Publications
238 results found
Bian H, Ai L, Heng JYY, et al., 2023, Effects of chemical potential differences on methane hydrate formation kinetics, Chemical Engineering Journal, Vol: 452, Pages: 1-11, ISSN: 1385-8947
To underpin the increasing interest in practical applications of gas hydrates, for gas storage and separation for instance, the formation and growth of hydrates at liquid-gas interfaces are of fundamental importance. Although the thermodynamics of hydrate formation has been widely studied and is well understood, the kinetics of these processes is not well characterised. In this work, a high-pressure, low-temperature stirred reactor was used to conduct hydrate formation kinetic studies in a temperature range from 276.5 to 283.5 K and a pressure range from 5 to 10.5 MPa, with a special focus on 1) the impact of agitation conditions on the available water-gas interfacial surface area for mass transfer and growth rate during hydrate formation, and 2) the effect of the chemical potential driving force on the formation rate. Five hydrate growth regimes were identified, with varying degrees of gas mass transfer control across the gas-water interface depending on the extent to which hydrate layers built up at this interface, gas needed to move through solid hydrate layers, and the extent to which the gas was entrained within the water phase. The formation rate in the initial linear growth regime, before the onset of solid hydrate gas mass transfer effects, was found to depend in an essentially exponential manner on the chemical potential difference from the equilibrium state. Semi-empirical models related to Arrhenius-type kinetic models were used to correlate the data, the best of which reproduced the formation rates from the chemical potential differences to within ± 5 %. The approach has general applicability to help determine the balance between kinetic and thermodynamic factors in identifying the optimum pressure-temperature conditions for processes for gas storage, gas separation and other hydrate applications.
Ansari H, Gong S, Trusler J, et al., 2022, Hybrid pore-scale adsorption model for CO2 and CH4 storage in shale, Energy and Fuels, Vol: 36, ISSN: 0887-0624
Making reliable estimates of gas adsorption in shale remains a challenge becausethe variability in their mineralogy and thermal maturity results in a broad distributionof pore-scale properties, including size, morphology and surface chemistry. Here, wedemonstrate the development and application of a hybrid pore-scale model that usessurrogate surfaces to describe supercritical gas adsorption in shale. The model is basedon the lattice Density Functional Theory (DFT) and considers both slits and cylindrical pores to mimic the texture of shale. Inorganic and organic surfaces associatedwith these pores are accounted for by using two distinct adsorbate-adsorbent interaction energies. The model is parameterised upon calibration against experimentaladsorption data acquired on adsorbents featuring either pure clay or pure carbon surfaces. Therefore, in its application to shale, the hybrid lattice DFT model only requiresknowledge of the shale-specific organic and clay content. We verify the reliability ofthe model predictions by comparison against high-pressure CO2 and CH4 adsorptionisotherms measured at 40 ◦C in the pressure range 0.01–30 MPa on four samples fromthree distinct plays, namely the Bowland (UK), Longmaxi (China) and Marcellus shale1(USA). Because it uses only the relevant pore-scale properties, the proposed model canbe applied to the analysis of other shales, minimising the heavy experimental burdenassociated with high pressure experiments. Moreover, the proposed development hasgeneral applicability meaning that the hybrid lattice DFT can be used to the characterisation of any adsorbent featuring morphologically and chemically heterogeneoussurfaces.
