On the optimum ageing time - magnetic resonance study of

Subscriber access provided by BUFFALO STATE

Fossil Fuels

On the optimum ageing time - magnetic resonance study of asphaltene adsorption dynamics in sandstone rock Igor Shikhov, Donald S. Thomas, and Christoph Hermann Arns Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b01609 • Publication Date (Web): 26 Jul 2019 Downloaded from pubs.acs.org on July 27, 2019

Just Accepted “Just Accepted” manuscripts have been peer-reviewed and accepted for publication. They are posted online prior to technical editing, formatting for publication and author proofing. The American Chemical Society provides “Just Accepted” as a service to the research community to expedite the dissemination of scientific material as soon as possible after acceptance. “Just Accepted” manuscripts appear in full in PDF format accompanied by an HTML abstract. “Just Accepted” manuscripts have been fully peer reviewed, but should not be considered the official version of record. They are citable by the Digital Object Identifier (DOI®). “Just Accepted” is an optional service offered to authors. Therefore, the “Just Accepted” Web site may not include all articles that will be published in the journal. After a manuscript is technically edited and formatted, it will be removed from the “Just Accepted” Web site and published as an ASAP article. Note that technical editing may introduce minor changes to the manuscript text and/or graphics which could affect content, and all legal disclaimers and ethical guidelines that apply to the journal pertain. ACS cannot be held responsible for errors or consequences arising from the use of information contained in these “Just Accepted” manuscripts.

is published by the American Chemical Society. 1155 Sixteenth Street N.W., Washington, DC 20036 Published by American Chemical Society. Copyright © American Chemical Society. However, no copyright claim is made to original U.S. Government works, or works produced by employees of any Commonwealth realm Crown government in the course of their duties.

Page 1 of 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

On the optimum ageing time - magnetic resonance study of asphaltene adsorption dynamics in sandstone rock. Igor Shikhov,∗,† Donald Thomas,‡ and Christoph H. Arns∗,† † School of Mineral and Energy Resources Engineering, University of New South Wales, Sydney, Australia ‡Mark Wainwright Analytical Centre, University of New South Wales, Sydney, Australia E-mail: [email protected]; [email protected]

Abstract

In particular we determined adsorption rate as a function of ageing fluid type, monitored freeradical and vanadyl contentent of deposits and wettability state (through surface relaxivity) over extended ageing time interval. EPR data suggest no correlation between the concentration of free radicals in deposits and wettability of the cores. On the other hand, vanadyl is one of the necessary components of oil required for efficient ageing process. An increase of the vanadyl fraction in deposits corresponds to a higher deposition rate. We observe two distinctive periods in the ageing process: (i) early-time adsorption best described by a pseudo-second order kinetic model similar for all ageing fluids used in this study suggesting a common reaction-limited process; (ii) a late-time adsorption process of a faster rate proportional to a bulk diffusion coefficient of ageing fluids approximated by an intraparticle diffusion kinetic model. The transition time interval between two can be used as a definition of an "optimum ageing time" in special core analysis. Obtained results provide a link between oil chemistry and wettability phenomena in rocks and may contribute to development of a model predicting wettability reversal and to more accurate reservoir modelling.

Wettability is a key factor defining ultimate hydrocarbon recovery from natural reservoirs and extensive experimentation is required to replicate even partially the wetting state of reservoir rocks. This involves a rock sample wettability restoration procedure, including an ageing step and a concept of an optimum ageing time, in which asphaltene chemistry plays a major role. Asphaltene’s tendency to adsorb on solid surfaces may lead to a wettability change and growth of accumulations restricting flow. Asphaltene properties vary in molecular weight, polarity, trace metals and heteroatoms content, which may relate to their tendency to interact with the solid phase, though subject evidence is contradictory. We investigate a possible relationship between composition of oil, kinetics of an ageing process and a change of sandstone rock wettability. A set of identical sister-plugs of Bentheimer sandstone was aged in four oils of different compositions over various time intervals and the wettability state of these cores evaluated using low-field NMR relaxometry. The composition and key components of accumulated deposits were established by matching 1 H solutionstate NMR and X-band EPR spectra of deposits to spectra of SARA fractions (saturatesaromatics-resins-asphaltenes) of ageing fluids.

ACS Paragon Plus Environment

1

Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Introduction

Page 2 of 30

cesses, and ion binding between charged sites and higher valency ions, e.g. Buckley et al. 7 . It is fair to state, that the mechanisms governing wettability in sedimentary rocks are still not completely understood, though a link to asphaltene chemistry has long been suggested. In addition to asphaltene adsorption there is at least one another highly competitive mechanism responsible for severe formation damage as well as to pipeline transportation problems – paraffin wax deposition. Though the primary cause of wax deposition is a loss in solubility in the crude oil, some reports suggest that asphaltenes play an important role providing crystal nucleation sites or simply restricting the diffusion of paraffins (the opposite effect on diffusion was also regularly reported), e.g. García 8 , Kriz and Andersen 9 . A good review on the topic of asphaltene effects on wax crystallisation is provided by Ariza-Léon et al. 10 . So far, there is no consensus regarding the direction and magnitude of the effect of asphaltenes on wax precipitation, point of crystallization, pour point and rheology of a host fluid. Magnetic resonance techniques enable studying wettability alteration processes at various scales including their dynamics. Low-field NMR relaxometry being sensitive to fluid-solid interaction has been utilised to monitor the wettability state of cores based on surface relaxivity Howard 11 , Fleury and Deflandre 12 , Looyestijn and Hofman 13 . High-field NMR spectroscopy reveals key inter- and intra-molecular information of hydrocarbons and interactions between their components, Dickinson 14 , Majumdar et al. 15 , Fergoug and Bouhadda 16 . EPR is utilised to analyse active components of crude oils and residues, such as free radicals and metal porphyrins Espinosa et al. 17 , Cui et al. 18 , Gafurov et al. 19 . In this work we apply low-field NMR relaxometry, chemical shift spectroscopy and EPR to investigate the relationship between oil chemistry and efficiency of ageing process in increasing rock cores oil wetness.

Asphaltene is the most active component in crude oil complicating petroleum reservoir development and production due to a tendency to adsorb on solid surfaces, which eventually may restrict flow and may change wettability, Yan et al. 1 . As a result porosity reduction and permeability impairment have been reported for a variety of rocks and conditions, Minssieux et al. 2 . Asphaltene fouling is a serious issue in oil pipeline transportation. The characterisation of petroleum prospects involves a core analysis step requiring the wettability state of cores and experimental conditions replicating those of a reservoir. Practically, cores are firstly cleaned to set a strongly water-wet state, followed by a wettability alteration step known as ageing (allowing direct interaction between rock and crude oil over a prescribed time interval at elevated temperature). However, the ageing practices have never been standardised across the industry and academic community and parameters and conditions such as temperature and ageing time intervals are typically chosen arbitrary and reported in literature across a broad range of values. Sripal and James 3 analysed the effect of temperature, ageing time and brine salinity on wettability of sandstone and carbonate rocks. The time of ageing was found to be the most significant factor in impacting the ageing process as observed through contact angle measurement. In agreement with the earlier works of Anderson 4 and Zhou et al. 5 it was observed that extending the ageing period from 2 weeks to 8 weeks leads to a shift from intermediate oil-wet to strongly oil-wet characteristics of rock samples. While acknowledging ageing time as a primary factor of the wettability alteration process (which has to be long enough), the mentioned works provide no connection to oil chemistry, which restrics results to a given pair of rock and oil types. Furthermore, some crude oils may not change wettability at all, while others may require no ageing, Hopkins et al. 6 . The main mechanisms governing rock wettability alteration include polar interactions between oil components and solid, adsorption pro-


2

Page 3 of 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Wettability and asphaltenes reactivity

adsorb is polarity, Gawrys et al. 27 . Wattana et al. 28 observed that chemical properties of asphaltenes deposited from unstable oils are substantially different to those of host crude oil. Their deposits contain a greater fraction of polar compounds and trace metals than asphaltenes of the matching crude oils, i.e. tendency of asphaltenes to precipitate correlates with their polarity and metal content. Summa summarum the asphaltene structure is currently seen as a PAH core enriched with alicyclic and linear/branched alkane groups (Fig. 1), with infrequent inclusions from a broad variety of heteroatom compounds like amide, pyrrolic, pyridinic, carbonyl, carboxyl, furanic and thiophenic groups (one or two per molecule). An appreciable amount of metals is contained in porphyrin complexes.

The term wettability relates to the preference of a solid to be in contact with one fluid rather than with another. It may be thought of as a tendency of a liquid to spread over the surface due to the balance between adhesive and cohesive forces and often quantitatively expressed through the contact angle. Wettability of rocks is among the key factors defining oil recovery, Morrow 20 . The relationship between asphaltenes and wettability of rocks through mechanism of adsorption from crude oil has been previously reported, Kim et al. 21 , Kaminski and Radke 22 , Buckley et al. 7 . Asphaltenes have an unusual definition based on their functionality (i.e. solubility in solvents of different polarity), rather than on the basis of their molecular structure or weight. This definition often allows the conductance of practically important studies without complex atomic- or molecular-scale experiments, but relies on titration; alone or in combination with other analytical techniques. In particular, Nalwaya et al. 23 separated asphaltenes into four subfractions based on their polarity. A subsequent study revealed that the polarity of these fractions correlates to or is defined by their metal content. Alternative approaches of asphaltene quantification are based on boiling point or molecular mass segregation. In a two-part study Subramanian et al. 24 ,25 reported a new procedure to isolate asphaltenes based on their active group composition (carbonyl and carboxylic acid and their derivatives) instead of relying on common solubility criteria. Their approach enabled to study asphaltene adsorption behaviour and stability of adsorbed layers in carbonate rocks. It is now established that asphaltene reactivity (a tendency to flocculate and to adsorb on solids) correlates to various features in their molecular structure, e.g. heteroatoms and metal content, and to solvent properties. The size of the polyaromatic hydrocarbon (PAH) core of the asphaltene molecule is also considered a factor contributing to aggregation, Hortal et al. 26 . However, the main single factor behind asphaltene tendency to flocculate and

Figure 1: The sketch of a hypothetical asphaltene molecule of 723 Da weight showing the key structural proton and carbon species identifiable by 1 H and 13 C NMR spectroscopy.

Overview of magnetic resonance techniques Adsorption behaviour and multiscale aggregation of asphaltene are the most significant and least understood processes in crude oil chemistry. Over the past decades a broad variety of magnetic resonance techniques have been applied, individually or in combinations, for the characterisation of asphaltene molecular structure, to study dynamics of asphaltene flocculation, asphaltene-maltene interactions and asphaltene adsorption on solids. For instance,


3

Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

liquid-state proton nuclear magnetic resonance (NMR) spectroscopy is commonly utilised to type functional groups of petroleum compounds including asphaltenes Semple et al. 29 , Lisitza et al. 30 and Fergoug and Bouhadda 16 . However, asphaltenes contain a substantial proportion of hydrogen-free structural groups, some of which are functionally important. Characterisation of these groups necessitates the use of carbon-sensitive techniques, such as solutionor solid-state 13 C NMR, e.g. Seshdari et al. 31 , Pekerar and Lehman 32 , Acevedo et al. 33 . A combination of 1D solution-state 1 H and 13 C chemical shift NMR spectroscopy is another common approach for the structural characterisation of petroleum fluids since the early work of Clutter et al. 34 and applied later specifically for asphaltene studies by Rousseau and Fuchs 35 , Artok et al. 36 . Other authors rely on 1 H and 13 C solid-state NMR techniques, Siskin et al. 37 , Majumdar et al. 38 . An excellent overview of applications of various NMR techniques to study asphaltenes chemical structure is given by Silva et al. 39 . Low-field NMR techniques have seen rather limited applications in the area of asphaltene chemistry. Zielinski et al. 40 , Zielinski and Hürlimann 41 applied NMR relaxometry to evaluate the size of asphaltene clusters and related the effectiveness of clusters as oil relaxing agent to their size. Gonzalez and Taylor 42 utilised relaxation measurements to monitor wettability change in sandpacks caused by asphaltene precipitation. Espinat et al. 43 used T1 –T2 correlation maps to investigate the effects of concentration and types of asphaltene in deuterated toluene solutions saturating γ-Al2 O3 catalyst supports of mono- and bi-modal pore size distributions asphaltene mobility. One emerging approach to study molecular properties of hydrocarbon species relies on modeling relaxation processes using molecular dynamics (MD) simulations. Singer et al. 44 ,45 applied MD simulations of the autocorrelation functions for intramolecular and intermolecular 1 H–1 H dipole-dipole interactions to obtain detailed information about the role of internal motions and molecular geometry on proton relaxation rates in liquid-state hydrocarbons. Ac-

