SPE 165437

See discussions, stats, and author profiles for this publication at: http://www.researchgate.net/publication/267461543 Using Geochemistry to Address H2S Production Risk due to Steam Injection in Oil Sands ARTICLE · JUNE 2013 DOI: 10.2118/165437-MS READS 31 2 AUTHORS: Claire Barroux Violaine Lamoureux-Var IFP Energies nouvelles IFP Energies nouvelles 11 PUBLICATIONS 36 CITATIONS 22 PUBLICATIONS 50 CITATIONS SEE PROFILE SEE PROFILE Available from: Violaine Lamoureux-Var Retrieved on: 25 September 2015 using a dedicated technique. Electronic reproduction. Society of Petroleum Engineers This paper was prepared for presentation at the SPE Heavy Oil Conference Canada held in Calgary. Hoffman et al. illustrations may not be copied. (1995). 11–13 June 2013. Aromatics. Thimm. The reservoir simulation can only be predictive if it integrates smartly the reactional mechanisms yielding to H2S production. Chakrabarty and Smith. Uzcategui et al. it was shown that the sulfur in the oil sand. can be interpreted in terms of sulfur-based kinetic model.SPE 165437 Using Geochemistry to Address H2S Production Risk due to Steam Injection in Oil Sands Violaine Lamoureux-Var and Claire Barroux. Solid matrix and H2S. Clark et al. The geochemical methodology has been applied to four oil sand samples from Athabasca. These include in particular the works published by Hyne et al. (3) transforming this sulfur-based kinetic model into a molecular SARA components-based kinetic model. As detailed in another SPE paper (Barroux et al. thus for estimating the H2S production potential. evidencing modifications in oil composition and H2S generation. Chen et al. This model can be used for a calculation of H2S generation upon aquathermolysis at field production temperature and time scale. But only a few contributions are leading to kinetic models describing H2S generation. Since the 1980s numerous aquathermolysis experiments have been performed at relevant temperatures for steam injection processes. Alberta.. Attar et al. One main finding of this study has been that the H2S/oil ratio at the wellhead appears to depend mainly on the stoichiometry of the kinetic model. Canada. It relies on (1) a quick estimate. as a function of time and temperature of aquathermolysis. 1984... or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. (1991). from which a kinetic model can be derived and implemented in a reservoir simulator. H2S production risk is particularly acute in oil sand reservoirs because they contain sulfur-rich bitumens. the duration of steam/rock contact and the amount and type of sulfur in presence (Greidanus et al. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Lamoureux-Var et al. the reservoir simulation is the most comprehensive tool but also the most complex to handle. called aquathermolysis. To quantitatively forecast this risk.. (1984). 2012). To forecast H2S production risk in these conditions. (2011). (2002). usable in a compositional and thermal reservoir simulator. to define a kinetic model for H2S generation based on atomic sulfur thermal reactivity. Lamoureux-Var and Lorant. reservoir simulation has been used to simulate a SAGD process in a generic 2D model of an Athabasca oil sand. (2) carrying out more time-consuming aquathermolysis experiments on oil sand samples selected from step 1. (1984). Resins. Chen et al. Attar and coworkers (1984) have proposed a relevant kinetic model for H2S generation due to steam exposure. 2013). or members. (4) simulating the EOR process with the reservoir simulator to calculate H2S/oil ratio at the wellhead. Introduction Enhanced oil recovery by steam injection in oil sands induces chemical reactions within the reservoir. 1984.. The results have underlined that sulfur content and sulfur thermal reactivity of oil sands measured with the quick estimation technique are well correlated with the amount of H2S produced from the more lengthy aquathermolysis experiments. Permission to reproduce in print is restricted to an abstract of not more than 300 words. its officers. of sulfur content and thermal reactivity of a large number of reservoir samples to map the H2S production risk over the field. (2011). which can lead to H2S production (Hyne et al. which depend primarily on the temperature of steam. Asphaltenes. Belgrave et al. 2001. 1977. Hyne et al. The material does not necessarily reflect any position of the Society of Petroleum Engineers. called aquathermolysis. The quality of the prediction depends then on the synergy developed between the reservoir simulation and the geochemistry. 2005). which can lead to in-situ H2S generation and to H2S production at the wellhead.. Moreover. 