Ansari H, Rietmann E, Joss L, et al., 2021, A shortcut pressure swing adsorption analogue model to estimate gas-in-place and CO2 storage potential of gas shales, Fuel: the science and technology of fuel and energy, Vol: 301, Pages: 1-13, ISSN: 0016-2361
Natural gas extraction from shale formations has experienced a rapid growth in recent years, but the low recovery observed in many field operations demonstrates that the development of this energy resource is far from being optimal. The ambiguity in procedures that account for gas adsorption in Gas-in-Place calculations represents an important element of uncertainty. Here, we present a methodology to compute gas production curves based on quantities that are directly accessed experimentally, so as to correctly account for the usable pore-space in shale. We observe that adsorption does not necessarily sustain a larger gas production compared to a non-adsorbing reservoir with the same porosity. By analysing the entire production curve, from initial to abandonment pressure, we unravel the role of the excess adsorption isotherm in driving this behaviour. To evaluate scenarios of improved recovery by means of gas injection, we develop a proxy reservoir model that exploits the concept of Pressure Swing Adsorption used in industrial gas separation operations. The model has three stages (Injection/Soak/Production) and is used to compare scenarios with cyclic injection of CO2 or N2. The results show that partial pressure and competitive adsorption enhance gas production in complementary ways, and reveal the important trade-off between CH4 recovery and CO2 storage. In this context, this proxy model represents a useful to tool to explore strategies that optimise these quantities without compromising the purity of the produced stream, as the latter may introduce a heavy economic burden on the operation.
Bian H, Ai L, Hellgardt K, et al., 2021, Phase behaviour of methane hydrates in confined media, Crystals, Vol: 11, Pages: 1-16, ISSN: 2073-4352
In a study designed to investigate the melting behaviour of natural gas hydrates which are usually formed in porous mineral sediments rather than in bulk, hydrate phase equilibria for binary methane and water mixtures were studied using high-pressure differential scanning calorimetry in mesoporous and macroporous silica particles having controlled pore sizes ranging from 8.5 nm to 195.7 nm. A dynamic oscillating temperature method was used to form methane hydrates reproducibly and then determine their decomposition behaviour—melting points and enthalpies of melting. Significant decreases in dissociation temperature were observed as the pore size decreased (over 6 K for 8.5 nm pores). This behaviour is consistent with the Gibbs–Thomson equation, which was used to determine hydrate–water interfacial energies. The melting data up to 50 MPa indicated a strong, essentially logarithmic, dependence on pressure, which here has been ascribed to the pressure dependence of the interfacial energy in the confined media. An empirical modification of the Gibbs–Thomson equation is proposed to include this effect.
Ansari H, Joss L, Hwang J, et al., 2020, Supercritical adsorption in micro- and meso-porous carbons and its utilisation for textural characterisation, Microporous and Mesoporous Materials, Vol: 308, ISSN: 1387-1811
Understanding supercritical gas adsorption in porous carbons requires consistency between experimental measurements at representative conditions and theoretical adsorption models that correctly account for the solid’s textural properties. We have measured unary CO2 and CH4 adsorption isotherms on a commercial mesoporous carbon up to 25 MPa at 40 °C, 60 °C and 80 °C. The experimental data are successfully described using a model based on the lattice Density Functional Theory (DFT) that has been newly developed for cylindrical pores and used alongside Ar (87K) physisorption to extract the representative pore sizes of the adsorbent. The agreement between model and experiments also includes important thermodynamic parameters, such as Henry constants and the isosteric heat of adsorption. The general applicability of our integrated workflow is validated by extending the analysis to a comprehensive literature data set on a microporous activated carbon. This comparison reveals the distinct pore-filling behaviour in micro- and mesopores at supercritical conditions, and highlights the limitations associated with using slit-pore models for the characterisation of porous carbons with significant amounts of mesoporosity. The lattice DFT represents a departure from simple adsorption models, such as the Langmuir equation, which cannot capture pore size dependent adsorption behaviour, and a practical alternative to molecular simulations, which are computationally expensive to implement.