Page 4 of 30

cording to authors the approach provides a path for an enhanced interpretation of experimental NMR data and can be extended to a case of multi-component hydrocarbon compounds and intricating scenarios like interaction of light hydrocarbon with complex polyaromatic structures of kerogen and bitumen, which may shed a light on the role of various components of crude oil on its stability and reactivity. Fast field cycling (FFC) NMR has been applied to study interactions between crude oil components by Stapf et al. 46 ,47 . Relaxation time spectra T1 (ω) (Larmor frequency dependent longitudinal relaxation time) and T1 /T2 ratios of fluorinated aliphatic and aromatic tracers added to asphaltene-free and asphaltenerich crude oils were utilised to evaluate the molecular mobility of tracers in a host liquid. Asphaltene presence strongly impacted the T1 /T2 ratio of aromatic tracers relative to aliphatic ones indicating a stronger interaction of aromatics moieties with asphaltenes. Aided with Dynamic Nuclear Polarisation (DNP) experiments of crude oil, Ordikhani-Seyedlar et al. 48 concluded that asphaltene aggregates dominate the relaxation of maltenes protons by surface diffusion mechanisms with prolonged residence time, possibly supplemented by trapping within asphaltene aggregates. Benamsili et al. 49 and Vorapalawut et al. 50 probed multiscale dynamics and interactions of maltenes with asphaltene aggregates in crude oils integrating multiple NMR techniques: lowfield D–T2 and T1 –T2 correlations, nuclear magnetic relaxation dispersion (NMRD) and high field two-dimensional NMR DOSY (Diffusion Ordered SpectroscopY). A set of samples was represented by a crude oil variously diluted by its maltenes to provide a range of asphaltene concentrations in an identical natural solvent. The experimentally observed relaxation dispersion has been theoretically explained by enhanced residence time of maltene molecules in the vicinity of vanadyl porphyrins which, according to Silva et al. 51 , is selectively located at the surface of asphaltene aggregates. A good overview on applications of this multiscale NMR approach is given in. 52 Saturates and aromatic fractions of maltenes were not dis-


4

Page 5 of 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Table 1: Components of mixtures and oil. Oil and mixtures OM.1 OM.2 OM.3 Crude oil

Bitumen wt% 10.0 15.0 25.0 0.0

Crude oil, wt% 0.0 30.0 0.0 100.0

criminated between. Electron paramagnetic resonance (EPR) is widely used to study natural hydrocarbons due to a unique sensitivity to active components containing radicals and paramagnetic centers. Gafurov et al. 19 , Biktagirov et al. 53 applied EPR to investigate the temperature dependence of porphyrin mobility in heavy oils. The rotational correlation time estimates enable relating observed temperature dependent motion regimes to the size of asphaltene aggregates. Cui et al. 18 studied the mobility of vanadyl complexes with their surroundings by investigating the effect of solvents, temperature and concentration of atmospheric residues, resins and asphaltenes. In this work we combine information provided by low-field relaxometry, proton chemical shift spectroscopy and EPR to characterise ageing processes in sandstone rock.

C16 H34 wt% 50.0 15.0 40.0 0.0

Toluene wt% 40.0 40.0 35.0 0.0

core samples due to handling, which result in substantially higher early-time adsorption estimates comparing to apparent values. The wettability state of cores is evaluated in respect to n-decane. Low-field NMR relaxation measurements are utilised to monitor the wettability state through surface relaxivity estimated from T2 relaxation time distributions. We recognised that relaxation in aged rocks may be enhanced not singly by increase of wetness, but also promoted by accumulation of asphaltenebased macro-aggregates creating a sort of oilwet microporosity, Shikhov et al. 54 ,55 . However, the focus of this work is a relationship between the chemistry of deposits and wettability change over early-, medium- and latetime ageing rather than effects of morphology alteration. Deposits eluted from the subset of the cores were analysed by means of high-field 1 H solution-state spectroscopy and EPR. Oils used for ageing the cores were fractionated into four SARA components based on their polarity. Proton spectra of eluted deposits were compared to spectra of SARA components to deduce a change of deposits composition over ageing time. EPR spectra of deposits compared to those of resin and asphaltene enable to draw a conclusion regarding the role of metals in ageing process. Several core plugs were selected to directly observe the effect of wettability alteration on two-phase flow characteristics (relative permeability).

Scope of this work We investigate the relationship between three elements of the ageing process: (i) composition of oils utilised for ageing sandstone cores; (ii) composition of resulting deposits, and (iii) observed average rock wettability. This study is an extension of our previous work discussing the application of low-field relaxometry to monitor evolution of wettability and morphology of sandstone and glass-bead packs as a consequence of ageing, Shikhov et al. 54 ,55 . Results are obtained sing Bentheimer sandstone cores aged in synthetic oil mixtures and a crude oil. Time-dependent deposition values are corrected to account for the loss of solid phase of

Materials and samples Sandstone plugs. We prepared in total 49 cylindrical plugs (32∼34 mm long and 12.7 mm in diameter) cored from a block of outcrop Bentheimer sandstone. The plugs were organised


5

Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 6 of 30

Table 2: Mineral composition and specific surface area of Bentheimer. Mineral phase Quartz K-Feldspar Na-Feldspar Kaolinite Other Total

Fraction wt% 95.65 1.80 0.60 1.35 0.60 100.00

Specific surface area, m2 /g 0.04∼0.05 0.2∼1.5 0.1∼1.5 10∼20 0.1∼0.5

Contribution m2 /g 0.038∼0.048 0.004∼0.027 0.001∼0.009 0.135∼0.270 0.001∼0.003 0.188∼0.347

chromatographic column with silica gel SiliCycle SiliaFlash P60 as a stationary phase (particle size of 230-400 mesh/40-63 µm). The following solvents were used for oil separation into SARA fractions: Honeywell B&J n-hexane of 99.97% purity (C6 isomers); Ajax Chemicals cyclo-hexane, 99.5%; Honeywell B&J toluene, BDH AnalaR benzene, 99.0%; Chem-Supply methanol, 99.5%. The three oil mixtures used in this work are composed of natural hydrocarbons (bitumen or/and crude oil) diluted with toluene and hexadecane in various proportions, Table 1. Normal isomer of 99% purity hexadecane was supplied by Sigma-Aldrich. We operationally define oil wetness of rock in respect to n-decane (99% purity, Alfa Aesar). Relative permeability measurements were performed using the isoparaffinic fraction of oil Soltrol 130 (Chevron Phillips) with mean carbon number of 11.9. NMR chemical shift spectroscopy has been performed on hydrocarbon samples highly diluted in deuterated methylene chloride-d2 (CD2 Cl2 , DCM) of 99.5% purity and 99.8% of deuterium content provided by Cambridge Isotopes. All solvents, natural and mixed oils used in the study are diamagnetic within a narrow range of magnetic susceptibility values (χv = -7.6 ∼ -8.5 µSI), Shikhov et al. 57 .

into five groups: three reference cores, not exposed to oils, three sets per 12 cores aged in three oil mixtures and a set of 10 cores aged in a crude oil. Bentheimer exhibits permeability of 1.28 µm2 (1.3 Darcy) and porosity of 23.9%. This rock is weakly diamagnetic, being composed mainly by quarts (about 96 wt.%), small fractions of feldspar (2.4 wt.%) and kaolinite (1.4 wt.%) and minor fractions of other minerals amounted to about 0.5 wt.% combined, see Table 2 based on calculations from measured elemental oxides composition. The surface area in one of the primary properties of sorbent controlling adsorption process. Based on published values (e.g. see excellent review on silicates by Brantley and Mellott 56 ) and own measurements we estimated specific surface area of Bentheimer being 0.2∼0.35 m/g, of which quartz contributes approximately 20% and a minor quantity of kaolinite provides majority of surface area (75%). Petroleum fluids. Two natural hydrocarbons were used to prepare ageing agents: a commercial grade C170 bitumen and a crude oil from a South Pacific oil field. Three synthetic oils were prepared by mixing bitumen, toluene, n-hexadecane and a crude oil in various proportions, Table 1. Asphaltene weight fraction in bitumen is 16∼17%, in crude oil 1.5∼3.5% and in oil mixtures 1.6∼3.9 wt%, depending on the method used, Table 3. Correspondingly, oil OM.3 of a relatively high asphaltene and resin content exhibits the highest viscosity and inversely, oil OM.1 has the lowest viscosity, Table 3 and Table 4. Solvents and other materials. Saturates, aromatics and resins were separated from maltene using a 1 cm × 40 cm

Ageing/cleaning procedure Four sets of Bentheimer sandstone cores fully saturated either with crude oil or oil mixtures OM.1∼3 were kept at 60 ◦ C temperature over specified time intervals according to the ageing schedule, Table 5. After ageing the cores were


6

Page 7 of 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Table 3: SARA analysis of base hydrocarbons. Hydrocarbons Crude oil, IP469a Crude oil, D2007b Bitumen, IP469 Bitumen, D2007

Saturates wt% 38.41 55.02 12.90 26.59

Aromatics wt% 5.60 4.59 28.80 34.03

Resins wt% 4.20 1.26 41.68 15.44

Asphaltenes wt% 3.49 1.47 15.72 17.87

Volatiles + LOCc , wt% 48.30 37.66 0.90 6.07

Asphaltenes to Resins ratio 0.83 1.17 0.38 1.16

a

Application of TLC-FID following Energy Institute protocol; b ASTM standard describing fractionation by sequential flushing chromatography; c LOC - loss on chromatographic column due to oil topping at 250 ◦ C prior to TLC-FID or solvent removal at 60 ◦ C. has to be removed from the oil before proceeding with an analysis of the other three fractions. The standard procedure to determine all four SARA compound classes using TLCFID is specified in the IP469 standard. 63 The asphaltene content determined by this method may differ to results obtained following IP143. TLC-FID typically recovers about 80 % of total asphaltene fraction extracted following IP143. The three techniques are different in time consumption and complexity and often lead to quite different results. The TLC-FID technique is much faster than the other two, but requires separate analysis of light-end distillate (> 250∼300 ◦ C). The ASTM D2007 method of adsorption on chromatographic column is time consuming (it takes at least one day comparing to a minute required for TLC-FID), not necessary accurate and depends on solvent and column sorbent material. However, since a gravimetric analysis of dried components is required, it naturally produces samples for further analysis, e.g. NMR spectroscopy. The choice of alkane solvent affects the quantity and structure of extracted asphaltenes. The mentioned test methods specify the use of n-pentane or n-heptane solvents, which defines accordingly C5 and C7 resins and asphaltenes as soluble and insoluble fractions of petroleum fluids in toluene. Alboudwarej et al. 64 developed a model predicting fractional asphaltene yield due to precipitation induced by various n-alkanes. Generally, the yield increases with lowering the carbon number of alkanes used to induce precipitation. Practically, n-hexane is frequently used, e.g. Andrews et al. 65 , Ma-

rinsed with n-hexane for six days at ambient lab temperature of 22 ◦ C (samples aged in oil mixtures) or 35 ◦ C (samples aged in crude oil). Thus, each core represents a still sample point of a dynamic ageing process.