2005a. a workflow based on geochemical investigation and reservoir simulation has been developed. The abstract must contain conspicuous acknowledgment of SPE copyright. based on the quantitative transformation of the main groups of organo-sulfur compounds . Hongfu et al. IFPEN Copyright 2013. Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). Song et al. (1994). 1991. when distributed among Saturates. Abstract Steam injection for enhanced oil recovery induces chemical reactions within the reservoir. (1990). distribution. Laboratory aquathermolysis experiments allow the study of the chemical mechanisms and the quantification of the H2S source terms as a function of the key-parameters. In these high temperature conditions. 2011. from observations made by Chen and coworkers (1991) and from our own results presented here. was distilled. This comprehensive model. Surmont (Lower Manville Group. could allow for delimitating at low cost the areas of high H2S production risk. this model. N-pentane and dichloromethane solvents. Three other teams (Ibatullin et al. H2S has been assumed to come from two sulfur classes in the Resins. From the model calibration step. these contributions being reviewed in Barroux and coworkers (2013).. Field Fisher field Leismer field Resdeln field Ethel Lake field TABLE 1 . describing the oil composition and the generation of different gases including H2S. The Asphaltenes are assumed to be the only organic source of H2S. with newly published related experimental data. The samples were obtained from the Oil Sands Sample Bank of Alberta. 2010. each class having a different H2S generation potential. Belgrave and coworkers (1997) have proposed a kinetic model for aquathermolysis. This technique. 2008. Lloydminster Formation). based on atomic sulfur distribution among the oil SARA fractions. based on the hydrothermal cracking of oil. 1990. However. is tough to calibrate. On receipt in our laboratories. We present also a new method allowing for reducing the number of the lengthy aquathermolysis experiments needed to build the sulphur-based kinetic model. maybe predominantly -.. comprising heavy Saturates+Aromatics+Resins. Resins are hosting the major part of sulfur of heavy oils and bitumen and are the most labile oil components with the Asphaltenes. Lamoureux-Var and Lorant (2005b. based on a large number of organo-sulfur components. It has been derived from aquathermolysis experiments at temperatures between 360°C and 420°C that are much higher than the ones prevailing in steam injection conditions. In this paper we present the kinetic model proposed by Lamoureux-Var and Lorant (2005b. 2008. were obtained from Air Liquide and were used as received. Uzcategui et al. and "light oil" comprising light Saturates+Aromatics+Resins. Thimm (2008) has proposed a simple model for a first estimation of H2S production using a pseudo-zero order kinetic reaction calibrated on production data. "heavy oil". describes the oil as the composition of three fractions: "Asphaltenes". Lamoureux-Var and Lorant.. and some results of reservoir simulation that have been obtained using it. 2007). used for gas chromatography analysis. for using the information delivered by this model in a compositional and thermal reservoir simulation. and appears too complex for being used in reservoir simulation. are expected to occur. they were mixed for homogenization and then stored in a glass bottle at 5°C. Kapadia et al. 2010 through 2012) have recently published works on reservoir simulation integrating a kinetic model of H2S production. which integrates the parameters of the atomic sulfur-based model. Perez-Perez et al. Standard gases. if applied intensively on the whole field area. chemical phenomena. used for oil extraction.. 2005a). but does not relate the H2S production to the oil composition. This new method is presented in this paper and accompanied with results. from the Resins. This method is based on a technology allowing for fast characterization of sulfur hosted by sedimentary rocks and oils (Espitalié et al. Water. 2011). de-ionized and deoxygenized by nitrogen bubbling. This component-based model has been used to simulate a SAGD process using industrial reservoir simulation software (Barroux et al. 2011.2 SPE 165437 in oil. The used pseudocomponents represent the oil SARA fractions. Consequently. Barroux and coworkers (2013) have proposed a method for traducing this experimentally derived atomic sulfur-based kinetic model into a component-based kinetic model. This model appears to fit the majority of the Athabasca SAGD projects. were obtained from Rathburn and were used as received.. Athabasca Formation) and Orion-Hilda Lake (Upper Manville Group. other than those involved in the aquathermolysis reactions. This 4-reaction sulfur-based kinetic model does not handle oil molecular-type components. used for the aquathermolysis experiments. 