Yao JG, Boot-Handford ME, Zhang Z, et al., 2020, Pressurized In Situ CO2 Capture from Biomass Combustion via the Calcium Looping Process in a Spout-Fluidized-Bed Reactor, INDUSTRIAL & ENGINEERING CHEMISTRY RESEARCH, Vol: 59, Pages: 8571-8580, ISSN: 0888-5885
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Rucker M, Bartels W-B, Garfi G, et al., 2020, Relationship between wetting and capillary pressure in a crude oil/brine/rock system: From nano-scale to core-scale, Journal of Colloid and Interface Science, Vol: 562, Pages: 159-169, ISSN: 0021-9797
HypothesisThe wetting behaviour is a key property of a porous medium that controls hydraulic conductivity in multiphase flow. While many porous materials, such as hydrocarbon reservoir rocks, are initially wetted by the aqueous phase, surface active components within the non-wetting phase can alter the wetting state of the solid. Close to the saturation endpoints wetting phase fluid films of nanometre thickness impact the wetting alteration process. The properties of these films depend on the chemical characteristics of the system. Here we demonstrate that surface texture can be equally important and introduce a novel workflow to characterize the wetting state of a porous medium.ExperimentsWe investigated the formation of fluid films along a rock surface imaged with atomic force microscopy using ζ-potential measurements and a computational model for drainage. The results were compared to spontaneous imbibition test to link sub-pore-scale and core-scale wetting characteristics of the rock.FindingsThe results show a dependency between surface coverage by oil, which controls the wetting alteration, and the macroscopic wetting response. The surface-area coverage is dependent on the capillary pressure applied during primary drainage. Close to the saturation endpoint, where the change in saturation was minor, the oil-solid contact changed more than 80%.
Chow YTF, Maitland GC, Trusler JPM, 2020, Erratum to “Interfacial tensions of (H2O + H2) and (H2O + CO2 + H2) systems at temperatures of (298 to 448) K and pressures up to 45 MPa” [Fluid Phase Equil. 475 (2018) 37–44], Fluid Phase Equilibria, Vol: 503, ISSN: 0378-3812
Alderman NJ, Gavignet A, Guillot D, et al., 2020, High-temperature, high-pressure rheology of water-based muds.
This paper reports measurements of the rheology of a range of water based drilling muds at temperatures up to 130DEGREESC and pressures up to 1000 bar. The fluids were highly thixotropic, and decoupling of temperature/pressure effects from those due to time dependent structural changes was achieved by developing a sample preparation and handling procedure which ensured that all samples experienced identical shear histories prior to study in the rheometer. The observed behaviour of the fluids and its physical origins are discussed. A simple model allowing reliable extrapolation of surface measurements to downhole conditions for well circulated water based muds is presented.
Calabrese C, McBride-Wright M, Maitland GC, et al., 2019, Extension of vibrating-wire viscometry to electrically conducting fluids and measurements of viscosity and density of brines with dissolved CO2 at reservoir conditions, Journal of Chemical and Engineering Data, Vol: 64, Pages: 3831-3847, ISSN: 0021-9568
In order to design safe and effective storage of anthropological CO2 in deep saline aquifers, it is necessary to know the thermophysical properties of brine–CO2 solutions. In particular, density and viscosity are important in controlling convective flows of the CO2-rich brine. In this work, we have studied the effect of dissolved CO2 on the density and viscosity of NaCl and CaCl2 brines over a wide range of temperatures from 298 to 449 K, with pressures up to 100 MPa, and salinities up to 1 mol·kg–1. Additional density measurements were also made for both NaCl and CaCl2 brines with dissolved CO2 at salt molalities of 2.5 mol·kg–1 in the same temperature and pressure ranges. The viscosity was measured by means of a vibrating-wire viscometer, while the density was measured with a vibrating U-tube densimeter. To facilitate the present study, the theory of the vibrating-wire viscometer has been extended to account for the electrical conductivity of the fluid, thereby expanding the use of this technique to a whole new class of conductive fluids. Relative uncertainties were 0.07% for density and 3% for viscosity at 95% confidence. The results of the measurements show that both density and viscosity increase as a result of CO2 dissolution, confirming the expectation that CO2-rich brine solutions will sink in an aquifer. We also find that the effect of dissolved CO2 on both properties is sensibly independent of salt type and molality.