Asphaltenes characterisation Fractionation and extraction Test methods and standards. Chemical components of petroleum fluids are typically classified into four groups: Saturates, Aromatics, Resins and Asphaltenes (SARA). The asphaltene fraction of crude oils can be extracted by titration under atmospheric conditions of a samplein-toluene with light alkane. The procedure is standardised across the petroleum industry with ASTM D4124-09(2018) 58 and ASTM D6560-12 59 standards and the equivalent standard of the Energy Institute (former Institute of Petroleum) EI IP143:2004 60 (IP143) for n-heptane (most sensitive to C7 -asphaltenes). SARA fractions of petroleum liquids can be obtained using one of three methods: (1) clay-gel adsorption chromatography, either gravity column (GCC) or flash column chromatography (FCC); (2) high pressure liquid column chromatography (HPLC); (3) thin-layer chromatography (TLC) or a variant of the latter combined with flame ionization detection (TLC-FID) also known as Iatroscan. The first method is standartised in ASTM-D2007 61 for n-pentane as a titration agent known as ASTM column separation. The second, HPLC, is specified by the IP368 62 test method. The asphaltene fraction


7

Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 8 of 30

Table 4: Physical properties of fluids and solvents. Hydrocarbons n-hexadecane n-decane Toluene Crude oil Bitumen OM.3 OM.2 OM.1

Density, g/cc @ 22 ◦ C 0.7713 0.7277 0.8625 0.8134 1.0304 0.8792 0.8529 0.8240

Density, g/cc @ 35 ◦ C 0.7626 0.7184 0.8505 0.8129 0.8554 0.8470 0.8162

Viscosity, cP @ 22 ◦ C 3.25 0.89 0.60 16.41 3.61 2.42 1.78

Viscosity, cP @ 35 ◦ C 2.45 0.76 0.53 4.01 3.09 2.03 1.54

TAN* , mg of KOH/g 1.19 1.90 2.37 1.14 1.63

TBN* , mg of KOH/g 0.66 3.80 1.00 0.78 0.32

*

TAN - Total Acid Number and TBN - Total Base Number expressed in equivalent of KOH concentration.

Table 5: Experimental program: ageing schedule and experimental data available per core. Cumulative ageing time, ta [days] Set 1 aged in oil OM.1 Set 2 aged in oil OM.2 Set 3 aged in oil OM.3 Cores aged in crude oil

1 (4)

5.5

7.5

10

13

17

22

28

36

52

72

100

T2LF

T2LF CS1H EPR T2LF CS1H EPR T2LF CS1H EPR T2LF CS1H EPR

T2LF

T2LF CS1H

T2LF

T2LF

T2LF

T2LF

T2LF

T2LF CS1H

T2LF

T2LF CS1H

T2LF

T2LF

T2LF

T2LF

T2LF

T2LF CS1H

T2LF

T2LF CS1H

T2LF

T2LF


T2LF

T2LF

T2LF

T2LF CS1H

T2LF

T2LF

T2LF

T2LF CS1H


T2LF T2LF T2LF

---

T2LF CS1H

T2LF ---

T2LF , CS1H and EPR abbreviates low-field NMR relaxation, proton chemical shift spectroscopy and electron paramagnetic resonance measurements respectively. jumdar et al. 66 , Subramanian et al. 24 ,25 . Solvent to sample ratio is another critical factor affecting the asphaltene yield, Ancheyta et al. 67 . Fan and Buckley 68 compared the performance of ASTM column separation, HPLC and TLCFID techniques using multiple oil samples. Results of the first two correlate well to each other, while the LC-FID technique has proven to be unsuitable for medium gravity oils without additional analysis of components boiling up to 250 ◦ C. GCC results. Asphaltenes were extracted

from the bitumen and the light oil by dissolving and stirring 15 g sample of each in 600 g of n-hexane for 12 hours at room temperature. The resulting solution was vacuum suction filtered through a Whatman 0.2 µm cellulose hydrophilic membrane, and the insoluble part containing asphaltenes was dried under an air-stream at 60 ◦ C. The yield was a black solid powder in case of the bitumen sample and a medium to dark brown residue in case of crude oil. ASTM column separation (sequential flushing GCC) of SAR components has been carried


8

Page 9 of 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Table 6: Elemental analysis of two asphaltenes, weight fractions. Source / / Element Crude oil

C wt% 84.61

H wt% 7.13

N wt% 2.85

S wt% 0.54

O wt% 4.85

Fe wt ppm 171

Ni wt ppm 25.3

V wt ppm 5.71

Bitumen

83.10

7.42

0.90

6.63

1.89

124

119

408

(Shikhov et al. 54 ), the elemental composition of asphaltene originating from bitumen (per 100 atoms) is: C46.98 H50.37 S1.40 N0.44 O0.80 V0.01 and asphaltene from crude oil: C47.94 H48.50 S0.11 N1.39 O2.06 Fe0.002 . Crude oil asphaltenes exhibit a rather low atomic ratio (H/C) of 1.01 evidencing high aromaticity, their low metal content represented mainly by iron. Asphaltene originating from bitumen has a more common H/C atomic ratio of 1.07 with a fair amount of vanadium. While only one in a hundred asphaltene molecules have a vanadyl complex, it may play a critical role in asphaltene-solid interactions, mechanisms of self-aggregation and flocculation with other polar molecules. Noteworthy, asphaltenes from the bitumen are of low nitrogen content having heteroatom fraction represented mainly by sulfur and oxygen, while asphaltenes from oil are deficient in sulfur and the main heteroatoms are nitrogen and oxygen. Despite the significant difference in heteroatom composition, both asphaltenes have a similar total electronegativity (in N,O,S).

out by using the following list of solvents: (1) 50:50 n-hexane and cyclo-hexane mixture; (2) toluene; (3) 60:40 benzene and methanol mixture. In addition, SARA fractions were estimated following TLC-FID analysis of oil and bitumen samples performed by a commercial lab in Perth, Australia (asphaltenes are reported as C5 type). The results are summarised in Table 3. Note the difference in SAR results produced by the two methods. Asphaltene fraction determined using GCC and TLC-FID are reasonably close: 1.45 ± 0.02 wt% and 3.49 wt% (crude oil) and 17.87±0.96 wt% and 15.72 wt% (bitumen). However, the difference in saturates fraction determined by the two methods is significant.

Elemental analysis of asphaltenes Inductively coupled plasma−optical emission spectrometry (ICP−OES) is commonly used for the analysis of metal fractions in petroleum materials. The sample preparation procedure involves asphaltene separation and purification from the maltenes with n-hexane, followed by digestion in strong oxidative conditions. Metals and sulfur content of asphaltene samples were obtained using a Perkin Elmer OPTIMA 7300 ICP-OES instrument at ICP Laboratory, Solid State & Elemental Analysis Unit (SSEAU) of the Mark Wainwright Analytical Centre (MWAC) and the additional analysis of carbon, nitrogen and sulfur content has been performed using a LECO TrueSpec thermogravimetric analyser at the X-ray Fluorescence Laboratory, SSEAU MWAC. The carbon, nitrogen and sulfur content of the asphaltene fraction was also measured by thermogravimetry using the LECO TruSpec Analyser at the XRF Lab, SSEAU. Based on elemental composition (Table 6) and 13 C solid state NMR data

NMR and EPR techniques 1

H solution-state NMR

Chemical shift proton NMR is commonly used to analyse crude oils and their SARA fractions, Woods et al. 70 , Molina V et al. 71 , SanchezMinero et al. 72 . With the aid of SARA proton spectra we aim to follow the composition of deposits in rock cores during the ageing process. Samples were prepared by dissolving eluted deposit (6 to 8 mg weight dry) in 0.6 mL of DCM (CD2 Cl2 ). Solution-state proton NMR spectra were obtained using a 400 MHz (9.4 Tesla) Bruker Avance III spectrometer via lock chan-


9

Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 10 of 30

Table 7: Definition of various types of protons in 1 H NMR solution-state chemical-shift spectrum. parameter

type of protons

HAr,tot HAr,mono HAr,poly HAC Hal,tot Hal,γ Hal,β Hna,β Hal,α

total aromatic proton mono-aromatic proton di- and poly-aromatics molecules aldehydic and carboxylic hydrogen total aliphatic proton Hγ in CH3 to aromatic ring paraffinic Hβ in CH2 to aromatic ring naphthenic Hβ in CH2 to aromatic ring Hα to aromatic ring; -OH and -SH

nel with 65536 data points and a sweep width of 12 ppm. Signal was averaged over 32 repeated scans with an inter-scan delay of 5 seconds. The total acquisition time was about 6.5 min. Spectra of SARA components and deposits were evaluated using published assignments (Table 7). The key features of spectra are the group of peaks corresponding to (a) protons in aromatic compounds, δ=6.0–9.5 ppm and (b) an aliphatic region in the 0.5–4.5 ppm interval of shifts. The latter contains three major peaks relative contribution, which is used to interpret the compositional change of deposits during the ageing process: the peak at 0.91 ppm corresponds to terminal methyl groups at the end of paraffin chains attached to PAH; the central peak at 1.3 ppm is related to methylene protons of alkane chains attached to aromatic groups. Chains on average are propyl groups. Methyl protons in α-position, adjacent to PAH core exhibit chemical shifts mainly in the 2-3 ppm interval, with a tail extending to 4.5 ppm. Protons in chains attached to saturated cyclic groups as well as in methylene groups closest to PAH exhibit shift mainly in the 2.8-3 ppm range. Naphthenic protons show 1.5-1.8 ppm shifts. Combining available data, an average asphaltene may be represented by approximately 600 Da molecule containing PAH of 45 aromatic rings, 2-3 alicyclic groups with 35 aliphatic chains and contain 1-2 heteroatom compounds, e.g. carbonyl groups. Fig. 2 shows proton spectra of crude oil and bitumen SARA fractions. In the aliphatic re-

δ range (ppm), Silva et al. 39 , Jameel et al. 69 6.0 - 9.0 6.0 - 7.2 7.2 - 9.0 9.0 - 10.0 0.5 - 4.5 0.5 - 1.1 1.1 - 1.5 1.5 - 2.1 2.1 - 4.5

Saturates Aromatics Resins Asphaltenes

[a]

9

8

7

6

5

4

3

2

1

0

4

3

2

1

0

Chem. shift,

[b]

Saturates Aromatics Resins Asphaltenes

9

8

7

6

5

Chem. shift, δ 1H [ppm]

Figure 2: Solution-state 1 H spectra of SARA components of [a] bitumen, [b] light crude oil. DCM peaks are not shown.

gion the relative contribution of terminal CH3 0.9 ppm and CH2 1.3 ppm peaks distinctly decreases from saturates to aromatics and further to resins and asphaltenes, while the 1.6 ppm peak exhibits the opposite trend. This feature is utilized in the analysis of deposits accumulated in aged cores.


10

Page 11 of 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

NMR relaxometry

constant characterising the magnetic moment and angular momentum electron is called gfactor. A free-electron in vacuum has a g-factor of 2.0023. A higher value of g indicates the effect of shielding of the applied magnetic field. A lower value indicates an environment producing additional magnetic field influencing an electron, such as a transition metal-ion complex: the vanadyl g-factor is typically reported to be 1.95∼1.98 and free radicals exhibit g-factor of 2.0036. Hyperfine splitting is frequently utilized in EPR spectroscopy to provide information about radicals. It is caused by the interaction between the magnetic moments arising from the spins of both the nucleus and electrons in atoms. In particular, the Vanadium (IV) nuclear spin I is 7/2 and the electron spin splits into 2I+1 energy states. Correspondingly, the expected number of hyperfine peaks is eight. The spacing between hyperfine peaks (or hyperfine coupling constant A) may be expressed through the g-factor as following: A = gµe /∆B, where µe = ||µe || and ∆B is a field difference corresponding to energy level splitting (hyperfine field). The magnitude of A, here A = A|| or A = A⊥ , indicates the extent of delocalization of the unpaired electron over the molecule. Fig. 3 [a-j] shows the first derivative (absorption) spectra normalised by sample weight: resin and asphaltene samples fractionated out of bitumen [a,b], deposits eluted from rock samples aged over 5.5 days, 22 days and 100 days (three oil mixtures [c-h] and a crude oil [i,j]). Spectra represented by a sum of two components - a single line contributed by "free radicals" (left column, Fig. 3) and hyperfine peaks due to interaction of unpaired electron spin with nuclear spin of 51 V (right column, Fig. 3). The g-factor value calculated for the DPPH mono-crystal reference sample is found to be 2.0029, the "free-radical" component average of all samples is 2.0027±0.0002 and the vanadyl component g is 1.955. Vanadyl features of the spectra show two sets of partially overlapping peaks corresponding to VO2+ in the porphyrin complex. Because of the planar structure the EPR spectrum consists of eight lines in parallel, with A|| = 17.07 mT separation and eight lines in transverse orientation A⊥ = 6.96 mT, very

Transverse relaxation time of decane saturating variously aged Bentheimer cores was measured using Magritek Rock Core Analyzer oprating at 2 MHz proton resonance frequency. The standard Carr-Purcell-Meiboom-Gill (CPMG) technique Carr and Purcell 73 , Meiboom and Gill 74 was employed to obtain a multi-exponential magnetisation decay. 40,000 echoes with echo spacing tE of 200 µs were acquired, such that the longest relaxation component from bulk fluid can be resolved. The problem of obtaining eigenvalues for an observed signal represents the Fredholm integral equation of the first kind with exponential kernel often referred (see discussion by Fordham et al. 75 ) as Inverse Laplace Transform. T2 distributions were obtained with the aid of a regularised non-negative least squares (NNLS) estimator with L-curve smoothing criterion following Lawson and Hansen 76 ,. 77 CPMG experiments were performed with 16 repeated scans to reduce random noise.

