having a design where the surfactant will degrade just before or during the chase-brine injection phase would provide the optimum sequestration strategy—without reliance on the presence or integrity of the seal.

Ali Morsali - One of the best experts on this subject based on the ideXlab platform.

  • flexible and breathing metal organic framework with high and selective Carbon Dioxide Storage versus nitrogen
    Polyhedron, 2019
    Co-Authors: Payam Abdolalian, Ali Morsali
    Abstract:

    Abstract A new functionalized metal–organic framework (MOF) {[Zn2(fum)2(4-bpdb)]·2H2O}n (TMU-42) fumarate (fum) and 1,4-bis(4-pyridyl)-3,4-diaza-1,3-butadiene (4-bpdb), synthesized and characterized by single-crystal X-ray diffraction, X-ray diffraction (XRD), etc. The breathing phenomenon and azine functional group introduced 2-fold interpenetrated TMU-42 as one of the highest CO2 Storage capacity and surface area in between pillared metal–organic frameworks. To reveal functionality effect on CO2 adsorption TMU-42 compared with previously reported non-functionalized MOF, {[Zn2(fum)2(dpe)]·DMF·(H2O)0.5}n (TMU-43) 2-di(4-pyridyl)ethylene (dpe).

Andrew R Millward - One of the best experts on this subject based on the ideXlab platform.