Al Ghafri S, Maitland GC, Trusler JPM, 2019, Densities of aqueous MgCl2(aq), CaCl2(aq), KI(aq), NaCl(aq), KCl(aq), AICl(3) (aq), and (0.964 NaCl + 0.136 KCI)(aq) at temperatures between (283 and 472) K, pressures up to 68.5 MPa, and molalities up to 6 mol.kg(-1) (vol 57, pg 1288, 2012), Journal of Chemical and Engineering Data, Vol: 64, Pages: 2912-2912, ISSN: 0021-9568
Chow YTF, Maitland GC, Trusler JPM, 2018, Interfacial tensions of (H2O + H-2) and (H2O + CO2 + H-2) systems at temperatures of (298-448) K and pressures up to 45 MPa, Fluid Phase Equilibria, Vol: 475, Pages: 37-44, ISSN: 0378-3812
We report new interfacial tension (IFT) measurements of the (H2O + CO2 + H2) and (H2O + H2) systems at pressures of (0.5 to 45) MPa, and temperatures of (298.15 to 448.15) K, measured by the pendant-drop method. The expanded uncertainties at 95% confidence are 0.05 K for temperature, 70 kPa for pressure, 0.017·γ for IFT in the both the binary (H2O + H2) system and the ternary (CO2 + H2 + H2O) system. Generally, the IFT was found to decrease with both increasing pressure and increasing temperature. However, for (H2O + H2) at the lowest two temperatures investigated, the isothermal IFT data were found to exhibit a maximum as a function of pressure at low pressures before declining with increasing pressure. An empirical correlation has been developed for the IFT of the (H2O + H2) system in the full range of conditions investigated, with an average absolute deviation of 0.16 mN m−1, and this is used to facilitate a comparison with literature values. Estimates of the IFT of the (H2O + CO2 + H2) ternary system, by an empirical combining rule based on the coexisting phase compositions and the interfacial tensions of the binary systems, were found to be unsuitable at low temperatures, with an average absolute deviation of 3.6 mN m−1 over all the conditions investigated.
Chow YTF, Maitland GC, Stevar MSP, et al., 2018, Correction to "Interfacial Tension of (Brines + CO2): (0.864 NaCl + 0.136 KCl) at Temperatures between (298 and 448) K, Pressures between (2 and 50) MPa, and Total Molalities of (1 to 5) mol.kg(-1)", Journal of Chemical and Engineering Data, Vol: 63, Pages: 2333-2334, ISSN: 0021-9568
Li et al.(1) reported interfacial tension measurements between carbon dioxide and the mixed brine (0.864 NaCl + 0.136 KCl) over wide ranges of temperature, pressure and total salt molality. We have determined that their data on the isotherm at 298.15 K for the salt molaity of 0.98 mol·kg–1 are erroneous; results at other temperatures and salt molalities reported in(1) are not affected by the error. We report herein new data, measured at T = 298.15 K and at pressures between (2 and 51) MPa, to replace the corresponding isotherm reported in Table 2 of the original reference.
Bui M, Adjiman CS, Bardow A, et al., 2018, Carbon capture and storage (CCS): the way forward, Energy and Environmental Science, Vol: 11, Pages: 1062-1176, ISSN: 1754-5692
Carbon capture and storage (CCS) is broadly recognised as having the potential to play a key role in meeting climate change targets, delivering low carbon heat and power, decarbonising industry and, more recently, its ability to facilitate the net removal of CO2 from the atmosphere. However, despite this broad consensus and its technical maturity, CCS has not yet been deployed on a scale commensurate with the ambitions articulated a decade ago. Thus, in this paper we review the current state-of-the-art of CO2 capture, transport, utilisation and storage from a multi-scale perspective, moving from the global to molecular scales. In light of the COP21 commitments to limit warming to less than 2 °C, we extend the remit of this study to include the key negative emissions technologies (NETs) of bioenergy with CCS (BECCS), and direct air capture (DAC). Cognisant of the non-technical barriers to deploying CCS, we reflect on recent experience from the UK's CCS commercialisation programme and consider the commercial and political barriers to the large-scale deployment of CCS. In all areas, we focus on identifying and clearly articulating the key research challenges that could usefully be addressed in the coming decade.
