Rapid Dissolution of Cinnabar in Crude Oils at Reservoir

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Rapid Dissolution of Cinnabar in Crude Oils at Reservoir Temperatures Facilitated by Reduced Sulfur Ligands Lars Lambertsson, Charles J Lord, Wolfgang Frech, and Erik Björn ACS Earth Space Chem., Just Accepted Manuscript • DOI: 10.1021/ acsearthspacechem.8b00096 • Publication Date (Web): 28 Aug 2018 Downloaded from http://pubs.acs.org on August 31, 2018

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ACS Earth and Space Chemistry

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Rapid Dissolution of Cinnabar in Crude Oils at Reservoir Temperatures

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Facilitated by Reduced Sulfur Ligands

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Lars Lambertsson1, Charles J Lord2, Wolfgang Frech1 and Erik Björn1,*

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Department of Chemistry, Umeå University, S-901 87 Umeå, Sweden

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ConocoPhilips, 315 S Johnstone Ave, Bartlesville, OK 74004, USA

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∗

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Erik Björn

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Department of Chemistry, Umeå University, S-901 87 Umeå, SWEDEN.

Corresponding author present address:

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Tel: +46907865189

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Email: [email protected]

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Keywords: mercury, crude oil, cinnabar, dissolution kinetics, thiol compounds

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Abstract

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Mercury (Hg) is present in petrochemical samples, including crude oils, and the processing and use of

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petroleum products contribute to global Hg emissions. We present a refined theory on geochemical

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processes controlling Hg concentrations in crude oil by studying dissolution kinetics and solubility

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thermodynamics of cinnabar (α-HgS(s)) in different crude oils held at reservoir temperatures. In a

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black light crude oil, α-HgS(s) dissolved in an apparent zero-order reaction with a rate of 0.14-0.58

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µmoles m-2 s-1 at 170-230 °C and an estimated activation energy of 43 kJ mole-1. For crude oil samples

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with a total sulfur concentration spanning 0.15-2.38% (w/w) the measured dissolution rate varied

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between 0.05-0.24 µmoles m-2 s-1 at 200 °C. Separate tests showed that thiols and, to a lesser extent,

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organic sulfides increased the solubility of α-HgS(s) in isooctane at room temperature compared to

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thiophenes, disulfides and elemental sulfur. Long-term (14 days) α-HgS(s) solubility tests in a crude 1 ACS Paragon Plus Environment

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oil at 200 °C generated dissolved Hg concentrations in the 0.3% (w/w) range. The high α-HgS(s)

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dissolving capacity of the crude oils was more than two orders of magnitude greater than the highest

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reported Hg concentration in crude oils globally. Based on the kinetic and solubility data it was

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further concluded that α-HgS(s) is not stable under typical petroleum reservoir conditions and would

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decompose to elemental mercury (Hg0). Our results suggest that source/reservoir temperature,

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abundance of reduced sulfur compounds in the crude oil, and dissolved Hg0 evasion processes are

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principal factors controlling the ultimate Hg concentration in a specific crude oil deposit.

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Introduction

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In crude oil, mercury (Hg) exists in widely varying concentrations1 and in several different chemical

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forms associated with specific oil fractions. Mercury concentrations and its chemical forms vary with

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geographic location and depth of exploitation as well as with physical and chemical conditions

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prevailing during oil production and transport. The most prominent Hg compounds found in crude

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oils are elemental Hg (Hg0) and various forms of inorganic mercuric Hg (Hg2+), e. g. Hg chlorides,

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sulfides or oxides.2-5 It is estimated that production and processing of crude oil contributes about 1%

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of the anthropogenic atmospheric Hg emissions worldwide.6 Despite this relatively small global

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contribution, the emissions occur at point sources and should be managed to limit local Hg releases.

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Further, managing the financial and operational risks associated with mercury in upstream and

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downstream crude oil operations represents a significant task for the petrochemical industry.

