Geochemical signatures of thermochemical sulfate reduction in controlled hydrous pyrolysis experiments

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Organic Geochemistry Organic Geochemistry 39 (2008) 308–328 www.elsevier.com/locate/orggeochem

Geochemical signatures of thermochemical sulfate reduction in controlled hydrous pyrolysis experiments Tongwei Zhang a, Geoffrey S. Ellis b, Clifford C. Walters c, Simon R. Kelemen c, Kang-shi Wang a, Yongchun Tang a,* a

Power, Environmental, and Energy Research Center, California Institute of Technology, 738 Arrow Grand Circle, Covina, CA 91722, USA b US Geological Survey, Box 25046, MS 939, Denver Federal Center, Denver, CO 80225, USA c ExxonMobil Research and Engineering Company, 1545 Route 22 East, Annandale, NJ 08801-0998, USA Received 16 May 2007; received in revised form 13 December 2007; accepted 18 December 2007 Available online 25 December 2007

Abstract A series of gold tube hydrous pyrolysis experiments was conducted in order to investigate the effect of thermochemical sulfate reduction (TSR) on gas generation, residual saturated hydrocarbon compositional alteration, and solid pyrobitumen formation. The intensity of TSR significantly depends on the H2O/MgSO4 mole ratio, the smaller the ratio, the stronger the oxidizing conditions. Under highly oxidizing conditions (MgSO4/hydrocarbon wt/wt 20/1 and hydrocarbon/H2O wt/wt 1/1), large amounts of H2S and CO2 are generated indicating that hydrocarbon oxidation coupled with sulfate reduction is the dominant reaction. Starting with a mixture of C21–C35 n-alkanes, these hydrocarbons are consumed totally at temperatures below the onset of hydrocarbon thermal cracking in the absence of TSR (400 °C). Moreover, once the longer chain length hydrocarbons are oxidized, secondarily formed hydrocarbons, even methane, are oxidized to CO2. Using whole crude oils as the starting reactants, the TSR reaction dramatically lowers the stability of hydrocarbons leading to increases in gas dryness and gas/oil ratio. While their concentrations decrease, the relative distributions of n-alkanes do not change appreciably from the original composition, and consequently, are non-diagnostic for TSR. However, distinct molecular changes related to TSR are observed, Pr/n-C17 and Ph/n-C18 ratios decrease at a faster rate under TSR compared to thermal chemical alteration (TCA) alone. TSR promotes aromatization and the incorporation of sulfur and oxygen into hydrocarbons leading to a decrease in the saturate to aromatic ratio in the residual oil and in the generation of sulfur and oxygen rich pyrobitumen. These experimental findings could provide useful geochemical signatures to identify TSR in settings where TSR has occurred in natural systems. Ó 2008 Elsevier Ltd. All rights reserved.

1. Introduction Throughout the generation, expulsion, migration, and accumulation processes, petroleum is potentially * Corresponding author. Tel.: +1 626 858 5077; fax: +1 626 858 9250. E-mail address: [email protected] (Y. Tang).

exposed to large quantities of brine. These aqueous solutions can serve as a solvent that facilitates reactions that are sluggish or not favored in oil or gas phases (Seewald, 2003). The most prominent abiotic alteration process in hot carbonate reservoir rocks is the reduction of sulfate to sulfide coupled with the oxidation of hydrocarbons to carbon dioxide, which collectively is termed thermochemical sulfate

0146-6380/$ - see front matter Ó 2008 Elsevier Ltd. All rights reserved. doi:10.1016/j.orggeochem.2007.12.007

T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

reduction (TSR). TSR is well documented in numerous petroleum systems and metal sulfide deposits (see references in Zhang et al., 2007). The occurrence of TSR is most commonly recognized by the presence of high concentrations of H2S (>10%) and CO2 (Worden et al., 1995; Machel, 2001). The presence of alkali earth elements and base or transition metals often results in the precipitation of carbonate minerals, particularly calcite and dolomite, and metal sulfides; thereby obscuring the characteristic geochemical signature of TSR by sequestering large quantities of CO2 and H2S (Machel, 2001). Calcite that precipitates during TSR typically occurs as milky white, coarse crystalline cements and/or as replaced masses after anhydrite (Machel and Anderson, 1989; Machel et al., 1995; Worden et al., 1996). Common metal sulfide by products of TSR are galena and sphalerite, often as Mississippi Valley Type deposits (Sangster et al., 1998). If iron is available during TSR, it tends to precipitate as pyrite or marcasite that replaces anhydrite (Dixon et al., 1989; Machel, 2001). Iron may be limited in sour gas reservoirs as most of the sedimentary iron may have already been fixed during early diagenesis by bacterial sulfate reduction (BSR) (Morse et al., 1987). Worden and Smalley (2001) suggested that TSR occurred in a clastic reservoir that resulted in substantial amounts of pyrite precipitation and very low residual H2S concentration. Field observations suggest that TSR can significantly affect the composition of petroleum hydrocarbons through oxidation and thermal cracking processes. In particular, the extent of souring within reservoirs has been correlated with increases in the gas to oil ratio (GOR) (Claypool and Mancini, 1989) and gases generated in association with TSR are found to be relatively dry (i.e. low C2+ content) (Krouse et al., 1988; No¨th, 1997). TSR altered oils are enriched in thiophenic and sulfidic hydrocarbons, which are formed in the reservoirs via reactions between H2S and hydrocarbons (Ho et al., 1974; Cai et al., 2003). Light hydrocarbon distributions and stable carbon isotope composition also can be very diagnostic of TSR alteration (Peters et al., 2005). Efforts to simulate TSR in the laboratory have focused generally on the determination of the reaction kinetics and attempts to understand the details of the reaction mechanisms involved (Toland, 1960; Dhannoun and Fyfe, 1972; Kiyosu, 1980; Trudinger et al., 1985; Kiyosu et al., 1990; Kiyosu and Krouse, 1993; Goldhaber and Orr, 1995; Cross et al., 2004).

309

Recently, the effects of TSR alteration on gas chemical and isotopic compositions were investigated by Pan et al. (2006) and the influence of petroleum composition on TSR reaction rate was investigated by Zhang et al. (2007). Geologic observations suggest that the most easily oxidized hydrocarbons are the gasoline range branched and normal alkanes followed by the cyclic and monoaromatic compounds (Krouse et al., 1988; Manzano, 1995; Rooney, 1995; Manzano et al., 1997; Cross et al., 2004) and that TSR lowers the saturate/aromatic hydrocarbon ratio, API gravity, and C15+ hydrocarbon content of petroleum while increasing the GOR (Orr, 1974, 1977; Claypool and Mancini, 1989; Manzano et al., 1997). These relationships have not been validated adequately in the laboratory. Prior simulations of the TSR process were conducted under unusual chemical conditions or under very high temperatures where it is difficult to differentiate hydrocarbon thermal cracking from sulfate reduction. The objectives of this study are to: (1) quantify the gas chemical composition change with the increase of the extent of TSR, (2) characterize the differences in the chemistry of residual liquid hydrocarbons following thermal cracking with and without TSR, (3) examine the effect of TSR on the thermal stability of oil during thermal maturation, and (4) characterize pyrobitumen formation resulting from TSR. In order to address these objectives, we designed a series of gold tube hydrous pyrolysis experiments that allow the reaction of hydrocarbons with MgSO4 to occur under a thermal regime where hydrocarbon oxidation by sulfate is the dominant reaction while hydrocarbon thermal cracking is minimized. Tang et al. (2005) reported that MgSO4 is an effective oxidant of hydrocarbons without the addition of initial hydrogen sulfide, which was used as an initiator in other experiments (Hoffmann and Steinfatt, 1993; Goldhaber and Orr, 1995). We intentionally employed extremely oxidizing conditions in order to amplify the effects of hydrocarbon oxidation associated with sulfate reduction and to minimize the relative effect of hydrocarbon cracking. These experiments provide an opportunity to investigate how TSR destabilizes hydrocarbons, the characteristics of the products (gases, liquids, and solids), and a means of quantifying the extent of TSR alteration in natural systems.