Li X, Peng C, Crawshaw JP, et al., 2017, The pH of CO<inf>2</inf>-saturated aqueous NaCl and NaHCO<inf>3</inf>solutions at temperatures between 308 K and 373 K at pressures up to 15 MPa, Fluid Phase Equilibria, Vol: 458, Pages: 253-263, ISSN: 0378-3812
The pH is a critical variable for carbon storage in saline aquifers because it affects the reaction rate and equilibrium state of the reservoir rocks, thus influencing the rates of mineral dissolution or precipitation and the integrity of caprocks. In this work, high-pressure pH and Ag/AgCl-reference electrodes were used to measure the pH of CO 2 -saturated aqueous solutions of NaCl and NaHCO 3 . The expanded uncertainty of the pH measurements is 0.20 at 95% probability. For CO 2 -saturated NaCl(aq), measurements were carried out at total pressures from (0.37 to 15.3) MPa and temperatures from (308 to 373) K with NaCl molalities of (1, 3 and 5) mol·kg −1 . For CO 2 -saturated NaHCO 3 (aq), the pH was measured at total pressures from (0.2 to 15.3) MPa and temperatures from (308 to 353) K with NaHCO 3 molalities of (0.01, 0.1 and 1) mol·kg −1 . The pH was found to decrease with increase in pressure and with decrease in temperature for both CO 2 -saturated NaCl and NaHCO 3 solutions. For CO 2 -saturated NaCl(aq), the pH was observed to decrease with increase of salt molality, while for CO 2 -saturated NaHCO 3 , the opposite behaviour was observed. The results have been compared with predictions obtained from the PHREEQC geochemical simulator (version 3.3.9) incorporating the Pitzer activity-coefficient model with parameters taken from the literature. For CO 2 -saturated NaCl(aq), agreement to within ±0.2 pH units was observed in most cases, although deviations of up to 0.3 were found at the highest molality. In the case of CO 2 -saturated NaHCO 3 (aq), the experimental data were found to deviate increasingly from the model with increasing salt molality and, at 1 mol·kg −1 , the model underestimated the pH by between 0.3 and 0.7 units.
Fennell PS, yao JG, maitland GC, et al., 2017, Pressurized Calcium Looping in the Presence of Steam in a Spout-Fluidized-Bed Reactor with DFT Analysis, Fuel Processing Technology, Vol: 169, Pages: 24-41, ISSN: 0378-3820
Calcium looping is a high-temperature solid-looping process for CO2 capture, exploiting cyclical carbonation of CaO. Previous work investigating the effects of steam on the carbonation reaction has produced conflicting results, with the majority of work conducted using thermogravimetric analyzers (TGA). Here, pressurized carbonation kinetics in the presence of steam in a 3 kWe pressurized spout-fluidized bed reactor, gives a rigorous insight into the effects of steam. Pseudo-intrinsic kinetics were determined using an effectiveness factor model along with activation energies and kinetic expressions. The mechanism in which steam promotes CO2 adsorption on the surface of CaO was investigated using density functional theory (DFT). The molecular-scale changes on the CaO surface owing to the presence of steam compared to the base case of CO2 adsorption on a ‘clean’ (without steam) surface were simulated with the Cambridge Serial Total Energy Package (CASTEP) software. The results suggest that steam promotes CO2 adsorption via the formation of surface OH groups on the CaO surface.