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Mercury is known to adversely affect the integrity of process equipment such as cryogenic aluminum

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heat exchangers and compressor seals, and is a potential threat to the health and safety of workers

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and the environment.2 In addition, the presence of Hg above a certain concentration can negatively

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impact the commercial value of a crude oil.7

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To date there is little information in the literature concerning the source and absorption mechanisms

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of Hg in crude oil.8 Atmospheric Hg deposition prior to petroleum formation has been suggested and 2 ACS Paragon Plus Environment

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contributes to Hg in crude oil deposits globally. It has further been argued that enhanced crude oil Hg

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concentrations are a result of secondary geological processes, such as interactions with metalliferous

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fluids and formation waters that mobilize Hg from the source rock, where it is present predominantly

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as cinnabar (α-HgS(s)), and transfer it to the reservoir.9 Gas phase Hg transfer to the crude oil

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reservoir through mantle degassing at high pressure and temperature has been proposed as another

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transfer process of Hg to crude oils.3, 10 As a consequence of these different processes large variation

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in concentrations (0.1–2×104 ng g-1) of Hg in crude oils are observed worldwide.10 Globally, the

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highest Hg levels in crude oils are typically associated with areas that were volcanically active during

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the deposition and early diagenesis of source and/or reservoir rocks. Examples of such areas are the

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Pacific coast of South America, Southeast Asia and the North Sea.11

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In contrast to crude oil systems, the solubility of α-HgS(s) and of metacinnabar (β-HgS(s)) in aqueous

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systems is relatively well documented and can be useful for the understanding of HgS(s) solubility

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processes in crude oil. From several published studies it is well documented that HgS(s) has a very

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low solubility in natural waters at typical conditions, but still there is environmental concern that at

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high concentrations of dissolved sulfide and/or thiols, a significant fraction of HgS(s) mercury could

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form dissolved complexes and enter into biological food webs. Reactions leading to dissolution of

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HgS(s) in the presence of dissolved sulfide and various types of natural dissolved organic matter

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(DOM) have therefore been investigated and the rate of HgS(s) dissolution has been quantified. For

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example, Paquette and Helz12 proposed the formation of several mercury-sulfide complexes of the

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type HgS2Hnn-2 during dissolution of α-HgS(s). They concluded that HgS(s) reversibly dissolves in

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sulfidic solutions to form Hg(SH)20, HgS2H-, HgS22-, within the pH range 4-10. Equilibrium constants for

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HgS(s) ↔ HgII(aq), for the dissolved Hg-complexes above, were found to be in the range 10-4,8 to 10-

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13,4

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soils, and its effects on sulfide oxidation which enhanced the dissolution of cinnabar. Waples et al.14

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measured the initial dissolution rate of α-HgS(s) in the presence of different types of DOM and found

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rates in the range of 2.31×10-13 to 7.16×10-12 mol Hg (mg C)-1 m-2 s-1.

. Ravichandran et al.13 studied the interactions of DOM with α-HgS cations in natural waters and

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Crude oils contain sulfur in concentrations between 0.1 and 10% (w/w) depending on their

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composition. Typically, light oils (API gravity >31.1°) are low in total sulfur content (sweet, 300 bar by the manufacturer.

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Bulk crude oil samples (5-50 g) were prepared in screw top borosilicate glass vials. For α-HgS(s)

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dissolution rate measurements α-HgS(s) (the surface area was 1.01 m2 g-1 determined by BET N2

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adsorption) was added to the samples at concentrations ranging between 0.04-10000 µg g-1.

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Appropriate amounts, depending on the added α-HgS(s) concentration and original total Hg

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concentration in the sample, of a

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HgCl2 toluene solution for isotope dilution (ID) calibration were 5

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then added. The samples were subsequently mixed on a shaker table for 30 min after which 0.5 g

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aliquots of the bulk samples were pipetted into the micro autoclaves. For heat treatment, the

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autoclaves were placed in a GC oven and heated from 30 °C up to temperatures between 170-230 °C

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at 40 °C min-1 and left at the experiment temperature for 0.3 to 96 h. At preselected heating times,

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the micro autoclaves were removed from the oven and placed in a freezer (-20 °C) for 15 min. After

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cooling the autoclaves were opened and 0.15 g aliquots were transferred to 2 ml crimp top GC vials,

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capped and stored at -20 °C until analysis. Between sample treatments the micro autoclaves were

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conditioned at 550 °C with one cap off for 4 h to remove residual Hg.