2007) have proposed a kinetic model for H2S generation. issued from four Canadian oil sand production projects (Table 1): Foster Creek. Geochemical investigation Materials. Lamoureux-Var et al. Four oil sands were studied. 2013)..OIL SAND SAMPLES SELECTED FOR THIS STUDY Project Well name Formation Foster Creek AEC Fischer 12-22-70-4 Athabasca Christina Lake PCP PCR Leismer 6-16-76-6 Athabasca Surmont Gulf Resdeln 5-24-83-7 Athabasca Orion Hilda Lake Norcen YBR Cold Lake OV 12-17-64-3 Lloydminster Core number 002: 446-455m 002: 365-374m 007: 346-362m 001: 438-446m . Then this approach suffers from a lack of intrinsic predictive value given that steam processes on different fields of Alberta can produce very different quantities of H2S because of noticeable differences in bitumen sulfur content or reactivity (Clark et al. Christina Lake. and two sulfur classes in the Asphaltenes.. it appears that H2S comes also significantly.. the solid matrix and H2S. But. . from a calibration with a sulfured reference sample. Each gold tube was then placed in an autoclave equipped with a thermocouple set in contact with the tube. Sulfur characterization is relying on two successive stages: an open pyrolysis under nitrogen flow of a small aliquot of bitumen (~5mg) followed by an open oxidation under air flow of the residual bitumen after pyrolysis. even the available quantities are small. For the oil sand from Foster Creek. and as the walls of the tube are thin enough. and the residual sulfur content. Aquathermolysis experiments for quantifying H2S generation. The amount of sulfur released at each stage is deduced. Then it is pierced and the whole gas is recovered using cryogenic traps at approximately -180°C. the sulfur contained in the bitumens is progressively released by cracking and converted into SO2. the C14+ oil SARA composition of oil is calculated. P~1 bar). corresponding to the Asphaltenes insoluble in n-pentane (ASP). i. then recovered and quantified together with the free gas. a gas line with a pressure gauge allowing for applying a fixed isotropic pressure around the gold tube. The pyrolizable sulfur being assumed to be more labile to thermal treatment than the residual sulfur. At this stage. giving four bitumen samples and four solid samples. The four initial oil sands were extracted with dichloromethane.. which is monitored continuously. Sulfur content of the solid samples was analyzed by direct elemental analysis using coulometry detection. the conditions of ideality being practically met. Sulfur content and sulfur thermal reactivity of the initial bitumens were analyzed with a RockEval-based technology. for the pyrolysis stage.e. which are weighed after solvent evaporation. At the end of each run. at different temperatures in the range from 240°C to 320°C. data of pyrolyzable sulfur content presented hereafter can be considered as more accurate than the ones previously published by Lamoureux-Var and Lorant (2005a).5g and 5g according to the heating conditions. During this thermal treatment using specific temperature programs. two sulfur contents being calculated: the pyrolyzable sulfur content. dissolved gas in oil and water. CO2. The total sulfur content of the sample is the sum of pyrolyzable sulfur content and residual sulfur content. An aquathermolysis experiment consists in heating an oil sand aliquot.SPE SPE 165437 3 Fast method for sulfur characterization of oil sands. to quantify its organic elemental carbon content and to estimate its proportion of pyrobitumen. Bitumen analysis. This new technology has been improved from the one proposed by Lorant and coworkers (2005) since the pyrolyzable sulfur content is now measured directly (instead of being deduced from the residual sulfur content and the total sulfur content measurements as in the original methodology). iC4H10 and nC4H10 per gramm of initial oil sand is estimated rather accurately. and by RockEval 6. The mass of the oil sand aliquot was between 0. The n-pentane solution is separated by a preparative medium pressure liquid chromatography into three fractions: C14+ Saturates (SAT). XRD and Rock-Eval 6 screening indicated that the solids were mainly composed by sand but also by some clay minerals and traces of organic compounds. together with pure water and nitrogen. The feed is extracted with n-pentane (nC5) and then with dichloromethane (CH2Cl2) to recover the C14+ oil cut and to separate it from the sand. is also weighed after solvent evaporation. After gas analysis. The atomic sulfur. 