Yao JG, fennell PS, Maitland GC, et al., 2017, Two-Phase Fluidized Bed Model for Pressurized Carbonation Kinetics of Calcium Oxide, Energy and Fuels, Vol: 31, Pages: 11181-11193, ISSN: 0887-0624
A two-phase reactor model has been developed using a system of ordinary differential equations in MATLAB to model the carbonation reaction and therefore determine the kinetics of calcium oxide in a pressurised fluidised bed reactor as part of the calcium looping cycle. The model assumes that the particulate and bubble phases are modelled as a CSTR and a PFR respectively. The random pore model developed by Bhatia and Perlmutter1 is incorporated into the system of equations to predict the rate of carbonation for pressures up to 5 bara total, and CO2 partial pressures up to 150 kPa. The surface rate constant and product layer diffusivity in the random pore model expression were obtained by fitting the model to experimental data for a range of pressures, CO2 concentrations and temperatures by minimization of the resid-ual sum of squares. The surface rate constants were found to be between 3.05 and 12.9 x 10-10 m4 mol-1 s-1 for a temper-ature range of 550 to 750 °C. The product layer diffusivities were found to be between 0.06 and 23.6 x 10-13 m2 s-1 for the same temperature range. The surface rate constant and product layer diffusivity activation energy were calculated using the Arrhenius e
Al Ghafri SZS, Maitland GC, Trusler JPM, 2017, Phase Behavior of the System (Carbon Dioxide + n -Heptane + Methylbenzene): A Comparison between Experimental Data and SAFT-γ-Mie Predictions, Journal of Chemical and Engineering Data, Vol: 62, Pages: 2826-2836, ISSN: 1520-5134
In this work, we explore the capabilities of the statistical associating fluid theory for potentials of the Mie form with parameter estimation based on a group-contribution approach, SAFT-γ-Mie, to model the phase behavior of the (carbon dioxide + n-heptane + methylbenzene) system. In SAFT-γ-Mie, complex molecules are represented by fused segments representing the functional groups from which the molecule may be assembled. All interactions between groups, both like and unlike, were determined from experimental data on pure substances and binary mixtures involving CO2. A high-pressure high-temperature variable-volume view cell was used to measure the vapor–liquid phase behavior of ternary mixtures containing carbon dioxide, n-heptane, and methylbenzene over the temperature range 298–423 K at pressures up to 16 MPa. In these experiments, the mole ratio between n-heptane and methylbenzene in the ternary system was fixed at a series of specified values, and the bubble-curve and part of the dew-curve was measured under carbon dioxide addition along four isotherms.
Mac Dowell N, Fennell PS, Shah N, et al., 2017, The role of CO2 capture and utilization in mitigating climate change, Nature Climate Change, Vol: 7, Pages: 243-249, ISSN: 1758-678X
To offset the cost associated with CO2 capture and storage (CCS), there is growing interest in finding commercially viable end-use opportunities for the captured CO2. In this Perspective, we discuss the potential contribution of carbon capture and utilization (CCU). Owing to the scale and rate of CO2 production compared to that of utilization allowing long-term sequestration, it is highly improbable the chemical conversion of CO2 will account for more than 1% of the mitigation challenge, and even a scaled-up enhanced oil recovery (EOR)-CCS industry will likely only account for 4–8%. Therefore, whilst CO2-EOR may be an important economic incentive for some early CCS projects, CCU may prove to be a costly distraction, financially and politically, from the real task of mitigation.
Rufai A, Crawshaw J, Maitland G, 2016, Capillary disconnect during evaporation in porous media: Visualization of transition from stage-1 to stage-2 evaporation regime, 2016 AIChE Annual Meeting, Pages: 219-219
Cadogan SP, Mistry B, Wong Y, et al., 2016, Diffusion coefficients of carbon dioxide in eight hydrocarbon liquids at temperatures between (298.15 and 423.15) K at pressures up to 69 MPa, Journal of Chemical and Engineering Data, Vol: 61, Pages: 3922-3932, ISSN: 1520-5134
We report experimental measurements of the mutual diffusion coefficients in binary systems comprising CO2 + liquid hydrocarbon measured at temperatures between (298.15 and 423.15) K and at pressures up to 69 MPa. The hydrocarbons studied were the six normal alkanes hexane, heptane, octane, decane, dodecane and hexadecane, one branched alkane, 2,6,10,15,19,23-hexamethyltetracosane (squalane), and methylbenzene (toluene). The measurements were performed by the Taylor dispersion method at effectively infinite dilution of CO2 in the alkane, and the results have a typical standard relative uncertainty of 2.6%. Pressure was found to have a major impact, reducing the diffusion coefficient at a given temperature by up to 55% over the range of pressures investigated. A correlation based on the Stokes–Einstein model was investigated in which the effective hydrodynamic radius of CO2 was approximated by a linear function of the reduced molar volume of the solvent. This represented the data for the normal alkanes only with an average absolute relative deviation (AAD) of 5%. A new universal correlation, based on the rough-hard-sphere theory, was also developed which was able to correlate all the experimental data as a function of reduced molar volume with an AAD of 2.5%.