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An Agilent 7890 GC coupled to an Agilent 7700x ICP-MS was used. The GC auto sampler was fitted

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with either a 10 or 100 μl gas tight syringe that was set at a sampling depth offset of 25 mm to

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sample only the headspace of the sample vials. The auto sampler was programmed to condition the

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syringe with the sample vial headspace through three sample pump cycles before injecting 1-50 μl of

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gas. The multi-mode GC inlet was operated in pulsed splitless or pulsed split mode (1:20 split ratio)

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with a pulse pressure of 65 psi for 10 s. All GC separations were done isothermally at 80 °C. Sample

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vials were conditioned at 60 °C for 5 minutes prior to analysis in order to increase the Hg0 vapor

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pressure.

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Method Validation

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The accuracy of the headspace method was validated by analyzing several different unfiltered crude

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oils of varying geological origin and composition (Table 1) using 1 h heating time at 200 °C and

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comparing the results with those obtained by combustion atomic absorption spectrometry (C-AAS)

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analyzes (for the same samples excluding the

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differences between the C-AAS reference and the ID-HS-GC-ICPMS results were observed (Table 2).

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Procedural method blanks were prepared with isooctane and measured at 0.03±0.01 ng g-1 (n=3)

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rendering a method detection limit of 0.03 ng g-1 (3σ).

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HgCl2 addition). In most samples no significant


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The results for the tested crude oil samples showed that accurate total Hg concentrations could be

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determined in crude oils of varying geological origin and composition with the developed headspace

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method (Table 2).

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Solubility of Inorganic Hg Compounds in Model Solvent Systems

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The solubilities of α-HgS(s) and HgO(s) (purity of each salt >99%) in different solvent solutions were

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determined using a shake flask method according to USEPA product properties test guidelines OPPTS

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830.7840.19 Briefly, about 25 mg portions of α-HgS(s) or HgO(s) were weighed in 12 ml borosilicate

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glass centrifuge tubes. To this was added about 4.5 g of either heptane or isooctane (p. a. grade or

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better) solutions of selected reduced sulfur compounds of p. a. quality (500 µg g-1 as S of either n-

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octyl thiol (C8H18S, CAS#: 111-88-6), n-dodecyl thiol (C12H26S, CAS#: 112-55-0), thiophene (C4H4S,

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CAS#: 110-02-1), tetrahydro thiophene (C4H8S, CAS#: 110-01-0), 2,5 dimethyl thiophene (C6H8S,

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CAS#: 638-02-8), diphenyl sulfide ((C6H5)2S, CAS#: 139-66-2), dioctyl sulfide ((C8H17)2S, CAS#: 2690-08-

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6), di-sec-butyl disulfide ((C4H9)2S2, CAS#: 5943-30-6) or elemental sulfur) and the actual total S

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concentrations in the solutions were verified before, and in some cases at the end of, the experiment

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by elemental analysis (PAC Multitek). All test solutions were prepared in triplicates, to carry out each

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experiment in triplicates, and were then placed in an oven held at 40 °C for 24 h after which they

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were put on a shaker table at 23 °C for a further 120 h. From the test solutions, about 0.7 g were

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withdrawn with a plastic syringe and filtered through 0.2 µm Teflon syringe filters.

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Determination of Total Hg Concentrations in Crude Oils and Filtered Solvent Solutions

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For total Hg determinations using C-AAS, either a Milestone DMA 80, Leco AMA 254 or a Lumex RA-

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915+ AAS mercury analyzer fitted with a PYRO-915 thermal decomposition unit was used. Depending

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on the expected Hg concentrations 25-80 mg of sample were analyzed. Standard reference materials

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NIST 1633b, Mess-2, NRCC and IAEA-356, IAEA (certified total Hg concentrations of 0.1431±0.0018 µg

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g-1, 0.092±9 and 7.62±0.62 µg g-1, respectively) were used for quality assurance.

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Results and Discussion

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α-HgS(s) Dissolution Rates in Crude oils at Reservoir Temperatures

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For this study we developed a novel autoclave-based method (described above) for the

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determination of total dissolved Hg concentrations in crude oils. This method uses headspace

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sampling which, as opposed to liquid sample injection, eliminates the introduction of particulate Hg

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to the GC injector. The particulate Hg can subsequently be thermally reduced to Hg0, as was recently

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reported by Gajdosechova et al.4 as a potential source of error for Hg0 determinations in crude oils.