1998). by coulometry for S and by thermal conductivity for C and H. From all these data. the absolute yield of H2S. H2. The oil sand aliquot and water were precisely weighed (accuracy ± 0. at different times and temperatures. insoluble in dichloromethane. CH4. which was extended to sulfur analysis (Espitalié et al. Experiments. This residue is composed of the mineral phase (mainly sand) and potentially of a pyrobitumen. insoluble in the dichloromethane. an organic material resulting from thermal alteration of bitumen. The gas sample is then stored in an ampule and transferred onto a gas chromatograph to analyze its molecular composition. under fixed and constant temperature and pressure. Once filled with the reactants. It is analyzed by direct elemental analysis. So the composition and the mass of the reactants were precisely controlled (± 1 mg). Consequently. several experiments were carried out under 100bar. The gas pressure is measured in a calibrated volume and its molar amount is deduced using the ideal gas law. the gold tube is removed from the vacuum line and opened. the gold tube is rapidly cooled down to room temperature and then depressurized down to 10-5 bar at about 70°C on a vacuum line. the C5-C13 oil cut and water are lost in the vacuum line. to quantify its carbon and sulfur elemental contents. Solid analysis. For each of the four oil sands. Due to these pressure and temperature conditions. the pressure outside the gold tube is almost entirely transmitted to the reactants inside. dedicated to the characterization of organic matter of sedimentary rocks (Lafargue et al. 2008 and 2010). during 203 hours. the set of mineral and pyrobitumen is named "Solid" (SLD). This pyrobitumen behaving as a solid in in-situ conditions due to its high density and viscosity. The residue. Gas analysis. As gold is a ductile material. the mass of added water was determined to get a water/oil volume ratio close to 1. The four oil sands were submitted to aquathermolysis experiments. for the oxidation stage. C3H8. is recovered and weighed.. By combining all experimental data. this sulfur content split can be used as an indicator of two levels of thermal reactivity of sulfur. The sulfur content and the sulfur thermal reactivity of the four initial oil sand samples were quantified. The dichloromethane solution. and adsorbed gas on solids are expected to be respectiveley exsolved and desorbed. additional experiments were performed during 24 hours in the same range of temperatures. C2H6. carbon and hydrogen mass contents of each SARA fraction are quantified by direct elemental analysis. the gold tube was sealed in the glove box by ultrasound welding to prevent any oxygen pollution and any vaporization of the reactants. C14+ Aromatics (ARO) and Resins (RES).5 mg) and settled in the gold tube in a glove box under nitrogen atmosphere (%O2<50 ppm. in a closed and static gold tube. Clark et al.. as explained above. C14+Saturates (SAT). in this case experimental data are considered unusable. The sulfur mass balance is calculated on the following fractions: H2S.98 4. H2S. The Figure 1 emphasizes that the pyrolyzable sulfur content of the four initial bitumens increases with their total sulfur content. 1990) and depends on the amount sulfur in bitumen and its type (disulfides. thiols.. Such correlation has been also found for heavy oils from Petrocedeño field in the Orinoco belt in Venezuela (Uzcategui et al. and the level of H2S production risk. rt is used as an indicator for the quality of the experimental results: a too low value of rt reveals an excessive loss of products during their recovery. 2005). 2011).. etc. and can be split into pyrolyzable sulfur and residual sulfur.. 1990 through 1992. The global mass balance equation should take into account the C5-C13 oil cut and the water content. is defined by: mt Gas + mt C14+Saturates + mt C14+Aromatics + mt Resins + mt Asphaltenes + mt Solid (1) rt = mi oil sand where mioil sand is the initial mass of the oil sand used in the aquathermolysis run.1 . H2S generation and sulfur thermal reactivity.. rt.1 <0.95 3. The C14+ saturates are not taken into account as they are assumed not to contain significantly sulfur. whatever there is steam or not. C14+ aromatics. The initial sandy solids and the initial bitumens. is calculated. Song et al. sulfides. This confirms that the pyrolyzable sulfur content could be a relevant indicator of the sulfur thermal