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2. Samples and experimental methods

2.2. Experimental methods

2.1. Sample description

2.2.1. Hydrous pyrolysis Gold is the material of choice for this work because of its high chemical inertness and flexibility that allows for external control of the confining pressure. All experiments were conducted in sealed gold tubes with a length of 60 mm and 70 mm, an internal diameter of 3.5 mm, and a wall thickness of 0.35 mm giving a total reactor volume of approximately 0.5 ml. Prior to loading the samples, the open ended tubes were heated to 600 °C to remove any residual organic material. One end of each tube then was crimped and sealed using an argon arc welder. Liquid organic reactants (oils or model compounds) and distilled water were loaded into the tubes by means of a 25 ll syringe. Precise amounts of MgSO4 powder and solid hydrocarbons (paraffin mixture) were accurately weighed and transferred to the tubes. The tubes were then flushed with argon for 5 min to remove air. The open end of the gold tube was crimped and welded while the other end was submerged in an ethanol liquid nitrogen mixture (80 °C) in order to minimize the loss of any volatiles created during the welding process. Individual sealed gold tubes were placed in separate stainless steel autoclaves and inserted into a pyrolysis oven. Pyrolysis experiments were conducted under isothermal conditions at a temperature of 350 °C for 24 h or non-isothermal conditions from 250 to 500 °C at a 20 °C/h heating rate. Temperature was controlled to within 1 °C of the set value, and was monitored using a pair of thermocouples secured to the outer wall of each autoclave. Constant confining pressure was maintained at approximately 24.1 MPa (3500 psi) by a water pump in order to prevent rupturing of the gold tubes at elevated temperatures. When the desired reaction temperature or time was reached, the stainless steel autoclave was withdrawn from the oven and then rapidly cooled to room temperature by quenching in water. Once the autoclaves were depressurized, the gold capsules were taken out and weighed to determine if leakage had occurred. The leakage verified gold tubes could be recovered for detailed analysis of their contents.

This study was performed on n-octane, a synthetic paraffin mixture, and on two crude oils of varying composition. The paraffin mixture is a research grade mix of C21 to C35 normal alkanes, with a melting point of 52–58 °C. This mixture was analyzed for its hydrocarbon composition by gas chromatography-flame ionization detection (GCFID) following the experimental protocol described in Section 2.2.3. The n-octane and paraffin mixture are model compounds that contain no sulfur. Two unrefined, wellhead crude oils were used in this study. These oils are referred to in this paper as ‘‘low-sulfur oil” and ‘‘high-sulfur oil” to protect proprietary interests of the oil companies that donated the samples. Their chemical properties are listed in Table 1. The low-sulfur oil was produced from a Carboniferous aged carbonate reservoir in an onshore field near the Caspian Sea in Kazakhstan. The oil has an approximate API gravity of 45°, contains 0.5% sulfur and has low polar content with no asphaltenes. The highsulfur oil was produced from an onshore field in the Oman. The oil contains 3.0 wt% (±0.1%) sulfur (Stainforth, pers. comm.), has an API gravity of 31.0°, and contains 15.3% asphaltene and 7.5% resins. The low and high-sulfur oils were characterized by GC-FID prior to reaction using the experimental protocol detailed in Section 2.2.3. The gas chromatography for the paraffin mix, high-sulfur and low-sulfur oil was reported by Zhang et al. (2007). Table 1 Some chemical properties of the hydrocarbons used in this study

Saturates (%) Aromatics (%) Resins (%) Asphaltenes (%) Total sulfur (%) Labile sulfura (mg/g oil) a

Paraffin mixture

Low-sulfur oil

High-sulfur oil

100 0 0 0

76 20 4 0

47.9 29.3 7.5 15.3

0

0.5

3.0

0

1.1

17.3

Total sulfur of the labile organosulfur species in oils was estimated based on the hydrogen sulfide produced from oil thermal cracking at R0 of about 1.12% according to Zhang et al. (2007).

2.2.2. Gas analysis Each gold tube was loaded separately into a piercing unit and connected to a custom made glass vacuum line with a residual pressure of 0.1 Pa. After isolation from the vacuum pump, each gold tube

T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

was punctured with a stainless steel piercing device to allow the product gases (C1, C2, C3, C4, C5, CO2, H2S, H2, and N2) to volatilize into the glass vacuum line. The heavier gaseous compounds were cold trapped with liquid nitrogen (196 °C), while the permanent gases were concentrated into a precalibrated volume using a mercury Toepler pump. Replacing the liquid nitrogen with a mixture of dry ice and acetone (80 °C) released the other volatile species, excluding water and organic compounds heavier than C5. These gases were drawn into the same calibrated volume in order to determine total gas yields, and the total number of moles of gas were calculated assuming ideal gas behavior (PV = nRT). Identification and quantification of individual hydrocarbon and non-hydrocarbon gas components were carried out using a two channel Hewlett–Packard 6890 Series Gas Chromatograph (GC) that was custom configured by Wasson ECE Instrumentation. The details of GC operation conditions are described in Zhang et al. (2007). 2.2.3. Liquid hydrocarbon analysis The hydrocarbon composition of the initial paraffin mixture and (non-pyrolyzed) oils were determined by gas chromatography-flame ionization detector (GC-FID) analysis using a Varian 3400 GC equipped with an Rtx-1 fused silica capillary column (30 m length, 0.53 mm ID, 0.25 lm film thickness). The non-reacted samples were prepared by dissolving 15 mg of sample into 480 ll of CS2 and then adding 20 ll of a 1.01% perdeuterated internal standard solution (C24D50). One microliter of prepared sample was then injected into the GC. The column was initially held at 50 °C for 1 min, and then heated to 325 °C at 10 °C min1. Integration of the FID signal was performed using PE Nelson Turbochrom 4 software. Compound identifications were based on relative retention times as compared to standard sample analyses. The liquid hydrocarbons remaining after reaction were analyzed in gold tube experiments conducted in parallel with those conducted for gas analysis using a procedure designed to prevent the loss of low molecular weight volatiles during sample recovery. Following post-pyrolysis cooling in water, a gold tube was frozen in liquid nitrogen (196 °C) for 5 min to completely condense all volatiles. The gold tube was removed from the liquid nitrogen cup and gently scored around the middle, taking care not to puncture the tube. The gold tube then was placed into a 5 ml vial filled with 20 ll internal

311

standard solution (1.01% C24D52) plus 480 ll of CS2 and the tube was then manually flexed it to break it along the score, and the vial capped immediately thereafter. The vial was agitated for several minutes to allow the soluble pyrolysis products to dissolve into the solvent. One microliter of prepared sample was then injected into the GC and analyzed following the same procedure described above for the initial reactants. 2.2.4. Residual solid analysis by X-ray photoelectron spectroscopy (XPS) Residual solids after reaction were recovered from gold tubes by manually cutting the gold tubes to small pieces and collecting the solids. After drying the solids at room temperature, XPS analyses of the residual solids were conducted using a Kratos Axis Ultra system equipped with a monochromatic Al Ka radiation source and automatic charge neutralization. Solid residues were mounted on a metallic sample nub using Scotch double sided non-conducting tape. An energy correction was made to account for sample charging based on the carbon (1s) peak at 285.0 eV. The relative amount of aromatic carbon was determined by the method of Kelemen et al. (1993) from the calibrated intensity of the p ? p* signal intensity. Curve resolution of the carbon (1s) spectra was performed following the method summarized in Walters et al. (2006). Inorganic carbonate carbon appears as a peak at 290.5 eV. The amount of organic oxygen was determined by analyzing oxygen’s effect on the carbon (1s) signal of adjacent carbon atoms. The C–O, C@O and O@C–O carbon (1s) curve resolved peaks are associated with 0.5, 1.0 and 2.0 oxygen atoms, respectively. Curve resolution of the sulfur (2p) spectra followed the method in Kelemen et al. (1990). Two chemical environments are found at energy positions consistent with aromatic (thiophenic) sulfur (164.1 eV) and sulfate (169.7–170.2 eV). 2.2.5. Residual solid analysis by X-ray diffraction (XRD) Residual solids were suspended in deionized water, and sonicated to ensure complete mixing. Suspended mixtures were freeze dried, loaded into aluminum holders, and analyzed using a Siemens D5000 X-ray diffractometer equipped with a h–2h goniometer and a copper anode X-ray tube. Standard methods were employed for data acquisition and mineral identification using DiffracPlus software.