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By incorporating isotope dilution analysis to the method, e. g. by spiking the sample with isotope

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enriched HgCl2 prior to heat treatment, potential non-quantitative reduction yields during heat

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treatment will be corrected for independent of the partition of Hg0 in the liquid and gaseous phases.

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Lastly and of great importance for the interpretation of the results presented below, with the

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headspace approach only dissolved and reduced Hg can be detected (and measured) since α-HgS(s),

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or other low soluble Hg minerals, display insignificant vapor pressure (compared to Hg0) at the

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analysis temperature (~30 °C). Compared to conventional filtering methods in which liquid and solid

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fractions are operationally defined by filter pore size, the developed headspace approach provides an

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absolute differentiation between dissolved and solid phase Hg.

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The developed headspace method was used to measure the dissolution rate normalized to surface

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area (Vdiss, µmol Hg (m-2 α-HgS(s)) s-1) of α-HgS(s) in different crude oils at temperatures between

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170-230 °C. It should be stated that the dissolution rates presented in this work represent both

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dissolution of α-HgS(s) to ionic Hg (i.e. ionic Hg complexes with reduced sulfur compounds) and

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subsequent reduction to Hg0. However, based on our previous measurements of HgII reduction rates

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in crude oil at these temperatures,18 we conclude that α-HgS(s) dissolution is the rate-limiting step in

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the process.

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Initial tests were performed using sample A to which α-HgS(s) was added at a concentration of 45 ng

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g-1. Six subsamples for each temperature were heat treated at 170, 200 and 230 °C for 2, 1.5 and 1 h,


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respectively, with subsampling at time intervals between 10-30 min. In this crude oil, at the tested

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temperatures, the added α-HgS(s) dissolved linearly in an apparent zero-order reaction at rates

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between 0.14-0.58 µmoles m-2 s-1 (Table 3, Figure 1).

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The 200 °C experiment was repeated three times which produced an average dissolution rate of

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0.24±0.04 (95% CI) µmoles m-2 s-1. By applying the Arrhenius equation to the obtained dissolution

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rates18 the activation energy for the convolute α-HgS(s) dissolution-reduction process was estimated

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to 43 kJ mol-1. This was comparable to an activation energy of 42.3 kJ mol-1 for dissolution of cinnabar

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ore in aqueous hydrochloric acid-potassium iodide solutions at temperatures between 5-45 °C

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previously reported by Nunez and Espiell.20 The similarity in activation energies for α-HgS(s)

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dissolution between these two very different systems suggests that the dissociation of the Hg-S bond

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within the α-HgS(s) crystalline structure is the rate-limiting step in the dissolution process in both

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systems. It should be noted that the relatively low activation energies for α-HgS(s) dissolution of 43

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and 42.3 kJ mol-1 in our study and by Nunez and Espiell,20 respectively, reflect a mineral dissolution

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process that is surface-reaction controlled.

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Two types of kinetic models were developed based on the experimental data: a temperature specific

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model valid for the specific experimental temperatures (nHg =nHg +kt, where nHg is the molar

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amount Hg0 at a given time; nHg is the molar amount Hg0 at t=0; k is an empirical temperature

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specific constant as specified in Supporting Information; and t is time (s)), and a variable temperature

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model (nHg =nHg +1.69*104e(-43222/RT)t, where 1.69*104 is the frequency factor (s-1); 43222 is the

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activation energy (J mol-1); R is the universal gas constant and T is temperature (K)) that incorporated

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the thermodynamic variables activation energy (Ea) and frequency factor (A). Excellent fit was

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obtained for most samples with the temperature specific- and variable temperature models, (Table 3,

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Figures 1, S1 and S2).

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A reference heptane sample spiked with α-HgS(s) to 65 ng g-1 was run in parallel at 200 °C and in this

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sample the measured dissolution rate was 0.04 µmoles m-2 s-1. Given that the composition of sample 9 ACS Paragon Plus Environment


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A is dominated by alkanes (75%) such as heptane this suggested that heteroatom compounds

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present in the crude oil, predominantly sulfur containing molecules, played an important role in the

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dissolution and/or reduction process. We measured α-HgS(s) solubility in five different crude oils,

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including sample A, spanning a total sulfur concentration range between 0.15-2.38% (w/w). The

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resulting dissolution rates ranged between 0.05-0.24 µmoles m-2 s-1 (Table 1), however the measured

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dissolution rates showed no correlation to the total sulfur concentration.