reactivity. The total mass of the following fractions: C1 to C4. dibenzothiophenes.07 4. The initial sandy solids have been found not to contain any significant sulfur: S< 0.1 <0.13 5.0001 [g S]/[g Solid] (Table 2).0488 and 0. the recovery ratio at time t of aquathermolysis. This sulfur is organic.. were analyzed separately for sulfur characterization. mt water < mi water. resins.93 SAND S gS/gSand *100 <0.1 <0.28 0. TABLE 2 – SULFUR CONTENTS OF THE INITIAL OIL SANDS S FOSTER CREEK CHRISTINA LAKE ORION HILDA LAKE SURMONT 5. This variability has been already noticed by different authors (Hyne et al. This suggests also that the pyrolyzable sulfur content could be used as proxy for identifying oil sands likely to generate H2S under steam treatment. Experimental results and Discussion Sulfur and sulfur thermal reactivity of the initial oil sands.4 SPE 165437 Mass balance and estimation of C5-C13 oil cut. both being not measured: (2) mi oil sand + mi water = mt Gas + mt C14+Saturates + mt C14+Aromatics + mt Resins + mt Asphaltenes + mt Solid + mt C5-C13 oil + mt water Rearranging equations (1) and (2). we can see that both are well correlated (Figure 3).88 5. Asphaltenes/nC5 (ASP) and Solid (SLD).15 0. The experimental results of aquathermolysis on the four oil sand samples show that the H2S yield varies significantly from one sample to another (Table 3.) (Katritzky et al.23 4.0566 [g S]/[g Bitumen] of total sulfur (Table 2). 1984.66 BITUMEN S Pyrolyzable S Residual after pyrolysis gS/gBitumen *100 4. it comes: mt C5-C13 oil = mi oil sand (1 − rt) + mi water − mt water (3) Considering that the net water balance is negative i. By plotting the H2S yield versus the pyrolyzable sulfur content of the initial bitumens. CO2. The analytical results showed that the initial bitumens contained between 0. Figure 2).73 0. the mass of C5-C13 oil cut is in the range given by the following inequalities: mi oil sand (1 − rt) < mt C5-C13 oil < mi oil sand (1 − rt) + mi water (4) This is the way used for quantifying the upper limit of C5-C13 oil cut in the results of aquathermolysis experiments reported hereafter. Resins (RES).81 1. benzothiophenes. asphaltenes and solid. meaning that it is linked to the hydrocarbon chains that compose the bitumens.e. Sulfur mass balance. H2. C14+Aromatics (ARO).. Consequently it has been considered that the initial sands can be practically excluded from potential sources of H2S during steam treatment. obtained from solvent extraction of the initial oil sands. Each dotted line is associated to a specific temperature of aquathermolysis run.8 Aquatherm olysis tem perature.8 5. Table 4). .Simultaneously. The results show that with increasing aquathermolysis severity (increasing duration or temperature): .C14+ bitumen proportion in oil sand decreases. despite very low values.SPE SPE 165437 5 Pyrolyzable and Residual Sulfur g S / g bitumen *100 Orion Hilda Lake Foster Christina Creek Lake Surmont 5 S Pyrolyzable 4 3 S Residual after pyrolysis 2 1 0 4. g S / g bitum en *100 Figure 2: H2S yield from aquathermolysis experiments (t=203h) Figure 3: H2S yield from aquathermolysis experiments (t= 203h). lose hydrogen and are enriched in sulfur compared to their mass and to their carbon content (Figs.2 4. 5 through 7. .4 to 0.2 5.06 wt%.C14+ aromatics increase significantly. then this suggests that the aquathermolysis reactions are inducing the formation of small quantities of pyrobitumen.0 4. . lose hydrogen and sulfur (Figs. °C Pyrolyzable Sulfur in initial bitum ens. the carbon in the solid matrix after aquathermolysis is mainly organic: the organic carbon content in solid varies from 0. The SARA composition of the Foster Creek bitumen was quantified after 24 hours and 203 hours of aquathermolysis.8 4. compared to pyrolyzable sulfur content in bitumens.6 3.Resins and asphaltenes. Surmont mg H2S / g initial bitumen 14 16 Surmont Christina Lake Foster Creek Orion Hilda Lake 12 10 8 6 4 320°C Christina Lake 14 mg H2S / g initial bitumen 16 12 Foster Creek 10 8 Orion Hilda Lake 6 300°C 4 280°C 2 2 0 220 240 260 280 300 320 340 260°C 240°C 0 3.02 to 0. If this organic carbon content increases effectively with increasing aquathermolysis severity as it seems on Figure 8. representing more than 60 wt% of the initial bitumen. Table 4).8 wt%. Evolution of bitumen composition. this being well correlated with an increase of light oil and gases (Table 4 and Figure 4). decrease significantly.0 5. According to RockEval6 analyses. whereas the mineral carbon content in solid varies from 0. a sulfured solid is generated. 