Liquid-state EPR EPR spectra were obtained using a Bruker ESP-300 X-band spectrometer operating at 9.83 GHz in continuous wave mode. Liquidstate samples were prepared by dissolving dry hydrocarbon solute in toluene. The solvent was selected on the basis of low dielectric constant η to maintain sensitivity of the EPR resonator. The magnetic field was varied between 2,500 and 4,500 G. The microwave power was 2 W and the aquired signal was averaged over 10 scans to improve SNR. The concentration of unpaired electrons in the samples was estimated by calibrating spectra to that of a 2,2-diphenyl1-picrylhydrazyl (DPPH) reference containing a stable free-radical. Two characteristics of the EPR spectra are used to identify chemical structure (in the immediate vicinity of a nuclei containing unpaired electron): g-factor and a hyperfine coupling constant A. The magnetic dipole moment µe = gµB L/¯h of the electron is approximately twice larger than that of a charged classical particle. The dimensionless


11

Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 12 of 30

15

0.06

10

0.04

5

0.02

0

VO 2+ ,

B

0

-5

-0.02 VO 2+ ,

-10

-0.04

B ||

-15

[a]

3450

3500

3550

-0.06

3000

[b]

15

0.06

10

0.04

5

0.02

0

3200

3400

3600

VO 2+ ,

3800

4000

4200

3800

4000

4200

3800

4000

4200

3800

4000

4200

3800

4000

4200

B

0

-5 -0.02 VO 2+ ,

-10

B ||

-0.04 -15

[c]

3450

3500

3550

-0.06

[d]

15

0.06

10

0.04

5

0.02

0

3000

3200

3400

3600

VO 2+ ,

B

0

-5 -0.02 VO 2+ ,

-10

B ||

-0.04 -15

[e]

3450

3500

3550

-0.06

[f]

15

0.06

10

0.04

5

0.02

0

3000

3200

3400

3600

VO 2+ ,

B

0

-5

-0.02 VO 2+ ,

-10

-0.04

B ||

-15

[g]

3450

3500

3550

-0.06

[h]

15

0.06

10

0.04

5

0.02

0

3000

3200

3400

3600

VO 2+ ,

B

0

-5 -0.02 VO 2+ ,

-10 -0.04

B ||

-15

[i]

3450

3500

3550

-0.06

[j]

3000

3200

3400

3600

Figure 3: EPR spectra of oil components and deposits eluted from aged cores (5.5, 22 and 100 days) normalised by sample weight (left column - free-radicals and right column - vanadyl): [a,b] DPPH reference, resins and asphaltenes extracted from bitumen; deposits eluted from cores aged in oil mixture OM.1 [c,d], oil OM.2 [e,f], oil OM.3 [g,h] and crude oil [i,j].


12

Page 13 of 30

1

similar to values reported by Biktagirov et al. 53 . EPR spectra of resins, Fig. 3 [a,b], show a very little amount of compounds containing unpaired electrons, i.e. approximately 20 times less "free radicals" and vanadyls than in asphaltenes. Following the standard definition, resins should have no metals at all. The observed presense of vanadium can be attributed to imperfect fractionation.

Relative permeability, krw , kro

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels Ref. no ageing BH ta =17 days BH ta =28 days

0.8

0.6

0.4

0.2

0 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

Water saturation, Sw

Results

Figure 4: Relative permeability curves (water and Soltrol 130 iso-alkane fluid pair) of a reference water-wet plug and two plugs aged over 17 and 28 days. Increase in oil-wetness is evident by the shift towards lower water saturation.

Wetting properties of decane. We evaluated wetting properties of surfaces covered by various types of hydrocarbons (gel-like petroleum paraffin, solid paraffin wax, bitumen and asphaltene extracted from bitumen) in respect to n-decane by a quick-look qualitative experiment (placing a drop of fluid on a flat glass substrate). The shape and spreading behavior of a decane drop is considered as a qualitative indicator of affinity to a given surface type. Observations show that decane strongly wets a paraffin covered substrate - the drop is not retained, but spreads as thin as surface quality allows. The bitumen covered surface retains a rather flat drop, but becomes partially dissolved by decane. Substrate covered with an asphaltene layer (deposited from toluene solution) is resistant to dissolution and retains a rather flat drop (same as non-covered substrate). We can conclude that though asphaltene is decane-wetting (in case of a decane/air pair) the degree of affinity is significantly lower comparing to the paraffin covered surface. Wettability state of aged cores. The actual wettability state of the aged plugs was evaluated using three approaches: (1) NMR transverse relaxation measurements - the main approach, which was confirmed by (2) spontaneous imbibition (D2 O in decane saturated cores) testing for strong water-wetness and (3) core flooding steady-state relative permeability measurements. While none of these three precisely recovers the standard Amott-Harvey or USBM tests, they provide a very good indication of wettability change. The imbibition test proved

the weak decane wetness of a reference Bentheimer core and the mixed- or intermediate wet state of early-time aged cores. Fig. 4 shows three steady-state relative permeability curves obtained on a reference core and two aged ones (17 and 28 days). Cores were fully saturated with water prior to fractional flow relative permeability experiments performed in 10 increments of volumetric rate ratios (of aqueous to oil phase) having a total flow rate fixed at 1.0 ml/min. After each fractional flow step saturation of fluids was determined by weighing. The pressure drop across the sample was converted to oil and water fractional permeability assuming steady-state conditions were achieved. Disrete data points were then fitted using powerlaw model (Burdine 78 , Brooks and Corey 79 ). The stronger paraffin wetness of the cores reduces transport of that phase - the same relative mobility value is achieved at a higher saturation. The resulting change in transport can be demonstrated by the shift of the position of relative permeability curves’ crossing point (phases saturation at which volumetric flow of two phases is equal, Fig. 4). The water-wet core has still 65% of pore space occupied by water when transport of oil and water through the core equalises and only 48% when rock is more oil-wet.


13

Energy & Fuels

Low-field relaxometry

Cores aged in oil OM.1

Four time series of T2 relaxation time distributions obtained on variously aged core plugs resaturated with decane are depicted on Fig. 5 [ad]. The colours encode a particular set of cores and are kept consistent across the text. The shift towards shorter relaxation time reflects primarily the increase of oil wetness, which is strongest for the set aged in oil OM.2, more moderate when oil OM.1 was used as an ageing agent, very limited in case of OM.3 and practically absent in the case of crude oil. In our previous work, Shikhov et al. 54 , we demonstrated that the ageing process may promote relaxation not only by increasing the affinity to the saturating fluid, but also due to a change of morphology by deposited macro-aggregates. Here, however, for the sake of simplicity, we avoid the use of relaxation-exchange data and just note the existence of a late-time ageing period at which morphological change becomes significant. Surface relaxivity calculated from log mean relaxation time of T2 distributions shown in Fig. 6 demonstrates consistent trends over ageing time, strongly non-linear in the case of a set aged in oil OM.2 which contains asphaltenes from both, bitumen and crude oil. The difference in oil chemistry between the four sets results in significantly different degrees of relaxation enhancement over the whole time interval of 100 days: by a factor x1.5 (crude oil), x1.9 (oil OM.3), x2.7 (oil OM.2) and x4.0 (oil OM.1).

Ageing time

0

→

[a]

0.001

0.01 0.1 1 Transverse relaxation time, T2 [s]

10


Ageing time

0

→

[b]

0.001


10


Ageing time

0

→

[c]

0.001


10

Cores aged in crude oil

0

Ageing time

Kinetic model The three most commonly used models of solute molecule adsorption onto an adsorbent are the: (i) pseudo-first-order kinetic model (PFO) of Lagergren 80 , (ii) pseudo-second-order kinetic model (PSO), Blanchard et al. 81 and (iii) intraparticle diffusion model, Weber and Morris 82 . The PFO kinetic model is expressed by the following differential equation and its solution: dqt = ka1 (qe − qt ) dt ka1 log(qe − qt ) = log(qe ) − t. 2.303

→

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 14 of 30

[d]

0.001


10

Figure 5: Relaxation time distributions obtained on decane saturated Bentheimer cores aged [a∼c] in three oil mixtures OM.1∼OM.3 and [d] in a crude oil over specified time intervals up to 100 days, Table 5. The reference line at 800 ms corresponds to the mode of relaxation time distribution of a core before ageing.

(1)


14

Page 15 of 30

Energy & Fuels

Surface relaxivity, ρ2 [µm/s]

16

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

14 12

the assumption that the adsorption rate is the straight adsorption-dissorption difference:

Set aged in oil OM.1 Set aged in oil OM.2 Set aged in oil OM.3 Set aged in crude oil

C1,t (t1 ) = A1,t (t1 ) − D1,t (t1 ) .

10 8

Our ageing experiment, however, is different to a simple mono- or multi-layer formation process because result is observed after a rinsing step (adsorption-dissorption+dissolution). It occurs in very different chemical conditions and is a function of the previous ageing step. Thus, the observed accumulation rate due to ageing is a sum of three processes (ignoring trapping of colloidal aggregates):

6 4 2 0 0

20

40 60 Ageing time, ta [days]

80

100

Figure 6: Evolution of apparent surface relaxivity ρ2 estimated from T2 distributions of four sets of variously aged and fully decane-saturated Bentheimer samples.

C2,t (t1 , t2 ) = C1,t (t1 )+A2,t (C1,t , t2 )−D2,t (C1,t , t2 ) . Here qt and qe are the specific amounts of adsorption [mg/g] at time t and at equilibrium, respectively. The PSO kinetic model and the solution of that differential equation are expressed by the following: dqt = ka2 (qe − qt )2 dt t t 1 , = + qt qe ka2 (qe )2

There is an agreement in the literature that asphaltene adsorption in rocks is a relatively fast process (reaching equilibrium in the order of hours or tens of hours) following a pseudo-first-order kinetic model with isotherms in agreement with the Langmuir model, e.g. Kokal et al. 84 , Alboudwarej et al. 85 , Nassar 86 . We fitted specific adsorption data as a function of square root of ageing time using nested PSO and IPD models (individual plots for each of four set shown on Fig. 7 [a-d]). One can see that the PSO fit is very similar for all data sets - the equilibrium specific amount of 1 to 1.5 mg/g is achieved sometime between 4 to 16 days of ageing. Adsorption capacity of adsorbents and especially rocks is often reported in respect to their surface area qs , rather than per unit mass qm . However, the appropriate choice of surface area values of a rock is not that trivial. Results provided by the BET technique Brunauer et al. 87 may be physically correct, but corresponds to an area accessible to gas molecules much smaller in size than asphaltenes and asphaltene clusters. For instance, Gonzalez and Taylor 42 reported the following parameters of asphaltene adsorption on 200 µm mean grain diameter sand packs: specific surface area 0.09 m2 /g, adsorption per unit weight - 0.19 mg/g and per unit surface area 2.2 mg/m2 . Syunyaev et al. 88 reported asphaltene adsorption on quartz sand of 200 µm grain diameter: specific surface area 0.01 m2 /g, adsorption per

(2)

where ka1 and ka2 are the first- and the second order kinetic coefficients of adsorption, having dimensions of the inverse of specific adsorption rate, e.g. (mg/g)−1 /hr. These coefficients are indicators of adsorption rate – smaller values correspond to earlier adsorption equilibrium. The IPD model is expressed by the following equation: where kd is the intraparticle diffusion rate constant having dimension of the specific adsorption rate, e.g. (mg/g)/hr. kd is proportional to the square root of the effective (intraparticle) diffusion coefficient. The constant C relates to boundary layer effects and becomes zero in it’s absence. The intraparticle diffusion coefficient in the context of adsorption processes from a multi-component fluid like oil refers to the mutual diffusion coefficient of the adsorption governing component. The first- and second-order rate equations can be derived from the Langmuir adsorption isotherm, Leu and Shen 83 , which in turn describes monolayer formation of noninteracting solutes under


15

Energy & Fuels

4

4

3

2

3

0 0

1

2

3

4

5

6

7 8 1/2

Sqrt of ageing time, ta

9

10 1/2

[days ]

1

2

3

4

5

6

7 8 1/2


9

10 1/2

[days ]

3

3

2

1

0 0

[c]

5

4

1

0 0

[b]

5

2

1

Set aged in crude oil PSO model fit IPD model fit

6

4

2

1

[a]

6

5

7

Set aged in oil OM.3 PSO model fit IPD model fit

Specific adsorption, qm [mg/g]

5

7


6


6


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

7



7

Page 16 of 30

1

2

3

4

5

6

7 8 1/2


9

10 1/2

0 0

[days ]

[d]

1

2

3

4

5

6


7 8 1/2

9

10 1/2

[days ]

Figure 7: Specific adsorption qm (the same data as shown on Fig. 8 [a]) plotted as a function of square root of time and fitted with two nested kinetic models: PSO, solid line and IPD, dash line for four sets of rock cores [a] aged in OM.1, [b] aged in OM.2, [c] aged in OM.3, [d] crude oil.