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Solubility of Inorganic Hg Compounds in Isooctane with Added Reduced Sulfur Compounds

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The lack of correlation between total sulfur concentration and α-HgS(s) dissolution rates for the

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different tested samples indicated that the sulfur speciation rather than the total sulfur content of a

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certain crude oil will determine its ability to dissolve α-HgS(s). We therefore investigated how the

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solubility of α-HgS(s) was affected by the presence of different reduced sulfur compounds in

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isooctane solutions.

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Reduced sulfur compounds are known to form predominantly linear two-coordinated complexes

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with dissolved Hg2+ (mercaptides) and are commonly present in crude oils in the form of thiophenes,

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benzothiophenes and organic sulfides. It is reasonable that the speciation of sulfur should be of great

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importance for the solubility of inorganic Hg compounds in crude oil in the sense that differences in

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Hg complexing capacity between reduced S compound classes exist.

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Significant increases in α-HgS(s) solubility were observed in the n-octyl- and n-dodecyl thiol solutions

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at about 60-150 times higher than the intrinsic solubility of α-HgS(s) in isooctane (~1 ng g-1), Figure 3

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and Table S1. The thiols can be considered “primary” reduced sulfur compounds in which the sulfur is

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located at the terminal end of the molecule binding to a carbon and a hydrogen. Such a structure is

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likely accessible for complexation with Hg2+ at the surface of α-HgS(s) particles and subsequent

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dissolution and formation of Hg(SR)2 coordination complexes in the liquid phase.

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Enhanced α-HgS(s) solubility was also observed in the two organic sulfide solutions at a factor of

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about 40-140 higher than in the reference isooctane sample. The uncertainty in data was however 10 ACS Paragon Plus Environment

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quite large and the solubility was not statistically separated from that observed for other sulfur

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compounds. Compared to the thiols, the organic sulfides could be regarded as secondary reduced

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sulfur compounds as the sulfur binds to two carbons and are generally stable towards Hg2+ ions.19

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However, with “bulkier” substituents, like n-octyl- or phenyl groups, the tendency for thiolate ion

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formation from organic sulfides becomes greater.21 This would be more pronounced with the

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diphenyl sulfide compared to the n-octyl sulfide as the phenyl group is a more stable leaving group

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through electron delocalization. Hence a higher solubility is achieved with diphenyl sulfide. A lower

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α-HgS(s) solubility, although not significant, was observed for the di-sec-butyl disulfide compared to

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the thiols and organic sulfides. Disulfides are generally slightly less stable than organic sulfides with a

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dissociation energy of 429 kJ mol-1 for the disulfide S-S bond compared to 699 kJ mol-1 for the organic

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sulfide C-S bond,22 which in theory would result in similar but slightly higher complexing capacity of

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disulfides compared to the organic sulfides. In the case of di-sec-butyl disulfide it is possible though

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that the secondary butyl groups are sterically hindering complexation with Hg. Significantly lower

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solubilities were observed for the different thiophenes used in the experiment. Thiophenes can be

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ascribed aromatic character in which the free electron pairs on the sulfur are delocalized in the π-

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electron system. Consequently, thiophenic sulfur atoms are non-nucleophilic and are hence less

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prone to complex with Hg in the isooctane.

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A similar Hg solubility pattern as for α-HgS(s) was observed when the experiment was repeated with

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HgO(s) and different sulfur compounds in isooctane. The solubility was however generally enhanced

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for HgO(s) compared to α-HgS(s), and a particularly enhanced solubility, by three orders of

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magnitude, was observed in the thiol samples (Figure 3 and Table S1). The n-octyl thiol and n-dodecyl

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thiol yielded solubilities of 160 μg g-1 and 120 μg g-1, respectively for HgO(s). Interestingly, after the

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addition of the thiol solutions the red HgO(s) powder turned white within 1 h in both solutions. We

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calculated the reduction in thiol concentration in the solutions by measuring the residual total S

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concentration in the supernatant isooctane after the equilibration period and comparing it with the

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original total S concentration. In the n-octyl thiol solution the original S concentration was reduced by 11 ACS Paragon Plus Environment


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73% while in the n-dodecyl thiol it decreased by 85%. After the equilibration period the white