5 through 7.8 Total sulfur g S/ g bitum en *100 Figure 1: Sulfur content in initial bitumens.4 5. whatever organic and/or mineral as seen in Figure 7. .6 4.4 4.6 5. 7 27.8 22. TABLE 3 – H2S YIELD Aquathermolysis Aquathermolysis FOSTER CREEK CHRISTINA LAKE ORION HILDA LAKE SURMONT temperature.1 1361. 203h) 20 60 100 140 180 220 260 300 340 Aquatherm olysis tem perature (°C) Figure 5: C14+ oil SARA composition after aquathermolysis of Foster Creek oil sand (t=203h) .40 C14+ oil composition (g/g) C14+ oil / initial oil sand.4 24.3 42.5 22.8 995.(3) 13% 12% 11% 203 h Resins 0.7 Total 859 862 865 870 872 869 870 871 872 875 882 968 981 988 994 995 991 994 995 996 1001 1005 32 19 12 6 5 9 6 5 4 0 0 Upper Recove limit of ry C5-C13 factor oil cut in rt oil Eq.2 1 0.30 Aromatics C14+ Saturates C14+ 0.8 15. TABLE 4 – COMPOSITION OF THE BITUMEN .1 28.5 C14+ AsphalAromatics Resins tenes mg/g initial oil sand 32.8 24.6 1807.6 30.3 20.7 39.9 23. (4) wt.9 40.8 23.9 42.5 23.5 4807.7 2526. showing a kinetic phenomenon.7 29.2 43.4 44.6 SPE 165437 .5 2241 300 203 1362 244 684 532 790 13 280 203 996 101 753 362 2244 0 589 399 260 203 1808 9 1179 223 240 203 2527 2 320 24 3804 413 300 24 4808 151 280 24 5710 18 260 24 7677 9 240 24 8028 4 α: mg of Initial oil sand in aquathermolysis runs.8 0. °C Figure 4: C14+ oil proportion in oil sand after aquathermolysis of Foster Creek oil sand (t=24h.3 0 24.2 23.6 30.3 C14+ Gas Saturates 5.FOSTER CREEK AquaAquathermolysis thermolysis duration temperature °C h 320 203 300 203 280 203 260 203 240 203 320 24 300 24 280 24 260 24 240 24 / / Initial oil sand mg 416.7 28. β: µg H2S / g initial oil sand from the aquathermolysis runs.0 31.1 44.10 240 260 280 300 320 340 Aquatherm olysis tem perature.6 44.9 26.1 0.4 0.25 0.(1) Eq.0 29.0 8027.6 3803.1 2.0 31.9 31.6 22.% 97% 24% 98% 14% 99% 9% 99% 5% 99% 4% 99% 7% 99% 5% 99% 4% 100% 3% 100% 0% 100% 0% 0.3 25.6 42.5 25. g/g*100 14% Solid Upper limit of C5-C13 oil cut in oil sand Eq.7 29.5 25.6 0. H2S generation increases as seen in Table 3.9 25.6 2.9 24.7 24.35 Asphaltenes 0.Simultaneouly.20 0.6 2554.15 24 h 10% 220 0.2 46.5 5710.1 1. °C hours α β α β α β α β 320 203 416 882 328 1169 374.1 7677.5 28.4 23. duration.5 30. wt% 0.SPE SPE 165437 7 Asphaltenes C14+ Aromatics 1.1 1. H2S and the solid sulfur.48 0. °C Figure 6: Atomic composition of the fractions after aquathermolysis of Foster Creek oil sand (t=203h). measured by Rock-Eval 6. asphaltenes. probably a sulfured pyrobitumen and possibly sulfur bearing minerals.44 0.72 0.4 1. g S/ g fraction*100 Resins 1.64 0. mol/mol 1.4 220 240 260 280 300 320 340 Tem perature of aquatherm olysis. whatever they are formed directly or indirectly. From these data the sulfur distribution among the C14+ aromatics.6 0. It appears clearly in Figure 9 that a part of sulfur initially present in resins and asphaltenes has been redistributed into C14+ aromatic sulfur.3 1. The arrows indicate the increasing aquathermolysis temperature.52 24 h 0.56 203 h 0. m ol/m ol Aquatherm olysis tem perature. The simplest interpretation of these results is that resins and asphaltenes are progressively cracked during aquathermolysis. resins.8 0.0 1 2 3 Sulfur in fractions. solid and H2S. Figure 7: Sulfur content in the SARA fractions after aquathermolysis of Foster Creek oil sand (t=203h) 0. was deduced (Table 5).68 0.5 H/C. . °C Figure 8: Total organic carbon content in the solid matrix after aquathermolysis of Foster Creek oil sand (t=24h. 203h). H2S and a sulfured solid. generating sulfured C14+ aromatics.2 1.76 TOC in solid.6 8 7 Resins 6 Asphaltenes 5 C14+ Aromatics Solid 4 3 2 1 0 4 20 60 100 140 180 220 260 300 340 S/C*100. 02 0.00 0.15 0.36 0.39 0.44 0.23 0.21 0.34 0.00 0.13 0.18 0.00 .02 0.34 0.27 0.44 0.21 0.25 0.43 0.43 0.19 0.06 0.00 0.20 0.04 0.14 0.15 0.8 SPE 165437 TABLE 5 – ELEMENTAL SULFUR DISTRIBUTION AMONG THE FRACTIONS – FOSTER CREEK Aquathermolysis temperature Aquathermolysis duration Gaseous S (H2S) Aromatic S °C 320 300 280 260 240 320 300 280 260 240 / h 203 203 203 203 203 24 24 24 24 24 0 0.25 0.19 0.20 0.18 0.19 0.20 0.00 0.00 0.40 0.21 0.18 0.46 0.00 0.26 0.00 0.20 0.38 0.38 Solid S 0.27 0.34 0.36 0.23 0.00 0.01 0.32 0.00 0.18 Resinic S Asphaltenic S Normalized mass of Sulfur 0. 12 0.1 203h 0.05 24h 0 220 0. g/g S in H2S / S.e).08 0.21 203h 0. °C e 24h 240 260 280 300 320 Aquatherm olysis tem perature. g/g 0. 