Table 8: Self-diffusion coefficients, vanadyl and asphaltene fractions of ageing oils vs IDP diffusion rate constants. Oil and

Oil mixture

Oil mixture

Oil mixture

Crude

mixtures

OM.1

OM.2

OM.3

oil

1.8

3.1

4.5

1.5

max concentration VO , ppm

66.4

102.7

166.3

9.3

mean self-diffusion coef. D0 , 103 µm2 /s

0.61

0.51

0.38

0.20

0.75

0.70

0.17

–

asphaltene fraction, wt% (D2007) 2+

IDP constant kd , mg/g/day

1/2

most other sandstone rocks. The first is the surface area of quartz grains, which accounts for 97 vol.% of solid phase, but only for 10∼15% of the total surface area (about 0.35 m2 /g). The second is the surface area of clays (kaolinite in case of Bentheimer), which account for meagre 3% volumetrically, but for 80% of the total surface area. The total specific surface area controls adsorption dynamics and indirectly wettability evolution, while inter-grannular space, adsorption onto and wetting state of grains control transport properties. Our value of PSO equilibrium adsorption in Bentheimer of approximately qm = 1.5 mg/g may be translated into qs of about 3∼4 mg/m2 corresponding to a uniform layer thickness of about 4 nm, which is on par with previously reported values. More intriguing is the appearance of a transition point after which the reaction-limited

unit weight - 0.023 mg/g and per unit surface area 2.3 mg/m2 , though the maximum theoretical value was calculated as 1.0 mg/m2 . Saraji et al. 89 reported asphaltene adsorption on 74150 µm particle diameter quartz sand pack having a BET surface area of 0.21 m2 /g: adsorption per unit surface area 1.5 mg/m2 . All authors concluded that at given experimental conditions (either dynamic – asphaltene in toluene flow or static – exposure with subsequent flushing with good solvent) the result is associated with the formation of a uniform adsorbed film of 1.6 to 3.9 nm thickness, comparable with the diameter of asphaltene nanoaggregates predicted by Mullins et al. 90 and estimated from electrical conductivity 91 and spectroscopic experiments Simon et al. 92 . To estimate qs in respect to Bentheimer, we need a value of the surface area, which is of two types in this and the


16

Page 17 of 30


7 6

4 3 2 1 0 0

20

[a] Specific adsorption, qm [mg/g]

7 6


80

100


5 4 3 2 1 0 0

[b] 4

3

2

4 8 10 6 Surface relaxivity, ρ2 - ρ2 (0) [µm/s]

12

Set aged in oil OM.1 Set aged in oil OM.2 Set aged in oil OM.3 Set aged in crude oil Sample points, all sets

2

1

0 0

[c]

diffusion coefficient of oils, Table 8. No extra adsorption is observed for the set of cores aged in crude oil, which points at the absence of excessive accumulation of aggregates. Potentially, the higher stability of crude oil comparing to oil mixtures during ageing may be attributed to its much lower vanadium content. The effect of ageing fluid composition on the relationship between the amount of adsorbed material and wettability can be illustrated by qm vs ρ2 - ρ2 (0), Fig.8 [b,c]. The latter denotes an increase of surface relaxivity relative to water-wet reference rock core. Noteworthy, within a significant range of adsorption and relaxivity shift values (a region on Fig.8 [b] limited by dash lines) a strong linear relationship holds for all four aged systems, Fig.8 [c]. This suggests that the degree of mono- and multilayer continuity linearly dependent on relaxation time shifts with the slope common for all ageing fluid used. Apparently, that common relationship between amount of deposit and relaxivity shift dictated by identity of porous medium properties. This supports the concept of surface relaxivity based NMR wettability index (within the mentioned limits), which can be generally approximated by relaxivity shift we used here. Yet, the rate and continuity of a formed layer are very specific to ageing fluid. Furthermore, high value of adsorption and relaxivity shifts (Fig.8 [b], outside the dash line limited) evidencing significant alteration of rock morphology by extensive accumulation of large macro-aggregates in case of core aged in OM.1 and OM.2.


5


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels


5

Figure 8: [a] Evolution of specific adsorption qm (ta ) over ageing time. The linear fit illustrates the difference in adsorption rates between four systems. [b] Relationship between relative surface relaxivity ρ2 (ta ) - ρ2 (0) and specific amount of adsorbed material qm . The interval where a common linear relationship holds is limited by dash lines. [c] A subset of data (the labelled region above) shows strong linear relationship.

Composition of deposits Fig. 9 depicts four time-series of chemical shift NMR spectra of deposits eluted from aged cores, each sampling five time intervals of the ageing process: 5.5, 10, 22, 72 and 100 days. All early-time ageing spectra show the presence of a peak at about 1.6 ppm, characteristic for asphaltenes, Fig. 2. However, that peak almost completely vanishes with increase of ageing time when OM.1 and OM.2 were used, Fig. 9 [a,b], and significantly reduces when OM.3 and a crude oil were utilised, Fig. 9

adsorption process is replaced by a diffusioncontrolled process with the rate very different between the four data sets, Fig.7 [a-d]. The diffusion rate constant kd correlates to the bulk


17

Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

[c,d]. Assuming that deposit spectra at any time may be represented as a weighted sum of asphaltene and only one of three SAR components spectra (of either crude oil or bitumen, Fig.2), we conducted sensitivity analysis to determine the evolution of deposits composition. The fitting was performed for five major spectra components (HAr,tot , Hal,γ , Hal,β , Hna,β , Hal,α , following Table 7 assignments) by minimising residual amplitudes. Aliphatics are found to be the best-fit second component of mainly asphaltene-made deposits, low fraction of which first appears in medium-time aged deposits and progressively increases as ageing process evolves into late-stage. Early-time deposits of all four core sets contain asphaltene fractions only. The estimated average fraction of nonasphaltene content is shown on Fig. 10 [a]. It follows an S–shape trend (all four data sets fit with sigmoid function modified by an inverse quadratic term) signifying three distinctive time intervals: (i) a relatively short earlytime period of pure asphaltene deposition (the first 5 to 7 days), followed by (ii) mid-time period of fast increase of non-asphaltene content (untill ta = 22∼24 days) after which the late-time ageing period (iii) is follows, when non-asphaltene fraction growth occurs at low rate. The latter is consistent with the assumption of aliphatic-asphaltene macro-aggregates trapping and accumulation and observed continuous surface relaxivity growth, Fig. 8 [b,c]. The relationship between asphaltenes and saturates is long known since it affects the pour point of oils (a temperature at which gelation starts), however, reports on the matter are scarce and contradictory. Evidences of interactions between asphaltenes and aliphatics were recently reported by Stachowiak et al. 93 and Orea et al. 94 , though the particular mechanism remains not fully understood. The latter work established the selective capacity of asphaltenes to retain certain types of saturated and unsaturated hydrocarbons (n-alkanes, cyclic and acyclic isoprenoids), while acyclic isoprenoids were the least retained. Majumdar et al. 38 , 95 investigated inter-asphaltene interactions in clusters by applying the dipolar and T2 filter sequences and typed environments within

[a]

[b]

[c]

[d]

Page 18 of 30

9

8

7

6

5

4

3

2

1

0

9

8

7

6

5

4

3

2

1

0

9

8

7

6

5

4

3

2

1

0

9

8

7

6

5

4

3

2

1

0

Figure 9: 1 H chemical shift spectra of deposits eluted from Bentheimer cores aged over five time intervals (5.5, 10, 22, 72 and 100 days) in various oils: [a] OM.1, [b] OM.2, [c] OM.3 and [d] crude oil. DCM calibration peaks are not shown.


18

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Non-asphaltene fraction in deposit

Page 19 of 30

Sigmoid function fit Modified sigmoid

0.5 0.4 0.3 0.2 0.1 0

[a]

0

20


80

100

[b]

Figure 10: [a] Plot of average non-asphaltene fraction over ageing time fitted with a variant of sigmoid function. [b] Diagram showing three stages of ageing process: (i) initial pure asphaltene layer growth, possibly discontinous due to local topological features; (ii) clusters deposition, continuous layer, increase in aliphatic content; (iii) development of a strongly alkane-wet sandwich layer containing highly porous asphaltene network clusters containing entrapped/entangled high-weight paraffins and alicyclic molecules.

broad elements of proton NMR spectra. The proton shift of 1.6 ppm of clustered asphaltene systems was attributed partly to cycloalkyl groups condensed with the aromatic core and partly to low mobile CH2 groups located inside the bulk of the clusters. These groups were held responsible for facilitating cluster formation through alkyl-alkyl interactions between nanoaggregates. We used an NMR spectrum predictor (Aires-de-Souza et al. 96 , Banfi and Patiny 97 , Castillo et al. 98 ) to evaluate elements of constructed model molecules. Indeed, modelling of proton spectra of structures composed on various ratios of aromatics, naphthenic and linear alkane groups reveals a likely origin of the 1.6 ppm proton shift, contributed by alicyclic protons immediately next to the aromatic core and methyne groups in β position. We have no direct information about the origin of these alicyclic groups.

nal CH3 , which is the most common in aliphatic fraction), Fig. 11. The observed compositionrelaxivity relationships due to ageing in fluids of similar nature (bitumen-based) show a common trend: a fast and strong decrease in ashaltene content combined with an increase of aliphatic content followed by the interval of surface relaxivity (and accumulated deposit) increase at about constant composition. The latter observation corresponds to accumulation of macroaggregates/clusters and relaxation rate increase due to more restricted pore space. Lastly, we discuss the main factors affecting quality of obtained data: (1) inhomogeneous deposition during ageing step; (2) effect of oxygen dissolved in ageing fluids and solvents used for NMR and EPR measurements; (3) effect of vanadyl complexes in adsobed and deposited hydrocarbons. The first problem arises due to ageing under static (non-flowing) conditions and results in local concentration inhomogeneity, specifically strong at the outer part of a rock sample. Furthermore, external surface naturally represents a system discontinuity, which tends to trap even mobile components of deposits/macro-aggregates at a later ageing stage. Apparently, the magnitude of the effect is a function of sample size. According to our assessment, long-time aged cores have up to 10% of pore-space affected by increased deposition, which is an acceptable trade-off for the conveniently small sample size. A good ac-

Discussion The analysis of proton chemical shift spectra enables estimating the evolution of the nonasphaltene fraction in deposits. The impact of compositional change and volumetric increase of deposits on wettability of the sandstone rock is illustrated by plotting a surface relaxivity change (as a crude wettability indicator) versus relative fractions of the 1.6 ppm peak (as an indicator of asphaltene) and 0.9 ppm peak (termi-


19

Energy & Fuels

count on a difference between ageing at static and flowing conditions can be found in Mascle et al. 99 .

hancement due to vanadyl porphyrins in aged rock is localised in the vicinity of the rock solid surface and accumulated asphaltene clusters. The presence of vanadyl complexes in asphaltene molecules means a lack of planar symmetry, which according to Silva et al. 51 tend to be selectively included at the outer shell of aggregates. These specifically ordered effective relaxation environments increase observed surface relaxivity, however without contributing to oil wettness (at least in a conventional understanding of the term), complicating the application of NMR wettability techniques. Based on EPR spectra of deposits it is possible to conclude, that in the investigated systems surface relaxivity is controlled by free-radicals over all ageing stages and contribution of vanadyls is relatively small.