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powder was collected, dried and analyzed by X-Ray diffraction, which yielded a diffractogram void of

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crystalline structure. This observation together with an almost quantitative depletion of dissolved

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thiols in these samples indicated that organic Hg compounds (mercaptides) were formed

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spontaneously at room temperature when mixing the HgO(s) with the respective 500 μg g-1 thiol

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solution. The resulting di-octyl or di-dodecyl Hg mercaptides were obviously relatively soluble in

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alkane solvents given the very high dissolved Hg concentrations obtained for HgO(s) in the thiol

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solutions (Figure 3). Compared to the α-HgS(s) samples this resulted in a solubility increase for the

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HgO(s) thiol samples at about one order of magnitude relative to the organic sulfide samples.

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Compared to the thiols, significantly lower solubilities were observed for the organic sulfides at 18 μg

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g-1 and 5 μg g-1 for dioctyl sulfide and diphenyl sulfide, respectively, while the di-sec-butyl disulfide

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gave a solubility of 7 μg g-1. The thiophenes generated relatively uniform solubilities between 100-

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150 ng g-1. We did not observe significant increase in solubility for any Hg compound in the presence

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of S0 compared to the solvent blanks. This implies that the oxidation state of S also plays a role in

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determining the Hg complexing capacity of different S compounds in organic solution. The results on

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how the solubility of α-HgS(s) is affected by the presence of different specific reduced sulfur

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compounds in isooctane solutions form an important basis for future characterization of crude oils.

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Identification and quantification of in particular thiols and organic sulfides will be valuable to further

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advance the understanding of processes controlling Hg concentrations in crude oils.

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Geochemical processes controlling Hg concentrations in crude oil

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In a long term solubility test spanning 14 days at 200 °C using crude oil sample A spiked with α-HgS(s)

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to 1% (w/w) we measured dissolved Hg concentrations of 2920 and 3260 µg g-1 after 7 and 14 days,

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respectively. This showed that almost one third of the added α-HgS(s) dissolved within the first week

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and that this concentration did not change much with an additional 7 days at 200 °C. This suggests

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that a concentration of around 3000 µg g-1 reflected the thermodynamic dissolution capacity of α-


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HgS(s) and/or saturation of Hg0 of this particular crude oil sample. Considering that the highest global

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reported Hg concentrations in crude oils are around 20 µg g-1, from the Cymric field, CA, USA,1 our

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data suggests that the Hg solubilizing capacities and saturation levels of crude oils, similar to the

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sample used in the experiment, are far greater. The fact that the Cymric field is associated with α-

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HgS(s) deposits10 but the crude oil Hg concentration is in the low µg g-1 range suggests that the

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abundance and distribution of α-HgS(s) and/or porosity of the source/reservoir rock play a major role

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together with temperature and reduced sulfur compound abundance for the Hg concentration of a

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specific crude oil deposit. However, the experimental set up in this study, using micro autoclaves,

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comprises a closed system which does not take into account possible evasion routes of Hg0 from the

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crude oil within the reservoir, e. g. by degassing and/or absorption in surrounding geological

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material.23, 24 Therefore, the Hg concentration in a crude oil should roughly represent an equilibrium

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between influx of dissolved and reduced α-HgS(s) and removal of Hg0 through various processes.

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This study shows that α-HgS(s) dissolves relatively fast in crude oil at reservoir temperatures and it

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can be concluded that particulate α-HgS(s), or other Hg minerals, are not likely to persist in crude oil

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reservoirs in a geological time perspective as reservoir temperatures often reach 150 °C or higher. In

317

addition to previously proposed mechanisms, as discussed above, our results suggest that the great

318

variability in crude oil Hg found globally is governed by sulfur speciation in the crude oil and reservoir

319

temperature. Given the relatively high thermodynamic solubility and dissolution rate observed for α-

320

HgS(s), the results indirectly suggest that factors controlling the physical contact between α-HgS(s)

321

and the crude oil (source rock permeability/porosity and concentration and spatial distribution of Hg)

322

in a reservoir are important for the ultimate Hg concentration in the crude oils. The results also

323

suggest that particulate HgS encountered in crude oil feedstocks24,

324

downstream of the well head at lower temperatures, e. g. in pipelines and storage tanks.