203h). Fig.25 S in Solid/ S.16 0. °C 340 20 60 100 140 180 220 260 300 340 Aquatherm olysis tem perature. °C 340 f 203h aquathermolysis 50% 0.5 0.4 0. g/g 0.25 0.23 0. °C d 0.04 203h 240 260 280 300 320 0.25 0.1 203h 0.SPE SPE 165437 9 a b 0. (f) synthesizes the data at 203h. H2S (c) and the Solid (d) vs Foster Creek oil sand aquathermolysis temperature (t=24h. g/g S in Aromatics C14+/ S.15 0.35 0.3 0.17 0.35 0.3 203h 24h 0.15 0.45 0. °C c 24h 0 220 240 260 280 300 320 340 Aquathermolysis tem perature.27 0.29 0.3 0. g/g S in Resins / S.b.4 S in Asphaltenes / S. .31 40% 30% 20% Resinic S Asphaltenic S Aromatic S Solid S Gaseous S 10% 0% 240 260 280 300 320 Aquatherm olysis tem perature.2 0.2 340 0 220 Aquatherm olysis tem perature. g/g 0.45 0.05 240 260 280 300 320 340 Aquatherm olysis tem perature.25 0.2 220 0.19 24h 0. °C Figure 9: Sulfur distribution among the SARA fractions (a.15 220 S in fractions/ S. the « gaseous sulfur ».5 kcal/mol) and generates only pyrobitumen.e. ARO S . as a first approximation. This kinetic model has been used for simulating. a sulfur-based kinetic model for H2S yield has been derived and calibrated from the sulfur distribution data among resins. sulfured aromatics and pyrobitumen. i.60 S + 0.mol-1) is the activation energy. on a year time scale (Figure 10). In the same way. whereas the other one is more refractory to aquathermolysis (EARES2 > EARES1) and generates only H2S. We can see two types of sulfured resins in this set of reactions: the first one is labile (EARes1 is low =48. i. For fulfilling the elemental sulfur mass balance.40 SSLD RES2 H2S EARES2 = 55. two for the resins and two for the asphaltenes. the fraction of atomic sulfur contained in hydrogen sulfide. solid and H2S (TABLE 5) (Lamoureux-Var and Lorant. and the activation energies are presented hereafter: EARES1 = 48. the « aromatic sulfur ».6 kcal/mol As the number of constraining experimental data was limited. Freitag and Exelby. i. the bottom hole temperature in Foster Creek project.K-1).mol-1 or kcal. and T is the temperature (K).8 kcal/mol SRES1 → 0.64 1018day-1. i. the reaction rate being directly proportional to the concentration of the reactant: d[SRES]/dt = -KrRES [SRES] and d[SASP]/dt = -KrAsp [SASP]. 2008. the « solid sulfur ». It is assumed that sulfur in resins and sulfur in asphaltenes are the only reactants. ASP S . The obtained values represent the H2S production potential.33 S S EA = 54.22 SH2S + 0.mol-1.2 kcal/mol S → S (8) ASP1 SLD EAASP1 = 48. the fraction of atomic sulfur contained in the C14+ aromatics. 2007). the fraction of atomic sulfur contained in the solid matrix. this order of magnitude being considered as relevant for oil cracking (Behar et al.e.314 J. the fraction of atomic sulfur contained in the asphaltenes. R is the universal gas constant (R=8. the fraction of atomic sulfur contained in the resins. The sulfur species are: RES S . the sum of stoichiometric coefficients per reaction r is equal to unity. asphaltenes. which appears to be drastically influenced by the temperature between 170°C and 220°C at the production time scale. H2S S .e.e. the « asphaltenic sulfur ».38 SARO + 0. two types of sulfured asphaltenes are considered: the first one is labile (EAASP1 is low =48. Sulfur in C14+ aromatics has not been considered as a reactant. and lower temperatures.07 S + 0. year Figure 10: H2S production potential computed with the kinetic sulfur-based model 15 . The reactions. the H2S generation at various temperature conditions: 220°C. 1100 220°C LH2S / m3 initial bitumen 1000 900 800 700 200°C 600 500 400 190°C 300 200 180°C 100 170°C 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Tim e. i.8 kcal/mol) and generates H2S. the value of the frequency factor Ar was set to 1014 s-1=8. C14+ aromatics. (6) The constant rates Kr are functions of temperature. 2006). following the Arrhenius law: (7) EAr  Kr = Ar exp−  R T where EAr (kJ. 2005a.10 SPE 165437 Geochemical kinetic model On the basis of the observations and statements presented above.5 kcal/mol S → S ASP2 H2S ARO SLD ASP2 → 0.e. whereas the other one is more refractory (EAASP2 > EAASP1) and generates mainly sulfured aromatics and pyrobitumen. The kinetic system has the following form: SRES → a1 SH2S + a2 SARO + a3 SSLD  (5) SASP → b1 SH2S + b2 SARO + b3 SSLD  RES ASP S and S are each the single reactant for at least one first-order kinetic reaction.. using GeoKin software. SLD S . the « resinic sulfur ». Ar (s-1) is the frequency factor. They have then applied this methodology to get a SARA components-based kinetic model.American Chemical Society. 29(4). This model. 1994. characterizing the sulfur compounds in the solid matrix. 