Lee JM, Rochelle G, Styring P, et al., 2016, CCS - A technology for now: general discussion., Faraday Discuss, Vol: 192, Pages: 125-151, ISSN: 1359-6640
Smit B, Graham R, Styring P, et al., 2016, CCS - A technology for the future: general discussion, Faraday Discussions, Vol: 192, Pages: 303-335, ISSN: 1359-6640
Maitland GC, 2016, Carbon Capture and Storage: concluding remarks., Faraday Discussions, Vol: 192, Pages: 581-599, ISSN: 1364-5498
This paper aims to pull together the main points, messages and underlying themes to emerge from the Discussion. It sets these remarks in the context of where Carbon Capture and Storage (CCS) fits into the spectrum of carbon mitigation solutions required to meet the challenging greenhouse gas (GHG) emissions reduction targets set by the COP21 climate change conference. The Discussion focused almost entirely on carbon capture (21 out of 23 papers) and covered all the main technology contenders for this except biological processes. It included (chemical) scientists and engineers in equal measure and the Discussion was enriched by the broad content and perspectives this brought. The major underlying theme to emerge was the essential need for closer integration of materials and process design - the use of isolated materials performance criteria in the absence of holistic process modelling for design and optimisation can be misleading. Indeed, combining process and materials simulation for reverse materials molecular engineering to achieve the required process performance and cost constraints is now within reach and is beginning to make a significant impact on optimising CCS and CCU (CO2 utilisation) processes in particular, as it is on materials science and engineering generally. Examples from the Discussion papers are used to illustrate this potential. The take-home messages from a range of other underpinning research themes key to CCUS are also summarised: new capture materials, materials characterisation and screening, process innovation, membranes, industrial processes, net negative emissions processes, the effect of GHG impurities, data requirements, environment sustainability and resource management, and policy. Some key points to emerge concerning carbon transport, utilisation and storage are also included, together with some overarching conclusions on how to develop more energy- and cost-effective CCS processes through improved integration of approach across the
Smit B, Styring P, Wilson G, et al., 2016, Modelling - from molecules to megascale: general discussion, Faraday Discussions, Vol: 192, Pages: 493-509, ISSN: 1359-6640
Maitland G, 2016, Importance of CCS, Chemistry & Industry, Vol: 80, Pages: 32-32, ISSN: 0009-3068
Peng C, Anabaraonye BU, Crawshaw JP, et al., 2016, Kinetics of carbonate mineral dissolution in CO2-acidified brines at storage reservoir conditions., Faraday Discussions, Vol: 192, Pages: 545-560, ISSN: 1364-5498
We report experimental measurements of the dissolution rate of several carbonate minerals in CO2-saturated water or brine at temperatures between 323 K and 373 K and at pressures up to 15 MPa. The dissolution kinetics of pure calcite were studied in CO2-saturated NaCl brines with molalities of up to 5 mol kg(-1). The results of these experiments were found to depend only weakly on the brine molality and to conform reasonably well with a kinetic model involving two parallel first-order reactions: one involving reactions with protons and the other involving reaction with carbonic acid. The dissolution rates of dolomite and magnesite were studied in both aqueous HCl solution and in CO2-saturated water. For these minerals, the dissolution rates could be explained by a simpler kinetic model involving only direct reaction between protons and the mineral surface. Finally, the rates of dissolution of two carbonate-reservoir analogue minerals (Ketton limestone and North-Sea chalk) in CO2-saturated water were found to follow the same kinetics as found for pure calcite. Vertical scanning interferometry was used to study the surface morphology of unreacted and reacted samples. The results of the present study may find application in reactive-flow simulations of CO2-injection into carbonate-mineral saline aquifers.