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3.1. Isothermal pyrolysis of n-octane with TSR

or the extent of TSR (Fig. 1B), showing that drier gas is generated during hydrocarbon cracking associated with TSR than during thermal cracking alone.

3.1.1. Gas yields from n-octane cracking with variable amounts of MgSO4 In order to investigate the effect of TSR on hydrocarbon thermal cracking, a series of experiments were conducted involving fixed amounts of n-octane (25 mg) and distilled water (5 mg) with a variable amount of MgSO4. All samples were pyrolyzed at 350 °C for 24 h. Gas yields from these experiments (Table 2) show clearly that H2S and CO2 yields increase with increasing amount of MgSO4 (Fig. 1A). Under these reaction conditions the extent of the TSR reaction is directly proportional to the amount of MgSO4 in the system as is the intensity of octane oxidation. This might imply that the TSR reaction occurs on the MgSO4 solid surface. The amounts of generated methane and C2–5 hydrocarbon gases increase, while the amounts of ethylene and propylene decrease, with increasing extent of TSR (Table 2), suggesting that the thermal stability of n-octane is lowered by TSR. Another important observation is the increase of C1–C5 total gas yields P and the ratio of C1/ C1–5 gases generated (gas dryness) from 0.12 to 0.39 with increasing gas sourness

3.1.2. Variable H2O/MgSO4 mole ratio on TSR reaction rate In order to further investigate the effect of water presence on MgSO4 reduction, another series of experiments was conducted involving fixed amounts of n-octane (25 mg) and MgSO4 (50 mg) with a variable amount of distilled water. All samples were pyrolyzed under the same condition of 350 °C for 24 h. Gas yields from these experiments (Table 2) show that the rate of MgSO4 reduction to H2S initially decreases with increasing H2O/MgSO4 mole ratio (Fig. 2), and then ceases when H2O/MgSO4 mole ratio continuously increases, but with further increasing H2O/MgSO4 mole ratio the reduction starts again. This experimental observation suggests that the mechanism of MgSO4 reduction in the presence of water is more complicated than the simple reaction occurring on the surface of MgSO4. In the low H2O/ MgSO4 mole ratios ranging from 0 to 5, the TSR reaction mainly occurs on the MgSO4 solid surface. However, under extremely dilute conditions with very high H2O/MgSO4 mole ratios, MgSO4 is entirely dissolved in water. The disassociation of MgSO4 produces

3. Results

Table 2 Gas yields from octane cracking in the presence of MgSO4 from gold tube hydrous pyrolysis at 350 °C for 24 h and 3500 psi confining pressure Expt. run

Reactants (mmol) C8

MgSO4

Gas yields (mmol/mol C8) H2O

H2O/MgSO4

C1

C2

C2ene

C3

C3ene

i-C4

0 0 0.05 0.04 0.02

14.04 12.95 8.16 5.06 1.89

0.05 0.15 0.32 0.64 0.61

0.31 0.26 0.09 0.03 0.02

of water on MgSO4 reduction by octane 0.00 0.00 36.39 23.08 0.00 0.15 0.35 24.86 15.77 0.04 0.61 1.46 18.90 13.52 0.07 0.82 1.94 8.10 8.13 0.04 1.14 2.71 0.86 3.06 0.14 1.27 3.02 1.47 5.46 0.20 1.71 4.05 0.66 2.48 0.12 1.99 4.71 0.78 2.86 0.15 2.14 5.06 0.87 2.91 0.13 2.41 5.76 1.53 4.85 0.19 3.39 8.08 0.68 2.49 0.12 4.56 10.90 1.27 3.82 0.15 7.11 16.93 2.51 4.70 0.12 7.72 18.39 4.07 5.76 0.14

15.63 10.48 9.73 6.65 2.85 5.17 2.34 2.67 2.73 4.54 2.32 3.72 4.84 5.60

0.05 0.01 0.02 0.06 1.67 2.78 1.40 1.64 1.59 2.33 1.35 1.81 1.53 1.71

0.34 0.28 0.23 0.15 0.01 0.01 0.01 0.01 0.01 0.01 0.01 3.68 0.08 0.13

Series 1: Effect of variable MgSO4 amounts on octane cracking 1 0.22 0.42 0.28 0.67 32.7 20.74 2 0.23 0.21 0.28 1.33 21.16 16.68 3 0.22 0.11 0.28 2.55 8.79 9.6 4 0.22 0.05 0.28 5.60 3.00 5.52 5 0.22 0 0.28 1.02 1.93 Series 2: Effect of the presence 6 0.22 0.42 7 0.22 0.43 8 0.22 0.42 9 0.22 0.42 10 0.21 0.42 11 0.22 0.42 12 0.22 0.42 13 0.22 0.42 14 0.22 0.42 15 0.22 0.42 16 0.21 0.42 17 0.21 0.42 18 0.22 0.42 19 0.22 0.42

n-C4

i-C5

n-C5

CO2

H2S

9.71 9.97 6.98 4.64 1.56

0.31 0.31 0.19 0.09 0.02

6.1 7.62 6.4 4.64 1.54

41.43 25.05 12.34 5.15 2.48

168.8 103.7 44.64 11.96 0

10.80 7.55 7.85 5.90 2.91 5.23 2.36 2.70 2.75 4.54 2.34 1.07 4.41 5.16

0.34 0.24 0.21 0.13 0.03 0.06 0.03 0.03 0.03 0.05 0.03 0.06 0.10 0.14

6.79 4.60 5.63 5.11 3.11 5.78 2.49 2.72 2.88 4.85 2.44 3.73 4.63 5.10

45.48 33.48 21.59 5.32 0.37 1.59 0.40 0.40 1.76 2.00 0.61 1.36 1.55 1.12

187.80 140.12 101.35 40.26 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.33 3.05

T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

Gas yields (mmol/mol octane)

A

313

200

160 H2S 120 C1-5

80

CO2

40

0 0.0

0.5

1.0

1.5

2.0

MgSO4/octane ratio in mole

Gas sourness and dryness

B 0.60

Gas sourness

Gas dryness

0.40

0.20

0.00 0.0

0.5

1.0

1.5

2.0

Mg SO4/octane ratio in mole

Fig. 1. Gas yields from pyrolysis experiments involving octane P with increasing MgSO4 amount under isothermal conditions at 350 °C for 24 h. (A) Gas yields; (B) gas sourness [H2S/(H2S + CO2 + (C1–C5)).