25

most likely is formed

325 326

Supporting Information



Page 14 of 21

327

Figures showing measured α-HgS(s) dissolution and fitted specific- and variable temperature models

328

in sample A at 200 °C, replicate 2, and at 230 °C; Table of experimentally determined solubility for

329

HgO(s) and α-HgS(s) in heptane or isooctane with or without different reduced sulfur compounds

330

added; Kinetic model equations for Sample A.

331

332

Acknowledgments

333

This work was financially supported by the ConocoPhillips Company. We thank Mingquan Liu for help

334

with the BET N2 adsorption measurements.

335


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336 337


Table 1. Total sulfur content and API gravity in all tested crude oils, and α-HgS(s) dissolution rates (Vdiss) at 200 °C in crude oils A, B, E, F and G.

Sample A B C D E F G

Region Europe North America Middle East South America North America Middle East North America

Total Sulfur (% (w/w)) 0.25 1.04 0.11 0.15 0.15 2.38 1.94

Gravity (API) 37.7 31.8 45.3 43.3 37 32.5 29.8

Vdiss (µmoles m-2 s-1) 0.24 0.12

0.05 0.12 0.17

338 339 340 341

Table 2. Average Total Hg Concentrations in Different Unfiltered Crude Oils Determined with Isotope Dilution Headspace GC-ICP-MS (1 h spike equilibration, 1h at 200 °C) or combustion-AAS.

Sample

342

Hg Concentration (ng g-1) ± 1σ, n=3 ID-HS-GC-ICP-MS

C-AAS

A

45±0.3

46±1

B

0.41±0.03

0.48 ±0.25

C

9.7 ±0.1

7.7 ±0.2

D

28.1±0.5

29.6 ±0.7

E

22.7±0.5

23.0 ±0.2

Blank, isooctane

0.03±0.01*

*ID-HS-GC-ICP-MS detection limit (3σ): 0.03 ng g-1

343 344 345 346 347

Table 3. Measured α-HgS(s) dissolution rates (Vdiss) and merit-of-fit (r2) of temperature specific(Temp. Specific) and variable temperature (Variable Temp.) kinetic models for sample A at temperatures between 170-230 °C. Temperature (°C) 170 200 (1) 200 (2) 200 (3) 230

Vdiss (µmoles m-2 s-1) 0.14 0.25 0.25 0.22 0.58

Fit of Kinetic Model (r2) Temp. Specific Variable Temp. 0.96 0.98 0.95 0.87 0.94 0.90 0.95 0.39 0.90 0.93

348 349


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

Dissolved-Reduced α-HgS (µmoles m-2)


Page 16 of 21

1600 1400 1200 1000 800 600 400 200 0 0

2000

4000

6000

8000

10000 12000

Time (s) 350 351

Figure 1. Measured α-HgS(s) dissolution over time (black dots) in sample A and fitted specific

352

temperature models (red line: nHg =nHg +0.1429t) at 170 °C and variable temperature models

353

(green lines: nHg =nHg +1.69*104e(-43222/RT)t), where t is time in seconds; nHg is the molar

354

amount Hg0 at a given time; nHg is the molar amount Hg0 at t=0; R is the universal gas constant and

355

T is temperature (K).

356


Page 17 of 21

300

250

α-HgS Solubility (ng g-1)

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


200

150

100

50

0

-50

357 358

Figure 2. α-HgS(s) solubility in isooctane with sulfur compounds added at 500 µg g-1 (as S) determined

359

by combustion-AAS total Hg analysis (error bars indicate 95% CI). Experiments conducted at 23 °C.

360



250000

200000

HgO Solubility (ng g-1)

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 18 of 21

150000

100000

50000

0

361 362

Figure 3. HgO(s) solubility in isooctane with sulfur compounds added at 500 µg g-1 (as S) determined

363

by combustion-AAS total Hg analysis (error bars indicate 95% CI). Experiments conducted at 23 °C.

364


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365


For TOC Only

366 367



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368

369 370 371 372 373 374 375 376 377 378 379 380 381 382 383 384 385 386 387 388 389 390 391 392 393 394 395 396 397 398 399 400 401 402 403 404 405 406 407 408 409 410 411 412 413 414 415

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Rapid Dissolution of Cinnabar in Crude Oils at Reservoir

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