Chow YTF, Eriksen DK, Galindo A, et al., 2016, Interfacial tensions of systems comprising water, carbon dioxide and diluent gases at high pressures: experimental measurements and modelling with SAFT-VR Mie and square-gradient theory, Fluid Phase Equilibria, Vol: 407, Pages: 159-176, ISSN: 0378-3812
Experimental interfacial tensions of the systems (H<inf>2</inf>O+CO<inf>2</inf>), (H<inf>2</inf>O+N<inf>2</inf>), (H<inf>2</inf>O+Ar), (H<inf>2</inf>O+CO<inf>2</inf> +N<inf>2</inf>) and (H<inf>2</inf>O+CO<inf>2</inf> +Ar) are compared with calculations based on the statistical associating fluid theory for variable range potentials of the Mie form (SAFT-VR Mie) in combination with the square-gradient theory (SGT). Comparisons are made at temperatures from (298 to 473)K and at pressures up to 60MPa. Experimental data for the systems (H<inf>2</inf>O+CO<inf>2</inf>), (H<inf>2</inf>O+N<inf>2</inf>) and (H<inf>2</inf>O+CO<inf>2</inf> +N<inf>2</inf>) are taken from the literature. For the (H<inf>2</inf>O+Ar) and (H<inf>2</inf>O+CO<inf>2</inf> +Ar) systems, we report new experimental interfacial-tension data at temperatures of (298.15-473.15)K and pressures from (2 to 50)MPa, measured by the pendant-drop method. The expanded uncertainties at 95% confidence are 0.05K for temperature, 70kPa for pressure, 0.016× γ for interfacial tension in the binary (Ar+H<inf>2</inf>O) system and 0.018× γ for interfacial tension in the ternary (CO<inf>2</inf> +Ar+H<inf>2</inf>O) system.The parameters in the SAFT-VR Mie equation of state are estimated entirely from phase-equilibrium data for the pure components and binary mixtures. For pure water, the SGT influence parameter is determined from vapour-liquid surface-tension data, as is common practice. Since the other components are supercritical over most or the entire temperature range under consideration, their pure-component influence parameters are regressed by comparison with the binary interfacial-tension data. A geometric-mean combining rule
Schmidt KAG, Pagnutti D, Curran MD, et al., 2016, Correction to "New experimental data and reference models for the viscosity and density of squalane", Journal of Chemical and Engineering Data, Vol: 61, Pages: 698-698, ISSN: 1520-5134
Empirical models for the density and the viscosity of squalane (C30H62; 2,6,10,15,19,23-hexamethyltetracosane) have been developed based on an exhaustive review of the data available in the literature and new experimental density and viscosity measurements carried out as a part of this work. The literature review shows there is a substantial lack of density and viscosity data at high temperature (373 to 473) K and high pressure conditions (pressures up to 200 MPa). These gaps were addressed with new experimental measurements carried out at temperatures of (338 to 473) K and at pressures of (1 to 202.1) MPa. The new data were utilized in the model development to improve the density and viscosity calculation of squalane at all conditions including high temperatures and high pressures. The model presented in this work reproduces the best squalane density and viscosity data available based on a new combined outlier and regression algorithm. The combination of the empirical models and the regression approach resulted in models which could reproduce the experimental density data with average absolute percent deviation of 0.04 %, bias of 0.000 %, standard deviation of 0.05 %, and maximum absolute percent deviation of 0.14 % and reproduce the experimental viscosity data with average absolute percent deviation of 1.4 %, bias of 0.02 %, standard deviation of 1.8 %, and maximum absolute percent deviation of 4.9 % over a wide range of temperatures and pressures. On the basis of the data set used in the model regression (without outliers), the density model is limited to the pressure and temperature ranges of (0.1 to 202.1) MPa and (273 to 525) K, whereas the viscosity model is limited to the pressure and temperature ranges of (0.1 to 467.0) MPa and (273 to 473) K. These models can be used to calibrate laboratory densitometers and viscometers at relevant high-temperature, high-pressure conditions.
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