Mg2+ and SO2 4 ions in the solution, and it is most likely that the presence of Mg2+ ions in the solution may play some role to sulfate reduction. 3.1.3. Mg2+ and SO2 4 ions in aqueous solution on TSR reaction rate In order to clarify the effect of the presence of Mg2+ and SO2 4 ions in aqueous solution on TSR reaction rate, three comparison experiments were conducted involving fixed amounts of n-octane (25 mg), MgSO4 (2 mg) and distilled water (380 mg) with addition of NaCl (43 mg), Na2SO4 (34 mg) and MgCl2 (24 mg), respectively. Three aqueous solutions give a same ionic strength of about 2.02 M. The molarity of MgSO4 solution is initially about 0.04 M for all three solutions. All samples were pyrolyzed at 350 °C for 100 h. Gas yields from these experiments are listed in Table 3. H2S yield from aqueous MgSO4 reduction increases

from 15.1 mmol/mol C8 with NaCl to 25 mmol/mol C8 with MgCl2, clearly suggesting that the presence of Mg2+ ion can enhance the sulfate reduction to H2S. However, the TSR reaction was shut down in the presence of Na2SO4, which provides additional SO2 4 and drives the precipitation of MgSO4 or its hydrated species and consequently, reduces the Mg2+ ion concentration in the solution. The experimental observation clearly suggests that the presence of Mg2+ ion in the aqueous solution plays an important role to sulfate reduction. 3.2. Non-isothermal pyrolysis of paraffin mixture (C21–C35) with and without TSR 3.2.1. Gas yields A series of experiments was conducted involving a paraffin mixture and distilled water (paraffin = 5 mg, H2O = 5 mg) with and without MgSO4

314

T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328 200

variable water amount with a fixed MgSO4 loading variable MgSO4 amount with a fixed water loading

H2S yield (mmol/mol C8)

150

Reduction of MgSO 4 solid

100

50 -

Reduction of HSO 4

0 0

5

10 H2O/MgSO4 mole ratio

15

20

Fig. 2. H2S yield from MgSO4 reduction by octane with increasing H2O/MgSO4 mole ratio under isothermal conditions at 350 °C for 24 h.

(100 mg) heated at 20 °C/h. Gas yield data for C1, C2–5, CO2 and H2S from these experiments are listed in Table 4. Pyrolysis of the hydrocarbons without TSR shows that the yields of methane and heavier hydrocarbon gases are very low at 375 °C, and increase dramatically when the temperature is above 425 °C (Fig. 3A). The methane yield is much smaller than the sum of the heavier hydrocarbons (C2–C5) up to 525 °C (equivalent vitrinite reflectance value 2.7% R0), which is consistent with previous reports of pyrolysis experiments involving crude oil that generate hydrocarbon gases with methane contents ranging from 10% to 60% (Appleby et al., 1947; Hikita et al., 1989; Horsfield et al., 1992). Pyrolysis experiments involving the paraffin mixture with the addition of MgSO4 (H2O/MgSO4 mole ratio 1:3, named 100 mg MgSO4 case) show that sulfate reduction begins at 300 °C, and that the H2S yield increases with temperature and reaches a maximum at 375 °C. H2S yield then

decreases at temperatures >400 °C. The yield of CO2 continuously increases with temperature from 300 to 500 °C and is much higher than that from paraffin reacting with water in the absence of MgSO4 (Table 4 and Fig. 3C), indicating that the oxidation of hydrocarbons by TSR is a dominant process. Furthermore, the changing yields of C1 and C2–C5 with temperature provide additional evidence of the strong oxidation potential of this system. The yield of the C2–5 hydrocarbon gases increases with increasing temperature from 300 to 375 °C and then decreases markedly from 6.4 to 0.01 ml/g paraffin mix at higher temperatures (Fig. 3B). The methane yield starts to decrease once the heavier hydrocarbon gases are oxidized completely (427 °C) (Fig. 3B). This decrease in methane must be due to TSR associated oxidation because CO2 yields continue to increase in these experiments and methane generation from paraffin thermal cracking alone consistently increases over this temperature range.

Table 3 2+ Effect of the presence of SO2 in aqueous solution on MgSO4 reduction by octane from gold tube hydrous pyrolysis at 350 °C 4 and Mg for 100 h and 3500 psi confining pressure Expt. run

Reactants (mmol) C8

MgSO4

1 2 3

0.22 0.22 0.23

0.017 0.016 0.017

Na2SO4

MgCl2

Gas yields (mmol/mol C8)

H2O

C1

C2

C2ene

C3

C3ene

i-C4

n-C4

i-C5

n-C5

CO2

H2S

21.46 21.11 21.84

0.25

32.92 18.06 41.36

69.83 63.52 66.94

0.60 1.10 0.75

63.96 52.95 75.77

8.05 10.55 7.62

2.15 0.22 6.84

52.47 47.44 57.57

1.99 0.93 4.33

34.94 33.59 44.35

7.40 4.15 28.93

15.09 0.00 25.17

0.24

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315

Table 4 Gas yields (ml/g oil) from paraffinic hydrocarbon cracking with and without MgSO4 from 250 to 550 °C and 3500 psi confining pressure at 20 °C/h heating rate Oil type

With MgSO4 C2–C5

CO2

H2S

Temperature (°C)

C1

C2–C5

Paraffinic mixture

250 275 300 325 340 350 360 370 375 400 427 475 500 525 550 575

0.01 0.01 0.02 0.08 0.19 0.68 1.27 2.90 4.54 8.34 6.35 0.17 0.00 0.01 0.00 0.00

0.02 0.02 0.02 0.11 0.30 1.23 2.30 5.16 6.43 1.11 0.06 0.02 0.02 0.00 0.01 0.04

0.88 0.37 0.50 2.01 1.93 4.28 5.80 11.36 24.95 79.67 171.65 288.59 443.68 504.42 676.89 811.82

0.00 0.00 0.88 4.37 12.60 30.97 44.50 86.18 108.44 62.10 33.61 25.30 33.26 48.25 131.02 345.53

375 400 425 450 478 504 525 550

0.02 0.12 1.47 29.24 75.06 183.79 263.74 412.70

0.05 1.40 17.74 123.91 211.51 293.88 264.32 218.12

0.20 0.70 0.41 3.43 0.92 2.32 2.76 3.35

300 325 340 350 360 375 400 427 453 475 500 550 575

0.07 0.25 0.99 1.23 2.04 5.09 11.21 11.72 5.63 0.84 0.00 0.00 0.00

0.11 0.25 0.60 0.88 1.38 3.81 1.52 0.03 0.03 0.03 0.02 0.00 0.00

6.17 7.99 17.00 18.50 28.00 35.00 91.18 152.62 235.37 306.75 463.78 601.11 787.65

0.00 3.64 13.68 16.74 20.50 39.10 53.84 60.38 41.40 68.39 29.00 79.20 69.64

350.00 375.00 400.00 425.00 450.00 475.00 500.00

0.07 0.32 0.43 2.75 11.46 44.95 135.44

0.15 0.46 1.13 7.63 42.66 114.96 211.97

1.18 3.14 1.17 8.19 0.24 1.72 2.00

0.08 0.25 0.39 0.59 0.67 0.68 1.41

300 325 340 350 360 370 375 400 427 475 500 525 550 575

0.11 0.62 1.31 1.87 3.32 4.20 10.58 16.66 13.01 8.30 16.20 0.01 0.01 0.00

0.31 0.68 1.29 1.67 3.05 3.56 4.68 1.66 0.04 0.02 0.03 0.02 0.01 0.00

0.33 2.30 5.95 14.10 21.35 29.00 34.70 125.76 184.90 352.67 376.26 539.44 844.73 856.45

0.88 8.48 10.31 14.51 20.30 28.01 70.98 64.78 50.05 110.09 144.79 55.43 24.27 87.35

355 375 400 425 450 475 500 525 550

0.67 1.49 1.65 5.74 23.12 60.00 137.16 209.31 319.15

1.33 2.65 2.03 10.34 55.28 139.30 212.00 210.48 192.85

0.86 1.64 1.16 2.06 3.60 6.86 7.88 10.84 16.99

4.38 5.10 5.03 8.06 8.23 10.71 14.01 14.84 14.65

Temperature (°C)

Low-sulfur oil

High-sulfur oil

No MgSO4 C1

CO2

H2S

Note: For the experiment with MgSO4, oils = 5 mg, H2O = 5 mg and MgSO4 = 100 mg; for the experiment without MgSO4, oils = 15 mg and H2O = 15 mg.