1.6 ppm shift fraction 0.9 ppm shift fraction

0.4

1

0.9 or 1.6 ppm fraction in H spectra

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

0.3

0.2

0.1

0 0

2


Page 20 of 30

12

Figure 11: Surface relaxivity change of aged plugs plotted versus fraction of 0.9 ppm (terminal methyl Hal,γ ) and 1.6 ppm peak (Hna,β ) of 1 H NMR spectra of deposits. Colour of symbols corresponds to Fig. 6.

Wettability heterogeneity There are several reasons can be named behind observed diversity of wettability alteration even of basic systems like used in this work, i.e. simple mineralogy, no flow quasistatic conditions, presence of only a very thin water film. Below we discuss several mechanisms which hypohetically may lead to heterogeneity of the wettability alteration process (and in certain circumstances create mixed-wet state of the rock). The first and the smallest scale of heterogeneity occurs due to inhomogeneity of underlying chemical processes thanks to broad variety of oil active components and surface active sites. The particulars of asphaltene deposition are strongly dependent on initial condition of the solid surfaces. (001) surface of α-quartz in a perfectly dry state is extremely reactive and hydrophilic resulting in fast reaction with atmospheric water vapour creating a surface monolayer of silanol groups. This hydroxylated quartz in turn is also hydrophilic and tend to acquire more water molecules to complete few successive layers (3-4 according to Asay and Kim 103 ) of ice-like water. Molecular arrangement in a monolayer of water molecules connected to silanol surface groups by a pair of uneven covalent bonds gradually changes in the subsequent layers to three-four bond arrange-

Paramagnetic relaxation enhancement due to oxygen dissolved in sample fluids affects both EPR and NMR responses. Interaction between free-radicals of oil components and oxygen di-radicals decrease the spin-lattice relaxation time, which lead to the EPR resonance line-width broadening. The magnitude of the effect is directly proportional to the concentration of interacting species; while the concentration of dissolved oxygen across different samples is constant, the amount of deposit between samples varies 5-fold (lower quantities of the early ageing time deposits were available). However, only one free radical spectrum (oil OM.3, ta = 100 days, see Fig. 3 [g]) exhibits signs of broadening being at the same time 20% lower in amplitude. NMR relaxation is equally affected by unpaired electrons of oxygen disolved in fluids. However, since T2 measurements were performed on fully decane saturated cores, all responses received an even shift towards shorter relaxation time, making relative comparison of aged core fully valid. More on the effect of oxygen on NMR relaxation can be found elsewhere, e.g. Parker and Burnett 100 , Mutina and Hürlimann 101 , Shikhov and Arns 102 . The effect of paramagnetic relaxation en-


20

Page 21 of 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

[a]

[b]

[c]

[d]

[e]

[f]

Figure 12: Quartz surface of Bentheimer sample after 13 days of ageing in OM.1 [a]; after 13 days and 52 days of ageing in OM.3, [b] and [c] respectively. Kaolinite verms before ageing [d]; after 13 days of ageing in OM.2 [e] and after 52 days of ageing in OM.3 [f].

ment creating an adsorbed film of "true" liquid water. The details of quartz surface structure and exact mechanisms of retention are still debated. Types of oxygen bonds terminations and distribution of siloxane, isolate, vicinal and geminal silanol groups on the surface dictate strength of hydrogen bonds to the first water layer and probability of interactions with active oil components. The oil components, primarily asphaltenes in clustered state, interact with water layer and if the latter exhibit sufficient thickness, an asphaltene-water interface would be created. Such an interface can be thought as a water saturated layer of asphaltene clusters of a thickness dictated by their size. Reported values of asphaltene-water interface are in approximately 5 to 50 nm range, see e.g. Gonzalez and Taylor 42 , Chen et al. 104 . Near linear dependence between asphaltene adsorption and water film thickness was suggested by Gonzalez and Taylor 42 . It has been recently reported that 500 nm thick water films provide near complete immunity to quartz surface against asphaltene deposition, Huang et al. 105 . On the other hand, in conditions of our experiments favouring asphaltene deposition, when water film is thinner or in the order of would be oil-water interface, nothing in principle should stop asphalene clusters (especially their exposed carbonyl and car-

boxyl groups) from establishing multiple bonds with silica and hydroxylated layer leading to no apparent difference in surface alteration process other than rate of approaching strongly oil-wet state. Another (second ) mechanism can be held responsible for creating large-scale deposition heterogeneity in conditions favouring asphaltene adsorption. Deposited asphaltenes displace water molecules even if the hydration layer is very thin. Huang et al. 105 demonstrated existence of a strong relationship between water film thickness and asphaltene adsorption from toluene and proposed a mechanism of asphaltene deposition through the relatively thick water film involving a partial interface rupture leading to creation of patches of brine on the silica surface. This resembles our observations of circular spots of exposed quartz frequency and size of which decreases as ageing progressing, Shikhov et al. 54 . Water lenses of displaced water are the places where asphaltene-water interface is certainly formed. Asphaltene properties likely dictates stability and elasticity of these interfaces. As a result of subsequent steps of our experimental procedure, interfaces covering water lenses rupture exposing clean quartz surface. Oil OM.1 demonstrated the highest wettability alteration capacity, yet it shows clearly the pat-


21

Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 22 of 30

sorption capacity and lekely lead to a strong decrease of surface area available for deposition of asphaltene aggregates over ageing time. Similarly to quartz, silica surfaces of kaolinite particles may exhibit locally mixed wet state due to creation of water lenses after even significant ageing time, Fig. 12 [f]. Sparsely distributed kaolinite accumulations may change composition of active oil components in adjacent pores, leading potentially to largest scale of wettability alteration process. Other types of clays, such as illite, chlorite, montmorillonite are significantly more hydrophilic, but tend to be pore-linig offering potentially more uniform wettability reversal at larger scales.

tern discussed above in 13 days aged sample, Fig. 12 [a]. We found no evidence of ruptured water lenses in samples aged in oil OM.2 (13 and 52 days). Oil OM.3 demonstrated low wettability alteration capacity and SEM show exposed quartz in both investigated samples (aged 13 and 52 days) - circled areas on Fig. 12 [b,c] as well as kaolinite surface Fig. 12 [f]. Potentially this may be a major micron-scale mechanism behind observed ageing time dependent surface relaxivity and wettability of sandstone rock minerals. The third and the largest-scale source of wettability heterogeneity may be related to chemical gradient defined by clay distribution pattern and their local chemistry and morphology. Above we already mentioned that even a small fraction of kaolinite in Bentheimer sandstone is the main contributor to surface area. Kaolinite has three types of surfaces: (001) silica and (001) alumina basal surfaces and (010) gibbsite edge surface, each representing approximately a third of total surface area. However, should we consider the whole surface area as participating in the ageing process? There is no simple answer to this question. While the edge surface of kaolinite is more "asphaltene hungry" comparing to basal ones (Fig. 12 [d]) due to its ability to established bonds with both positive and negative polar groups, that difference is likely not so critical comparing to the morphological nature of surface area. It is easy to calculate that kaolinite particles approximately 10 times larger across (often 5 µm or more) than the particle size required to match surface area returned by gas adsorption measurements. Fig. 12 [e] shows authigenic book-like type of kaolinite in sandstone typically fully filling selected pores. The vast majority of surface area of such kaolinite is in the highly uneven side surface containing all three chemically distinct surface types. Kaolinite crystals exhibit several types of structural defects (layers dislocation, lateral layer termination and deformation) leading to a various spacing between the perfect crystalline kaolinite plates ranging from angstromscale stacking faults to near micron size openings between deformed large plates. This provides kaolinite with a certain size-selection ad-

Conclusion We designed a set of magnetic resonance experiments integrating low-field relaxometry, proton chemical shift spectroscopy and electron spin resonance into time series capturing the dynamics of the rock ageing process. We qualified components of ageing fluids associated with different regimes of adsorption kinetics (and wettability alteration), evaluated the contribution of metals, thus enabling estimates of the socalled optimum ageing time. The importance of vanadyl complexes as a signature of asphaltene reactivity was confirmed. Vanadyls likely control the aggregation of asphaltenes and porescale accumulation in rocks. On the other hand, free radicals define the early-stage adsorption on solid surfaces, a process following a pseudosecond order adsorption model. The widelyaccepted Yen-Mullins model of hierarchical asphaltene aggregation 106 predicts cluster formation of approximately 5 nm in size. However, much larger sizes of cluster networks are frequently experimentally observed (50 to 300 nm across), e.g. Peréz-Hernández et al. 107 , Tanaka et al. 108 , Trejo et al. 109 , Behbahani et al. 110 , Shikhov et al. 54 . There is no detailed theory proposed (other than in general interaction of asphaltene clusters with maltenes) to explain the formation of such large aggregates. Results of this work support the involvement of the aliphatic fraction of ageing fluid in the for-


22

Page 23 of 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

mation of deposits, especially at the late stage when large clusters in question tend to form, which leads to a characteristic footprint in observed relaxivity evolution. We classified the ageing process into three phenomenologically different stages (a concept depicted in Fig. 10 [b]):

UNSW for thermogravimetric elemental analysis and Dr. Yin Yao from Electro Microscope Unit, MWAC UNSW for assisting with FESEM.

(i) initial discontinuous asphaltene layer formation following PSO kinetics resulting in relatively fast wettability change; the layer is discontinuous due to grain surface roughness;

(1) Yan, J.; Plancher, H.; Morrow, N. R. Wettability changes induced by adsorption of asphaltenes. SPE Prod. & Facil. 1997, 12, 259–266.

References

(2) Minssieux, L.; Nabzar, L.; Chauveteau, G.; Longeron, D.; Bensalem, R. Permeability damage due to asphaltene deposition: Experimental and modeling aspects. Rev. IFP 1998, 53, 313–327.

(ii) the withdrawal from the ageing fluid of the most active compounds triggers change in deposit chemistry resulting in formation of asphaltene micelle containing aliphatic molecules; the most complete wettability alteration step occurs during this stage;

(3) Sripal, E.; James, L. A. Application of an optimisation method for the restoration of core samples for SCAL experiments Part II. 31th Int. Symp. Soc. Core Analysts. Vienna, Austria, 2017; pp 1–14.

(iii) intense formation of aliphatic-rich macroaggregates changes rock morphology an undesired effect for the purpose of rock core analysis; accumulated aggregates provide effective relaxation environment of saturating fluids on metal porphyrins, significantly increasing apparent surface relaxivity without contributing to surface oil wetness.

(4) Anderson, W. G. Comparison of coalderived and petroleum asphaltenes by 13 C nuclear magnetic resonance, DEPT, and XRS. Soc. Pet. Eng. J. 1986, 38, 1125–1144. (5) Zhou, X.; Morrow, N. R.; Ma, S. Interrelationship of wettability, initial water saturation, aging time, and oil recovery by spontaneous imbibition and waterflooding. Soc. Pet. Eng. J. 2000, 5, 199–207.

Results provide an insight into wettability reversal phenomena in rocks and may be useful for the design of representative laboratory special core analysis experiments and reservoir quality evaluation. A particular outcome is the definition of an end-point surface relaxivity reference for NMR wettability index definitions, e.g. ageing to the end of stage (ii), which may also be taken as an optimal ageing time.

(6) Hopkins, P. A.; Strand, S.; Puntervold, T.; Austad, T.; Dizaj, S. R.; Waldeland, J. O.; Simonsen, J. C. The adsorption of polar components onto carbonate surfaces and the effect on wetting. J. Petr. Sc. Eng. 2016, 147, 381–387.