However, the gas generation and gas characteristics from paraffin thermal cracking as a function of temperature is obviously different when the H2O/ MgSO4 mole ratio increases to 10:1. Zhang et al. (2007) reported the gas yields from pyrolysis experimental involving the 15 mg paraffin mixture with the addition of 10 mg MgSO4 and 15 mg distilled

water from 340 to 550 °C at 2 °C/h. We gave a name of ‘‘10 mg MgSO4” to these experimental conditions. The previous experimental results clearly show that TSR starts at a temperature of 400 °C for the 10 mg MgSO4 case, which is about 100 °C higher than that of 100 mg MgSO4 case presented in this study. There is no observed difference in C1

316

T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

Gas yields (ml/g oil)

400

C1

without MgSO4

300 200 C2-5

100 0 300

350

400

450

500

550

600

500

550

600

Gas yields (ml/g oil)

15 with MgSO4

10

C1

5 C2-5

0 300

350

400

450

Gas yields (ml/g oil)

1000 800

with MgSO4

600 CO2

400 200 0 300

H2S

350

400

450 500 Temperature (°C)

550

600

Fig. 3. Gas generation as a function of temperature from a paraffin mixture cracking with and without the presence of MgSO4 from 300 to 550 °C at 20 °C/h heating rate.

and C2–5 generation as a function of temperature with and without TSR for the 10 mg MgSO4 case. In other words, the dominant reaction is the thermal cracking of paraffinic compounds to gases, and TSR plays an insignificant role in the alteration of gas compositions. Therefore, the 10 mg MgSO4 case is not suitable to differentiate the effect of TSR on the paraffinic compounds from thermal cracking. However, the oxidation of hydrocarbons by TSR is a dominant process for the 100 mg MgSO4 case, which provides an opportunity to investigate how

TSR destabilizes hydrocarbons and the characteristics of the products (gases, liquids, and solids) while minimizing the relative effect of hydrocarbon cracking. 3.2.2. Residual liquid hydrocarbons The paraffin mixture (C21–C35) was pyrolyzed without the addition of MgSO4 under non-isothermal hydrous pyrolysis conditions from 370 to 475 °C (20 °C/h heating rate). Concentrations of residual C11–C35 hydrocarbons following thermal

T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

cracking were determined using the method described in Section 2.2.3 and are shown in Fig. 4A. Above 375 °C the yield of the lighter paraffinic components with carbon number less than C21 gradually increases and accounts for a significant percentage of the total residual hydrocarbons at 450 °C. This pattern is similar to that seen in the thermal cracking of other model compounds and crude oils (e.g., Speight, 2003; Xiong et al., 2004; Wang et al., 2006). Similar experiments were conducted involving the paraffin mix with the addition of MgSO4 under non-isothermal hydrous pyrolysis conditions from 300 to 475 °C (20 °C/h heating rate); however, the reactivity and distribution of n-alkanes in the liquid residues are significantly different in the TSR reactions relative to the hydrocarbon cracking experi-

ments. As shown in Fig. 4B, loss of the C21 to C35 n-alkanes begins at approximately 325 °C and by 400 °C, the onset temperature for thermal cracking of the paraffin mixture, almost all of the original paraffin mixture is consumed. Furthermore, the generation of shorter chain length hydrocarbons (
1.4 1.2

317

room temp. 375 ° C

without MgSO4

weight amount (mg)

400 ° C

1 425°

0.8 0.6 0.4 450°

0.2

475°

0 11

13

15

17

19

21

23 25 27 29 Carbon number

31

33

35

37

39

0.4 room Temp.

with MgSO4

weight amount (mg)

0.32

300° 325°

0.24

340 °C

0.16

350°

0.08

375 °C 400 °C

0 11

13

15

17

19

21

23 25 27 29 Carbon number

31

33

35

37

39

Fig. 4. Comparison of remaining paraffinic mixture with temperature after heating paraffin mixture with and without the presence of MgSO4 at 20 °C/h heating rate.

318

T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

increases above 400 °C and H2S yields are low (Table 4). The H2S yield in the presence of MgSO4 is obviously higher than that from oil thermal cracking alone, confirming that MgSO4 was reduced by the two oils. The onset temperature of TSR from the two different oils and paraffin mixture is similar, indicating that the difference in chemical compositions among these hydrocarbons does not play a significant role in controlling the onset temperature of TSR under these strong oxidation conditions. In all experiments containing MgSO4 at temperatures from 300 to 400 °C H2S yield consistently increases. At temperatures above 400 °C H2S yield becomes highly variable and there are no consistent trends observed with increasing temperature. The trends with increasing temperature in CO2, C1 and C2–C5 yields from the oils are similar to those seen in the paraffin mix (Table 4). CO2 yield continuously increases at temperatures >427 °C, while methane yield starts to decrease once the heavier gaseous hydrocarbons (CP 2–C5) are consumed by TSR. The gas dryness (C1/ C1–5) of the generated hydrocarbons in the whole oil experiments is significantly impacted by TSR with the maximum increasing from 67% for oil cracking to 100% with TSR (Fig. 5).

3.3.2. Residual liquid hydrocarbons Residual liquid hydrocarbons were analyzed in experiments involving the high-sulfur oil with and without MgSO4 at 400 °C with 20 °C/h heating rate (Table 5). The concentrations of all saturated hydrocarbons were depleted dramatically by TSR

Table 5 Comparison of n-C9 to n-C40 normal alkane distribution for highsulfur oil thermal decomposition with and without TSR at 400 °C with 20 °C/h heating rate Component

Amount of concentration (mg/g oil)

C9 C10 C11 C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30 C31 C32 C33 C34 C35 C36 C37 C38 C39 C40

Unheated oil

Cracked oil without TSR

Cracked oil with TSR

6.90 7.17 6.84 6.23 6.59 5.45 5.60 4.10 4.00 3.54 3.85 2.74 2.21 1.85 1.85 1.38 1.44 1.27 0.92 0.74 0.71 0.65 0.54 0.53 0.54 0.47 0.41 0.22 0.18 0.14 0.11 0.12

10.18 8.98 9.04 7.77 7.75 7.03 7.08 4.96 4.63 4.03 4.17 3.07 2.42 2.00 1.97 1.53 1.56 1.31 0.97 0.76 0.74 0.71 0.47 0.51 0.45 0.38 0.35 0.20 0.17 0.15 0.11 0.12

3.56 2.96 2.39 1.95 1.76 1.52 1.79 0.92 0.80 0.52 0.51 0.47 0.29 0.24 0.24 0.37 0.33 0.30 0.20 0.18 0.12 0.21 0.10 0.11 0.09 0.09 0.08 0.10 0.05 0.04 0.03 0.04

1 0.9 with TSR

C1/C1-5, gas dryness

0.8 0.7 0.6 0.5 0.4

without TSR

0.3 0.2 0.1 0 300

Low-sulfur oil w/TSR Low-sulfur oil w/o TSR High-sulfur oil w/TSR High-sulfur oil w/o TSR

350

400 Temperature (°C)

450

500

Fig. 5. Gas dryness for pyrolysis experiments involving a low-sulfur and high-sulfur oil with and without MgSO4.

T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

319

tures from 275 to 575 °C at a 20 °C/h heating rate were analyzed by XPS. Quantities of sulfur, carbon, and oxygen species in the residual solids determined by XPS are listed in Table 7. Sulfur (2p) spectra and examples of curve resolution are shown in Fig. 7. XPS is a surface sensitive technique and the changing nature of the proportion of sulfate to reduced sulfur reflects the deposition of thiophenic solids onto the exterior portion of the sulfate minerals. At 275 °C, sulfur exists exclusively as S6+ and 93% of the curve is resolved into the two 2p3/2 and 2p1/2 components characteristic of a single sulfate chemical environment (Fig. 7). At higher temperatures the sulfate peak broadens significantly indicating that the sulfate exists in two distinct chemical environments: MgSO4 and hydrated MgSO4 species. XRD analysis of the residues confirmed

(Fig. 6). Even the n-alkanes in the condensate range (C6–C14), which are thermally stable at 400 °C, are consumed in the presence of MgSO4. Comparison of geochemical parameters such as Pr/Ph, Pr/n-C17 and Ph/n-C18 with and without TSR is listed in Table 6. The Pr/Ph ratio in the residual oils after reaction with MgSO4 generally increases with the extent of TSR and the Pr/n-C17 and Ph/n-C18 ratios decrease. Thermal cracking of the oil produces the same trend, though to a lesser degree at equivalent temperatures. 3.4. Residual solids characterization by XPS after TSR Residual solids from the TSR reaction of paraffinic mixture and MgSO4 over a range of tempera12

weight (mg/g oil)

10

8 Cracked oil without TSR

6 Unheated oil

4 Oil with TSR

2

0 9

11

13

15

17

19

21 23 25 27 Carbon number

39

31

33

35

33

39

Fig. 6. Comparison of saturated hydrocarbon distributions from high-sulfur oil thermal decomposition at 400 °C with and without TSR.

Table 6 Comparison of geochemical parameters for remaining oils with and without MgSO4 after being heated from 300 to 450 °C at 20 °C/h Conditions

Temperature (°C)

Unheated oil

Low-sulfur oil

High-sulfur oil

n-C14/n-C14+

Pr/Ph

Pr/n-C17

Ph/n-C18

n-C14/n-C14+

Pr/Ph

Pr/n-C17

Ph/n-C18

1.69

1.04

0.46

0.48

1.53

0.70

0.49

0.78

With TSR

300 325 350 375 400

1.44 1.56 1.41 3.46 3.43

1.06 1.06 1.10 1.42 1.55

0.43 0.44 0.42 0.30 0.12

0.43 0.45 0.41 0.26 0.18

1.36 1.38 1.51 2.33 3.82

0.65 0.59 0.55 0.62 0.99

0.39 0.35 0.31 0.21 0.14

0.70 0.69 0.65 0.43 0.20

Without TSR

375 400 425 450

1.62 1.59 2.14 6.40

0.98 1.06 1.11

0.42 0.38 0.31

0.44 0.38 0.30

1.39 1.76 2.55 5.71

0.62 0.64 0.81

0.37 0.34 0.29

0.68 0.61 0.40

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T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

Table 7 XPS analysis of carbon, sulfur, and oxygen species in the residual solids forming during TSR of a paraffin mix reacting with MgSO4 at 20 °C/h heating rate Temperature (°C)

275 300 325 350 375 400 427 475 500 550 575

Per 100 carbons

Mole percent

Aromatic carbon

Carbonate carbon

Organic oxygen

Sulfate sulfur

Thiophenic sulfur

Thiophenic

SO4 (1)

SO4 (2)

0 9 13 31 53 46 61 76 78 91 94

0 0 0 0 0 2.2 1 1.8 1.9 1.9 2

8.1 8.6 10.6 6.5 8.1 9.3 9.5 8.7 7.2 7.6 10

99.4 51.1 51.5 40 21.1 14.5 19.4 20.6 18.3 16.8 31.4

0 0 1.1 3 9.5 10.9 13.5 16.1 16.9 15.6 12.2

0 0 2 7 31 43 41 44 48 48 28

93 95 93 81 59 43 46 42 38 38 51

7 5 5 12 11 15 14 14 14 14 20

Aromatic carbon/ thiophenic sulfur ratio

11.8 10.3 5.6 4.2 4.5 4.7 4.6 5.8 7.7

Reactors heated at 20 °C/h under 3500 psi constant confining pressure to the indicated maximum temperature.

o

SO4 SO4

275 C

S0

XPS Sulfur (2p) Signal

275 oC 300 oC 325 oC

SO4

o

375 C S0

350 oC

375 oC 400 oC o

o

SO4

475 C

2P3/2

425 C 2P1/2

475 oC 172 168 164 160 Binding Energy (eV) 173

169 165 Binding Energy (eV)

Fig. 7. X-ray photoelectron sulfur (2p) spectra and curve-resolved spectra of solid residues from the reaction 100 mg MgSO4 + 5 mg paraffin mix and 5 mg H2O at a 20 °C/h heating rate.

varying amounts of kieserite (MgSO4  H2O), magnesium sulfate hydroxide hydrate (Mg1.33SO4(OH)0.66  0.33H2O), magnesium sulfate hydrate (MgSO4  1.25H2O), hexahydrate (MgSO4  6H2O), and epsomite (MgSO4  7H2O). Trace amounts of reduced sulfur forms appear in the XPS sulfur 2p spectrum at 325 °C corresponding to the onset of H2S generation (Fig. 8). The amount

of the reduced sulfur is sufficient in experiments terminated at 350 °C and higher to curve resolve their spectra, showing that this reduced sulfur exists in a single chemical environment at an energy position consistent with thiophenic sulfur (Fig. 7). The proportion of reduced organic sulfur and inorganic sulfate remains fairly constant until 575 °C where the thiophenic sulfur decreases and the H2S yield

T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

321

100

Aromatic carbon

SO4(1) 80

80

60

60

Thiophenic S 40

40

20

20

Carbon aromaticity (mole % carbon)

Sulfur species in solids (mole % sulfur)

100

SO4(2) 0

0 275

325

375

425

475

525

575

Temperature (°C)

Fig. 8. Relative mole percent of sulfur species and aromatic carbon in the residual solids as a function of temperature from paraffin mixture with MgSO4 at 20 °C/h heating rate.

substantially increases. This coincides with an increase in the aromatic carbon to thiophenic sulfur ratio. No elemental sulfur, thiosulfate, or sulfite forms are evident in the residual solids from these experiments. 4. Discussion 4.1. Possible mechanism of MgSO4 reduction under our experimental conditions Our experimental observations show that the H2S yield from anhydrous MgSO4 reduction by octane is the highest and dramatically decreases with the increase of H2O/MgSO4 mole ratio. This suggests that the anhydrous MgSO4 itself is reactive towards hydrocarbons. Under our highly oxidizing conditions (H2O/MgSO4 mole ratio of 1:3), XRD analysis of the residues confirmed that sulfate exists in two distinct chemical environments: MgSO4 and hydrated MgSO4 species. As a result, the reaction of TSR occurs at a much lower temperature (300 °C) under highly oxidizing condition with H2O/MgSO4 mole ratio of 1:3 than that of H2O/ MgSO4 mole ratio of 10:1 (Zhang et al., 2007) because of the excess of MgSO4 solid presence. Our experimental observation also shows that the presence of Mg2+ ion in the aqueous solution can significantly enhance the rate of sulfate reduction under the same H2O/MgSO4 mole ratio. Previ-

ous experimental studies by Bischoff and Seyfried (1978) revealed that seawater becomes an acid at temperatures >200 °C. Heating of seawater to 300 °C at 500 bars resulted in large decreases in the concentrations of Mg2+, SO2 4 and pH (Janecky and Seyfried, 1983). The precipitation of a magnesium hydroxide sulfate mineral (MHSH) was identified as the cause of the change in seawater characteristics as temperature increased above 200 °C (Janecky and Seyfried, 1983). The reaction that caused these changes may be written as follows: ð1 þ nÞMg2þ þ SO2 4 þ H2 O ¼ ðnÞMgðOHÞ2 : MgSO4 : ð1  2nÞH2 O þ ð2nÞHþ ;