Acknowledgement The authors acknowledge the Australian Research Council (LE120100162, FT120100216) and the member companies of the UNSW NMR satellite to the ANU/UNSW Digital Core Consortium for their support. Authors wish to thank Dr. Rebeya Akter from ICP Laboratory, SSEAU MWAC UNSW for conducting Inductively Plasma elemental analysis, Dr. Sarah Kelloway from Xray Fluorescence Laboratory, SSEAU MWAC

(7) Buckley, J. S.; Liu, Y.; Monsterleet, S. Mechanisms of wetting alteration by crude oils. SPE J. 1998, 3, 54–61. (8) García, M. Crude oil wax crystallization. The effect of heavy n-paraffins and flocculated asphaltenes. Energy & Fuels 2000, 14, 1043–1048.


23

Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 24 of 30

Ueda, M.; Al-Mutairi, A.; Marafi, A.; Park, J.; Yoon, S.; Mochida, I. Studying rotational mobility of V=O complexes in atmospheric residues and their resins and asphaltenes by electron spin resonance. Energy & Fuels 2017, 31, 4748–4757.

(9) Kriz, P.; Andersen, S. I. Effect of asphaltenes on crude oil wax crystallization. Energy & Fuels 2005, 19, 948–953. (10) Ariza-Léon, E.; Molina-Velasco, D.; Chaves-Guerrero, A. Review of studies on asphaltene - wax interaction and the effect thereof on crystallization. CT&F - Ciencia, Tecnología y Futuro 2014, 5, 39–53.

(19) Gafurov, M. R.; Volodin, M. A.; Rodionov, A. A.; Sorokina, A. T.; Dolomatov, M. Y.; Petrov, A. V.; Vakhin, A. V.; Mamin, G. V.; Orlinskii, S. B. EPR study of spectra transformations of the intrinsic vanadyl-porphyrin complexes in heavy crude oils with temperature to probe the asphaltenes’ aggregation. J. Petr. Sc. Eng. 2018, 166, 363–368.

(11) Howard, J. J. Quantitative estimates of porous media wettability from proton NMR measurements. Magn. Reson. Imag. 1998, 16, 529–533. (12) Fleury, M.; Deflandre, F. Quantitative evaluation of porous media wettability using NMR relaxometry. Magn. Reson. Imag. 2003, 21, 385–387.

(20) Morrow, N. R. Wettability and its effect on oil recovery. J. Petr. Tech. 1990, 42, 1476–1484.

(13) Looyestijn, W.; Hofman, J. Wettabilityindex determination by nuclear magnetic resonance. SPE Res. Eval. & Eng. 2006, 9, 146–153.

(21) Kim, S. T.; Boudh-Hir, M.; Monsoori, G. A. The role of asphaltene in wettability reversal. Proc. SPE Ann. Tech. Conf. & Exhib. New Orleans, USA, 1990; pp 799–809.

(14) Dickinson, E. M. Structural comparison of petroleum fractions using proton and 13 C n.m.r. spectroscopy. Fuel 1980, 59, 290–294.

(22) Kaminski, R.; Radke, C. J. Asphaltenes, water films and wettability reversal. SPE J. 1997, 2, 458–493. (23) Nalwaya, V.; Tantayakom, V.; Piumsomboon, P.; Fogler, S. Studies on asphaltenes through analysis of polar fractions. Ind. Eng. Chem. Res. 1999, 38, 964–972.

(15) Majumdar, R. D.; Gerken, M.; Mikula, R.; Hazendonk, P. Validation of the Yen–Mullins model of Athabasca oil-sands asphaltenes using solution-state 1 H NMR relaxation and 2D HSQC spectroscopy. Energy & Fuels 2013, 27, 6528–6537.

(24) Subramanian, S.; Simon, S.; Gao, B.; Sjöblom, J. Asphaltene fractionation based on adsorption onto calcium carbonate: Part 1. Characterization of subfractions and QCM-D measurements. Coll. Surf. A: Physiochem. Eng. Aspects 2016, 495, 136–148.

(16) Fergoug, T.; Bouhadda, Y. Determination of Hassi Messaoud asphaltene aromatic structure from 1 H & 13 C NMR analysis. Fuel 2014, 115, 521–526. (17) Espinosa, P. M.; Campero, A.; Salcedo, R. Electron spin resonance and electronic structure of vanadyl-porphyrin in heavy crude oils. Inorganic Chem. 2001, 40, 4543–4549.

(25) Subramanian, S.; Sørland, G. H.; Simon, S.; Xu, Z.; Sjöblom, J. Asphaltene fractionation based on adsorption onto calcium carbonate: Part 2. Selfassociation and aggregation properties. Coll. Surf. A: Physiochem. Eng. Aspects 2017, 514, 79–90.

(18) Cui, Q.; Nakabayashi, K.; Ma, X.; Miyawaki, J.; Ideta, K.; Tennichi, Y.;


24

Page 25 of 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

(26) Hortal, A. E.; Hurtado, P.; MartinezHaya, B.; Mullins, O. C. Molecularweight distributions of coal and petroleum asphaltenes from laser desorption/ionization experiments. Energy & Fuels 2007, 21, 2863–2868.

(34) Clutter, D. R.; Petrakis, L.; Stenger, Jr., R. L.; Jensen, R. K. Nuclear magnetic resonance spectrometry of petroleum fractions. Carbon-13 and proton nuclear magnetic resonance characterizations in terms of average molecule parameters. Anal. Chem. 1972, 44, 1395–1405.

(27) Gawrys, K. L.; Specker, P. M.; Kilpatrick, P. K. The role of asphaltene solubility and chemical composition on asphaltene aggregation. Petr. Sci. & Technol. 2003, 21, 461–489.

(35) Rousseau, B.; Fuchs, A. H. Determination of average molecular weights of high-boiling aromatic oil fractions by 13 C and 1 H nuclear magnetic resonance. Fuel 1989, 68, 1158–1161.

(28) Wattana, P.; Fogler, H. S.; Yen, A.; Carcia, M. D. C.; Carbognani, L. Characterization of polarity-based asphaltene subfractions. Energy & Fuels 2005, 19, 101– 110.

(36) Artok, L.; Su, Y.; Hirose, Y.; Hosokawa, M. Structure and reactivity of petroleum-derived asphaltene. Energy & Fuels 1999, 13, 287–296.

(29) Semple, K. M.; Cyr, N.; Fedorak, P. M.; Westlake, D. W. S. Characterization of asphaltenes from Cold Lake heavy oil: variations in chemical structure and composition with molecular size. Can. J. Chem. 1990, 68, 1092–1099.

(37) Siskin, M.; Kelemen, S. R.; Eppig, C. P.; Brown, L. D.; Afeworki, M. Asphaltene molecular structure and chemical influences on the morphology of coke produced in delayed coking. Energy Fuels 2006, 20, 1227–1234.

(30) Lisitza, N. V.; Freed, D. E.; Sen, P. N.; Song, Y. Q. Study of asphaltene nanoaggregation by nuclear magnetic resonance (NMR). Energy & Fuels 2009, 23, 1189– 1193.

(38) Majumdar, R. D.; Gerken, M.; Hazendonk, P. Solid-state 1 H and 13 C nuclear magnetic resonance spectroscopy of Athabasca oil sands asphaltenes: Evidence for interlocking π-stacked nanoaggregates with intercalated alkyl side chains. Energy & Fuels 2015, 29, 2790– 2800.

(31) Seshdari, K. S.; Yound, D. C.; Cronauer, D. C. Characterization of coal liquids by 13 C n.m.r. and FT-i.r. spectroscopy - fractions of oils of SRC-I and asphaltenes and preasphaltenes of SRC-I and SRC-II. Fuel 1985, 64, 22–28.

(39) Silva, S. L.; Silva, A. M. S.; Ribeiro, J. C.; Martins, F. G.; Da Silva, F. A. Chromatographic and spectroscopic analysis of heavy crude oil mixtures with emphasis in nuclear magnetic resonance spectroscopy: A review. Anal. Chim. Acta 2011, 707, 18–37.

(32) Pekerar, C.; Lehman, T. Mobility of asphaltene samples studied by spectroscopy. Energy & Fuels 1999, 13, 305– 308.

(40) Zielinski, L.; Saha, I.; Freed, D. E.; Hürlimann, M. D. Probing asphaltene aggregation in native crude oils with low-field NMR. Langmuir 2010, 26, 5014–5021.

(33) Acevedo, S.; Gutierres, L. B.; Negrin, G.; Pereira, J. C. Molecular weight of petroleum asphaltenes: A comparison between mass spectrometry and vapor pressure osmometry. Energy & Fuels 2005, 19, 1548–1560.

(41) Zielinski, L.; Hürlimann, M. D. Nuclear Magnetic Resonance dispersion of distributions as a probe of aggregation in


25

Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 26 of 30

(49) Benamsili, L.; Korb, J.-P.; Hamon, G.; Louis-Joseph, A.; Bouyssiere, B.; Zhou, H.; Bryant, R. G. Multidimensional Nuclear Magnetic Resonance characterizations of dynamics and saturations of brine/crude oil/mud filtrate mixtures confined in rocks: The role of asphaltenes. Energy & Fuels 2014, 28, 1629–1640.

crude oils. Energy & Fuels 2011, 25, 5090–5099. (42) Gonzalez, V.; Taylor, S. E. Asphaltene adsorption on quartz sand in the presence of pre-adsorbed water. J. Coll. Interface Sci. 2016, 480, 137–145. (43) Espinat, D.; Gaulier, F.; Norrant, F.; Barbier, J.; Guichard, B.; Rivallan, M.; Levitz, P. Characterization of asphaltenes in solution and inside the pores of catalysts by 1 H NMR relaxometry. Energy & Fuels 2017, 30, 7382–7395.

(50) Vorapalawut, N.; Nicot, B.; LouisJoseph, A.; Korb, J.-P. Probing dynamics and interaction of maltenes with asphaltene aggregates in crude oils by multiscale NMR. Energy & Fuels 2015, 29, 4911–4920.

(44) Singer, P. M.; Asthagiri, D.; Chapman, W. G.; Hirasaki, G. J. Molecular dynamics simulations of NMR relaxation and diffusion of bulk hydrocarbons and water. J. Magn. Res. 2017, 277, 15–24.

(51) Silva, H. S.; Sodero, A. C. R.; Korb, J.-P.; Alfara, A.; Guisti, P.; Vallverdu, G.; Bégué, D.; Baraille, I.; Bouyssiere, B. The role of metalloporphyrins on the physical-chemical properties of petroleum fluids. Fuel 2017, 188, 374–381.

(45) Singer, P. M.; Asthagiri, D.; Chapman, W. G.; Hirasaki, G. J. Role of internal motions and molecular geometry on the NMR relaxation of hydrocarbons. J. Chem. Phys. 2018, 148, 164507:1–10.

(52) Korb, J.-P. Multiscale nuclear magnetic relaxation dispersion of complex liquids in bulk and confinement. Progress in Nucl. Magn. Reson. Spectrosc. 2018, 104, 12–55.

(46) Stapf, S.; Ordikhani-Seyedlar, A.; Ryan, N.; Mattea, C.; Kausik, R.; Freed, D. E.; Song, Y.-Q.; Hürlimann, M. D. Probing maltene– asphaltene interaction in crude oil by means of NMR relaxation. Energy & Fuels 2014, 28, 2395–2401.

(53) Biktagirov, T. B.; Gafurov, M. R.; Volodin, M. A.; Mamin, G. V.; Rodionov, A. A.; Izotov, V. V.; Vakhin, A. V.; Isakov, D. R.; Orlinskii, S. B. Electron paramagnetic resonance study of rotational mobility of vanadyl porphyrin complexes in crude oil asphaltenes: Probing the effect of thermal treatment of heavy oils. Energy & Fuels 2014, 28, 6683–6687.

(47) Stapf, S.; Ordikhani-Seyedlar, A.; Mattea, C.; Kausik, R.; Freed, D. E.; Song, Y.-Q.; Hürlimann, M. D. Fluorine tracers for the identification of molecular interaction with porous asphaltene aggregates in crude oil. Micropor. Mesopor. Mater. 2015, 205, 56–60.

(54) Shikhov, I.; Li, R.; Arns, C. H. Relaxation and relaxation exchange NMR to characterise asphaltene adsorption and wettability dynamics in siliceous systems. Fuel 2018, 220, 692–705.