ð1Þ

where n in reaction 1 can vary between 0 and 0.5 (Janecky and Seyfried, 1983). Therefore, the presence of Mg2+ ion at our experimental temperature results in the decrease of pH that, in turn, increases the concentration of HSO 4 ion, which is the dominant sulfate species in acidic aqueous solutions. Molecular modeling calculations have shown that 2 HSO 4 ions are much more reactive than SO4 ions in aqueous solution; the calculated activation energy of the HSO 4 ion reacting with ethane is about 55 kcal/mol, which is about 23 kcal/mol lower than that of SO2 4 ion with ethane (Ma et al., unpublished data). Kiyosu (1980) observed that sulfuric acid and sodium bisulfate were reduced to H2S by dextrose at temperatures above 300 °C, with an initial pH of the

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T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

aqueous solution in the range of 0.9–1.35 (at 25 °C). However, the reduction of sodium sulfate to H2S did not occur when the initial pH of the aqueous solution was 7, which is consistent with our observation of the effect of Na2SO4 presence to TSR reaction. Both experimental and theoretical results suggest that the reduction of the HSO 4 ion by HC is more energetically favorable than the SO2 ion. Therefore, HSO 4 4 is thought to be the reactive sulfate species in aqueous MgSO4 solution under our high temperature condition. 4.2. Effect of TSR on gas compositions 4.2.1. Increase of gas sourness P Gas sourness H2S/[H2S+CO2 + (C1–C5)] is considered a direct indicator of the extent of TSR (Worden and Smalley, 1996; Cai et al., 2003). Our experimental observations show that gas sourness increases with the extent of TSR in the presence of excess hydrocarbons. We observe that from 300 to 400 °C H2S yield increases as TSR proceeds for experiments involving the two oils and the paraffinic mixture. However, above approximately 400 °C H2S yield becomes highly variable. Experiments conducted with the paraffin mixture show that from 375 to 475 °C H2S yield decreases and then increases again to 575 °C. In contrast, experiments involving the two whole oils show complex patterns of H2S yield at temperatures above approximately 400 °C without any consistent trends. We speculate that this is the result of a complex series of reactions involving the formation and thermal destruction of organic sulfur species (e.g., thiophenes, benzothiophenes and thiols) or reduced sulfur (elemental sulfur), and is highly dependent on the type of hydrocarbon presence. This speculation can be partially substantiated by examining the XPS data. Fig. 8 shows that thiophenic compounds are produced during TSR experiments involving the paraffin mixture, and that thiophene formation increases dramatically when the temperature is above 375 °C, corresponding with the observed decrease in H2S. Although XPS analysis does not indicate the presence of elemental sulfur in the solid residues of our experiments, a previous study of sulfur speciation in residues of TSR experiments analyzed by GC-sulfur chemoluminescence detection (GC-SCD) showed that elemental sulfur is produced from reactions involving paraffin and MgSO4 at 400 °C (Ellis et al., unpublished data). Experiments involving the complex mixtures

of organic compounds found in whole crude oils might be expected to exhibit complex patterns of organic sulfur species formation and H2S yields. It is important to note that reactions that occur at these high temperatures (>400 °C) and highly oxidizing conditions are not likely to be very representative of processes that take place in natural settings. 4.2.2. Increases in gas dryness In our experiments, the relative contribution of methane to the total amount of hydrocarbon gases generated by TSR increases as the extent of TSR increases (Fig. 5). When compared to the hydrocarbon gases generated from thermal cracking alone, the TSR associated hydrocarbon gases are significantly drier at the same thermal maturity. Seewald (2001) reported that methane rich gas is produced in the stepwise oxidation of hydrocarbons. Our experimental observations show P that, for the two oils studied, gas dryness (C1/ C1–5) reaches 1.0 (100% methane remains because heavier gaseous hydrocarbons were consumed by oxidation) at approximately 425 °C when TSR is present, yet without TSR gas dryness does not exceed 0.67 at nearly 500 °C (Table 4). Admittedly, the major gas products from reactions involving TSR are H2S and CO2 rather than methane, suggesting that if TSR were a significant mechanism for the generation of dry gas then one would expect to encounter high concentrations of H2S and CO2 associated with this gas. It should also be noted that our experimental conditions are extremely oxidizing because of the addition of MgSO4 in excess and that the actual effect of TSR on gas dryness under reservoir conditions may be much less pronounced. 4.3. Effect of TSR on oil stability Our results show that the thermal stability of all hydrocarbons, even methane, can be significantly lowered under the strong oxidation conditions used in our TSR experiments. TSR does not merely accelerate thermal cracking, but follows different chemical pathways that involve hydrocarbon oxidation. The effect of these processes are illustrated in Fig. 6, which compares the distributions of nalkanes in the high-sulfur oil with the remaining products at 400 °C in the absence and presence of MgSO4. Without TSR, the n-alkanes with carbon chain lengths C15 saturated hydrocarbons are slightly

T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

reduced in concentration relative to the unheated high-sulfur oil, indicating an increase in condensate range compounds resulting from the cracking of longer carbon chain components. In other words,
323

effects of thermal cracking and TSR (Fig. 9). Pentacosane (n-C25) is almost totally consumed by sulfate reduction before 400 °C, whereas almost 90% n-C25 remains when undergoing only thermal cracking. We can assume that the consumption of C25 when the temperature is below 400 °C could mainly result from thermochemical sulfate reduction and have a minor contribution from hydrocarbon thermal cracking under our strong oxidation experimental conditions. The conversion index might apply to understanding the extent of oil cracking with and without involving TSR reaction. As shown in Fig. 4B, C21–C35 n-alkanes in the paraffinic mixture are equally oxidized by TSR with no obvious difference in reactivity of individual homologs. In order to compare the conversion index calculated for TSR experiments involving the paraffin mixture with those conducted with the whole oils, the saturates in the two oils were grouped into two families, i.e. >C21 (C21–C40) and C21 saturates increases as TSR and thermal cracking proceeds, indicating the destruction of
1 0.9

Conversion index Xi

0.8 0.7 0.6

Thermochemical sulfate reduction

0.5 0.4 Thermal chemical alteration

0.3 0.2 0.1 0 250

275

300

325

350 375 400 Temperature (°C)

425

450

475

500

Fig. 9. Consumption of n-pentacosane during TSR reactions involving a paraffinic mixture occurs at a much lower temperature compared with oil thermochemical alteration (TCA) alone.

324

T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

A

1.0 >C21, w/TSR High-sulfur >C21, w/TSR Low-sulfur

Conversion Index

0.8

>C21, w/o TSR High-sulfur >C21, w/o TSR Low-sulfur

0.6 0.4 0.2 0.0 250

300

350

400

450

500

450

500

Temperature (°C)

B

1.0

Conversion Index

0.6 0.2 -0.2
-0.6


-1.0


-1.4 250

300

350 400 Temperature (°C)

Fig. 10. Conversion index of >C21 and
In natural systems, saturated hydrocarbons are preferentially destroyed relative to aromatics by thermochemical sulfate reduction (Rooney, 1995; Manzano et al., 1997). Similar effects are observed in the laboratory simulation experiments. Normal C8–C35 alkanes are consumed as the oil is altered by the TSR reaction and the depletion increases with the extent of TSR (Fig. 5). The C1–5 gas yield from high-sulfur oil thermal cracking without TSR at 355 °C is 2 ml/g oil, which is almost equivalent to the hydrocarbon gas yield from the paraffinic mixture at 400 °C (Table 4). This suggests that the destruction of C8–C35 saturates from oils reacting with MgSO4 at temperatures above 370 °C could result from both hydrocarbon oxidation by TSR and hydrocarbon thermal cracking. As a result, it is hard to accurately assess the extent of TSR on the basis of the quantification of the remaining C8– C35 saturates from the heated oils. While the conversion index of >C21 saturates group in the oils mainly represents the destruction of n-alkanes by TSR, it might be used as an estimate of the minimum extent of TSR for the oils at a given temperature.