(48) Ordikhani-Seyedlar, A.; Neudert, O.; Stapf, S.; Mattea, C.; Kausik, R.; Freed, D. E.; Song, Y.-Q.; Hürlimann, M. D. Evidence of aromaticityspecific maltene NMR relaxation enhancement promoted by semiimmobilised radicals. Energy & Fuels 2016, 30, 3886–3893.

(55) Shikhov, I.; Thomas, D. S.; Rawal, A.; Yao, Y.; Gizatullin, B.; Hook, J. M.; Stapf, S.; Arns, C. H. Application of


26

Page 27 of 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

low-field, 1 H/13 C high-field solution and solid state NMR for characterisation of oil fractions responsible for wettability change in sandstones. Magn. Reson. Imaging 2018, 56, 77–85.

petroleum products by thin layer chromatography and flame ionization detection; Energy Institute: London, UK, 2006. (64) Alboudwarej, H.; Akbarzadeh, K.; Beck, J.; Svrcek, W. Y.; Yarranton, H. W. Regular solution model for asphaltene precipitation from bitumens and solvents. AIChE J. 2003, 49, 2948–2956.

(56) Brantley, S. L.; Mellott, N. P. Surface area and porosity of primary silicate minerals. Am. Mineralogist 2000, 85, 1767– 1783. (57) Shikhov, I.; Li, R.; Arns, J.; Arns, C. H. T2 -store-T2 relaxation exchange NMR to characterize effect of asphaltenes on wettability dynamics in siliceous systems. 31th Int. Symp. Soc. Core Analysts. Vienna, Austria, 2017; pp 1–12.

(65) Andrews, A. B.; Edwards, J. C.; Pomerantz, A. E.; Mullins, O. C.; Nordlund, D.; Norinaga, K. Comparison of coal-derived and petroleum asphaltenes by 13 C nuclear magnetic resonance, DEPT, and XRS. Energy & Fuels 2011, 25, 3068– 3076.

(58) ASTM D4124-09(2018), Standard test method for separation of asphalt into four fractions; ASTM International: West Conshohocken, PA, USA, 2018; Vol. 04.03.

(66) Majumdar, R. D.; Bake, K. D.; Ratna, Y.; Pomerantz, A. E.; Mullins, O. C.; Gerken, M.; Hazendonk, P. Single-core PAHs in petroleumand coal-derived asphaltenes: Size and distribution from solid-state NMR spectroscopy and optical absorption measurements. Energy & Fuels 2016, 30, 6892–6906.

(59) ASTM D6560-12, Standard test method for determination of asphaltenes (heptane insolubles) in crude petroleum and petroleum products; ASTM International: West Conshohocken, PA, USA, 2012; Vol. 05.03.

(67) Ancheyta, J.; Centeno, G.; Trejo, F.; Marroquín, G.; J. A. García, E. T.; Torres, A. Extraction and characterization of asphaltenes from different crude oils and solvents. Energy & Fuels 2002, 16, 1121–1127.

(60) EI IP143:2004, Determination of asphaltenes (heptane insolubles) in crude petroleum and petroleum products; Energy Institute: London, UK, 2016. (61) ASTM D2007-11, Standard test method for characteristic groups in rubber extender and processing oils and other petroleum-derived oils by the clay-gel absorption chromatographic method ; ASTM International: West Conshohocken, PA, USA, 2016; Vol. 05.01.

(68) Fan, T.; Buckley, J. S. Rapid and accurate SARA analysis of medium gravity crude oils. Energy & Fuels 2002, 16, 1571–1575. (69) Jameel, A. G. A.; Elbaz, A. M.; Emwas, A.-H.; Roberts, W. L.; Sarathy, S. M. Calculation of average molecular parameters, functional groups, and a surrogate molecule for heavy fuel oils using 1 H and 13 C nuclear magnetic resonance spectroscopy. Energy & Fuels 2016, 30, 3894–3905.

(62) EI IP368:2001, Determination of hydrocarbon types in lubricating oil basestocks Preparative high performance liquid chromatography method ; Energy Institute: London, UK, 2006. (63) EI IP469:2001, Determination of saturated, aromatic and polar compounds in


27

Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

(70) Woods, J.; Kung, J.; Kingston, D.; Koltyar, L.; Sparks, B.; McCracken, T. Canadian crudes: A comparative study of SARA fractions from a modified HPLC separation technique. Oil & Gas Sci. and Technol. - Rev. IFP 2008, 63, 59–72.

Page 28 of 30

(80) Lagergren, S. Zur theorie der sogenannten adsorption gelöster stoffe. About the theory of so-called adsorption of soluble substanses. K. Svenska Vetenskapsakad. Handl. 1898, 24, 1–39. (81) Blanchard, G.; Maunaye, M.; Martin, G. Removal of heavy metals from waters by means of natural zeolite. Water Res. 1984, 18, 1501–1507.

(71) Molina V, D.; Uribe, U. N.; Murgich, J. Correlations between SARA fractions and physiochemical properties with 1 H NMR spectra of vacuum residues from Colombian crude oils. Fuel 2010, 89, 185–192.

(82) Weber, W. J.; Morris, J. C. Kinetics of adsorption of carbon from solution. J. Sanitary Eng. Div., ASCE 1963, 89, 31– 60.

(72) Sanchez-Minero, F.; Ancheyta, J.; SilvaOliver, G.; Flores-Valle, S. Predicting SARA composition of crude oil by means of NMR. Fuel 2013, 110, 318–321.

(83) Leu, Y.; Shen, L. From Langmuir kinetics to first- and second-order rate equations for adsorption. Langmuir 2008, 24, 11625–11630.

(73) Carr, H. Y.; Purcell, E. M. Effects of diffusion on free precession in nuclear magnetic resonance problems. Phys. Rev. 1954, 94, 630–638.

(84) Kokal, S.; Tang, T.; Schramm, L.; Sayegh, S. Electrokinetic and adsorption properties of asphaltenes. Coll. Surf. A. Physiocchem. Eng. Aspects 1995, 94, 253–265.

(74) Meiboom, S.; Gill, D. Modified spin-echo method for measuring nuclear relaxation times. Rev. Sci. Instru. 1958, 29, 688– 691.

(85) Alboudwarej, H.; Pole, D.; Svrcek, W. Y.; Yarranton, H. W. Adsorption of asphaltenes on metals. Ind. Eng. Chem. Res. 2005, 44, 5585–5592.

(75) Fordham, E. J.; Venkataramanan, L.; Mitchell, J.; Valori, A. What are, and what are not, Inverse Laplace Transforms. Diffusion Fundamentals 2017, 29, 1–8.

(86) Nassar, N. N. Asphaltene adsorption onto alumina nanoparticles: Kinetics and thermodynamic studies. Energy & Fuels 2010, 24, 4116–4122.

(76) Lawson, C. L.; Hansen, R. J. Solving Least Squares Problems; Prentice-Hall: New-Jersey, 1974.

(87) Brunauer, S.; Emmett, P. H.; Teller, E. Adsorption of gases in multimolecular layers. J. Am. Chem. Soc. 1938, 60, 309– 319.

(77) Hansen, P. C. Numerical tools for analysis and solution of Fredholm integral equations of the first kind. Inverse Problems 1992, 8, 849–872.

(88) Syunyaev, R. Z.; Balabin, R. M.; Akhatov, I. S.; Safieva, J. O. Adsorption of petroleum asphaltenes onto reservoir rock sands studied by near-infrared (NIR) spectroscopy. Energy & Fuels 2009, 23, 1230–1236.

(78) Burdine, N. T. Relative permeability calculations from pore size distribution data. AIME Petroleum Trans. 1953, 198, 71–78. (79) Brooks, R. H.; Corey, A. T. Hydraulic properties of porous media. Hydrological Papers, Colorado St. U. 1964, 3, 1–27.

(89) Saraji, S.; Goual, L.; Piri, M. Adsorption of asphaltenes in porous media under


28

Page 29 of 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

measurements using high throughput experimentation methods. 32nd Int. Symp. Soc. of Core Analysts. Trondheim, Norway, 2018; pp 1–12.

flow conditions. Energy & Fuels 2010, 24, 6009–6017. (90) Mullins, O. C. et al. Advances in asphaltene science and the Yen-Mullins model. Energy & Fuels 2012, 26, 3986–4003.

(100) Parker, D. S.; Burnett, J. F. Dipolar spin-lattice relaxation in water containing oxygen. Chem. Phys. Let. 1974, 25, 505–506.

(91) Goual, L. Impedance spectroscopy of petroleum fluids at low frequency. Energy & Fuels 2009, 23, 2090–2094.

(101) Mutina, A. R.; Hürlimann, M. D. Effect of oxygen on the NMR relaxation properties of crude oils. Appl. Magn. Reson. 2005, 29, 503–513.

(92) Simon, S.; Jestin, J.; Palermo, T.; Barré, L. Relation between solution and interfacial properties of asphaltene aggregates. Energy & Fuels 2009, 23, 306–313. (93) Stachowiak, C.; Viguié, J.-R.; Grolier, J.P. E.; Rogalski, M. Effect of n-alkanes on asphaltene structuring in petroleum oils. Langmuir 2005, 21, 4824–4829.

(102) Shikhov, I.; Arns, C. H. Temperaturedependent oxygen effect on NMR D − T2 relaxation-diffusion correlation of nalkanes. Appl. Magn. Reson. 2016, 47, 1391–1408.

(94) Orea, M.; Ranaudo, M. A.; Lugo, P.; López, L. Retention of alkane compounds on asphaltenes. Insights about the nature of asphaltene-alkane interactions. Energy & Fuels 2016, 30, 8098–8113.

(103) Asay, D. B.; Kim, S. H. Evolution of the adsorbed water layer structure on silicon oxide at room temperature. J. Phys. Chem. B 2005, 109, 16760–16763.

(95) Majumdar, R. D.; Montina, T.; Mullins, O. C.; Gerken, M.; Hazendonk, P. Insights into asphaltene aggregate structure using ultrafast MAS solid-state 1 H NMR spectroscopy. Fuel 2017, 193, 359–368.

(104) Chen, J.; Chen, J.; Zhong, C.; Chen, S.; Chen, B.; Fang, S.; Xiang, W. Mesoscopic probes in asphaltenes nanoaggregate structure: from perpendicular to paralleled orientation at the water-in-oil emulsions interface. RSC Adv. 2017, 7, 38193:1–11.

(96) Aires-de-Souza, J.; Hemmer, M. C.; Gasteiger, J. Prediction of 1 H NMR chemical shifts using neural networks. Anal. Chem. 2002, 74, 80–90.

(105) Huang, X.; Yutkin, M. P.; Hassan, S.; aMartin J. Blunt, J. W. Asphaltene adsorption from toluene onto silica through thin water Layers. Langmuir 2019, 35, 428–434.

(97) Banfi, D.; Patiny, L. Resurrecting and processing NMR spectra on-line. Chimia 2008, 62, 280–281.

(106) Mullins, O. C. The modified Yen model. Energy & Fuels 2010, 24, 2179–2207.

(98) Castillo, A. M.; Patiny, L.; Wist, J. Fast and accurate algorithm for the simulation of NMR spectra of large spin systems. J. Magn. Reson. 2011, 209, 123– 130.

(107) Peréz-Hernández, R.; MendozaAnaya, D.; Mondragón-Galicia, G.; Espinosa, M. E.; Rodríguez-Lugo, V.; Lozada, M.; Arenas-Alotorre, J. Microstructural study of asphaltene precipitated with methylene chloride and n-hexane. Fuel 2003, 82, 977–982.

(99) Mascle, M.; Youssef, S.; Deschamps, H.; Vizika, O. In-situ investigation of ageing protocol effect on relative permeability


29

Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

(108) Tanaka, R.; Sato, E.; Araki, T. Characterization of asphaltene aggregates using X-ray diffraction and small-angle Xray scattering. Energy & Fuels 2004, 18, 1118–1125. (109) Trejo, F.; Ancheyta, J.; Rana, M. S. Structural characterization of asphaltenes obtained from hydroprocessed crude oils by SEM and TEM. Energy & Fuels 2009, 23, 429–439. (110) Behbahani, T. J.; Ghotbi, C.; Taghikhani, V.; Shahrabadi, A. Asphaltene deposition under dynamic conditions in porous media: Theoretical and experimental investigation. Energy & Fuels 2013, 27, 622–639.


30

Page 30 of 30

On the optimum ageing time - magnetic resonance study of

Recommend Documents