Oils reacted in the presence of MgSO4 show no obvious differences in n-alkane distributions compared to the original unheated oils with the increase of TSR extent (Fig. 11). Hence, we conclude that nalkane distributions are not diagnostic of the extent of TSR. However, the Pr/n-C17 and Ph/n-C18 ratios obviously decrease with the increase of the extent of TSR (Fig. 12). These ratios are significantly lower when TSR occurs compared to thermal cracking alone. These observations suggest that abnormally low Pr/n-C17 and Ph/n-C18 ratios in oils at a given thermal maturity may be caused by TSR. This experimental observation agrees with field observations of oils from the Western Canada Sedimentary Basin that have experienced TSR (Manzano et al., 1997). 4.4. Effect of TSR on aromatization and sulfur and oxygen incorporation to solid residues (pyrobitumen) XPS analysis indicates that a significant amount of aromatic carbon appears on the surface of the 325 and 350 °C reaction residues, coincident with

T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

325

FID response

FID response

21000 16000 300°C (x=0.26)

11000 6000

5

10

15

20

25

30

35

40

11000

0

45

5

10

15

20

25

30

35

40

45

21000 16000

FID response

FID response

0

350°C (x=0.38)

11000 6000

41000

400˚C (x=0.34)

31000 21000 11000 1000

1000 5

10

15

20

25

30

16000

35

40

375°C (x=0.67)

11000

0

45

FID response

0

FID response

375°C (x=0.31)

21000

1000

1000

6000

5

10

15

20

25

30

41000

35

40

45

425°C (x=0.42)

31000 21000 11000 1000

1000 5

10

15

20

25

30

16000

35

40

400°C (x=0.86)

11000

0

45

FID response

0

FID response

31000

6000

5

10

15

20

25

30

101000

35

40

45

450°C (x=0.72)

81000 61000 41000 21000 1000

1000 0

5

10

15

20

25

30

35

40

45

minutes

0

5

10

15

20

25

30

35

40

45

minutes

Fig. 11. Gas chromatography of remaining high-sulfur oil after reacting with MgSO4 (left side) and remaining high-sulfur oil after thermal alteration without MgSO4 (right side) at different temperatures at 20 °C/h heating rate. The numbers in the bracket below the temperature labels are the n-C25 conversion index which indicates the reaction extent of TSR and TCA.

observed cracking of normal paraffins, indicating that TSR facilitates the decomposition of paraffinic hydrocarbons and the production of an aromatic carbon residue on the mineral surfaces. As a result, the saturate/aromatic ratio in remaining oils becomes smaller as TSR proceeds. This is consistent with the geochemical observations of oil compositional changes after experiencing TSR (Manzano et al., 1997). The thiophenic sulfur in the residue is interpreted as reduced sulfur that is incorporated into the aromatic organic char as a by product of this modeled TSR reaction system. Table 7 shows that the ratio of aromatic carbon to thiophenic sulfur stays remarkably constant (4.2–5.9) between 375 and 550 °C, indicating that nearly all of the aromatic carbon is associated with thiophenic sulfur structures. Organic oxygen species are present at relatively constant levels throughout the experimental temperature range, while CO2 yield as an indication

of hydrocarbon oxidation constantly increases with temperature. Obviously, TSR promotes aromatization, and the incorporation of sulfur and oxygen into hydrocarbons. The residues from the experiments suggest that the chemical nature of reservoir pyrobitumens may be diagnostic for the occurrence of TSR. This may be particularly insightful in cases where the H2S from TSR was precipitated as metal sulfides (Machel, 2001) or migrated from the trap that underwent TSR. The organic solids formed in the experiments are consistent with naturally occurring TSR solid bitumens. Kelemen et al. (2007) report that sulfur rich organic solids from TSR associated reservoir rocks from the Madison and Nisku formations are highly enriched in aromatic carbon structures, have little or no nitrogen, and contain organic sulfur almost exclusively in aromatic form.

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0.6

0.4

0.4

Pr/nC17

Pr/nC17

Low-sulfur oil 0.6

TCA

0.2

High-sulfur oil

TCA

0.2 TSR

TSR

0 300

0 325

350 375 400 Temperature (°C)

425

300

450

325

350 375 400 Temperature (°C)

425

450

0.8

0.6 Ph/nC18

Ph/nC18

0.6 0.4 TCA

0.2

TCA

0.2

TSR

0 300

0.4

TSR

0 325

350 375 400 Temperature (°C)

425

450

300

325

350 375 400 Temperature (°C)

425

450

Fig. 12. Pr/n-C17 and Ph/n-C18 ratios in oils that experience TSR obviously decrease compared with those by thermal chemical alteration alone.

5. Conclusions Quantification of gas yields (C1–C5, H2S, and CO2), the residual saturated hydrocarbon fractions of pyrolysates, and generated pyrobitumen from a series of gold tube hydrous pyrolysis experiments were carried out and provided a unique opportunity to investigate gas generation and the oxidation of hydrocarbons by sulfate reduction before significant thermal cracking of hydrocarbons occurred. The principal findings of this study are as follows: (1) H2O/MgSO4 mole ratio determines the intensity of TSR, the smaller the ratio, the stronger the oxidizing conditions. At the low H2O/ MgSO4 mole ratio conditions, anhydrous MgSO4 solid is the main reactive oxidant towards hydrocarbons. (2) HSO 4 is thought to be the reactive sulfate species in aqueous MgSO4 solution under our high temperature conditions due to the precipitation of a magnesium hydroxide sulfate mineral (MHSH), which lowers pH of the aqueous solution. (3) Thermal stability of oil is affected by thermochemical sulfate reduction (TSR) in geological settings. The temperature required for TSR is

(4)

(5)

(6)

(7)

less than that of hydrocarbon thermal cracking. As a result, TSR can dramatically lower the thermal stability of oil. TSR preferentially generates methane and gas dryness is proportional to the extent of the TSR reaction. The distribution C8–C35 n-alkanes is not significantly altered in oil as it undergoes TSR in the laboratory experiments. Pr/n-C17 and Ph/n-C18 ratios decrease in oils exposed to simulated TSR compared to oils that undergo thermal cracking. TSR promotes aromatization, and the incorporation of sulfur and oxygen into hydrocarbons. As a result, a decrease in the ratio of saturated to aromatic hydrocarbons in residual oils and an increase of sulfur and oxygen content in pyrobitumen may be observed with the progression of TSR. Methane can be oxidized to CO2 by TSR; however, the reaction rate is relatively slower than heavier gaseous hydrocarbons (C2–C5).

Acknowledgements This research was supported by the Joint Industrial Program on Thermochemical Sulfate

T. Zhang et al. / Organic Geochemistry 39 (2008) 308–328

Reduction at the Power, Environmental and Energy Research Center at Caltech. Industrial sponsors include BP, ChevronTexaco, ENI, ExxonMobil, SaudiAramco, Shell Oil and Total. The technical review by M. Lewan, P. Lillis and D. Nichols from USGS Energy Resource Surveys Team were helpful and constructive to improve the manuscript. This work benefited from collaborations and discussions with many colleagues, and we would especially like to thank H. Wycherly, M. Haught and X. Zhang for constructive discussion and P. Kwietak for performing the XPS analyses. The authors also extend their thanks to the reviewers Dr. C. Ostertag-Henning and Dr. R. Hill. Associate Editor—Rolando di Primio

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