2013. Sulfur Functional Groups in Heavy Oils and their Transformations in Steam Injected Enhanced Oil Recovery. of simplifications. thermal and reactive reservoir simulation. Forecastingof H2S Production due to Aquathermolysis Reactions. V. the 4-reaction sulfur-based kinetic model is not usable in a compositional. Flauraud. as is.experimental study and compositional modelling of molecular classes. F. (39)6. Organic Geochemistry. to be further checked and validated. br EAr activation energy of reaction r Kr constant rate of reaction r R ideal gas constant T temperature References Al Darouich. What will be considered in a next future are the improvements in the experimental protocol which could contribute to reduce the number of experimentally unconstrained parameters: measuring the molecular weight of the SARA-type pseudocomponents. Mazeas. 2008. • the unique solid product of reactions.. 37 (9). L. paper presented at the Symposium on the Chemistry of Enhanced Oil Recovery .Division of Petroleum Chemistry. for discriminating the mineral sulfur from the organic sulfur. using XRD. Aknowledgments The authors would like to acknowledge Dr. Bahrain. a 4-stage methodology is proposed: (1) screening sulfur properties of a large number of reservoir samples to rapidly delimitate the areas over the field where a risk of H2S production exists. A. Such an adsorption phenomenon could be partly taken into account by modifying the reactions stoichiometry. there are a number of subjacent hypotheses. Thermal cracking of the light aromatic fraction of Safaniya crude oil . Manam. and for identifying and providing relevant oil sand samples used in this work. Barroux. designing experiments to address the hypothesis of gas adsorption on the solid matrix. presented at the SPE Middle East Oil and Gas Show and Conference. at reservoir scale during a steam-based EOR process. • an adsorption phenomenon on a solid is very sensitive to the solid specific area. Attar. R. No experimental measurement of the molecular weight of the SARA fractions has been available for this work. et al. provides an estimation of the maximum potential of H2S production. considered in the reservoir simulations. . Largeau. 1984. F. A first step has consisted in validating this model by the reservoir simulation of the aquathermolysis experiments. but also to the attribution of given molecular weights to the SARA-type pseudo-components. quantifying the light oil C5-C13. C. given that any reservoir simulation software is not handling atoms. has not been well defined. 511-516. but molecular-type components. A hypothesis of H2S adsorption on solid species produced by the reactions is formulated for explaining the observed differences in H2S production between the laboratory results and the field measurements.. Conclusions For predicting.. Lorant.. Elaboration of a new compositional kinetic schema for oil cracking. The authors would like to acknowledge Dr.SPE SPE 165437 11 Reservoir simulation As is.. The reaction model has been then input in a 2D reservoir model built using generic properties for an Athabasca oil sand. Pauline Michel for reviewing and for valuable comments. 764-782 Belgrave. then simulating aquathermolysis experiments for validating the component-based kinetic model. and then deriving a sulfur-based kinetic model. F. In particular: • the stoichiometry of the reactions is related not only to the sulfur-based kinetic model presented here.G.. E. R. R. Canadian Journal of Chemical Engineering. Organic Geochemistry. (2) quantifying the H2S source terms using aquathermolysis experiments on some relevant reservoir samples selected from (1).G.M. Behar. 1212-1222. thermal and reactive reservoir simulator. Ursenbach. SEM and Rock-Eval+Sulfur. A. (3) traducing the sulfur-based kinetic model into a SARA component-based kinetic model with consistent component thermodynamic properties. 2006. T. Barroux and coworkers (2013) have proposed a methodology for traducing the sulfur-based kinetic model proposed here above in reactions where reactants and products are the components (or pseudo components) used for the fluid thermodynamic modeling. Verona D. As stated by the authors. for numerous valuable discussions and suggestions. Lamoureux-Var. J.. C. Moor. Gas evolution from the aquathermolysis of heavy oils. The results of SAGD reservoir simulations in terms of H2S/oil ratio at well head versus time are found to depend strongly on the stoichiometry of the reactions. this letting the reaction model for reservoir simulation unconstrained concerning the component molecular weights. Paper SPE 164317. (4) simulating the production process using the reservoir simulation software. Villoria. the H2S/oil production ratios.1130-1154. F... Behar. usable in a compositional. 72(3).D.. Eric Delamaide from IFP Technologies (Canada) Inc. Nomenclature Ar Frequency factor of reaction r stoichiometric coefficient of sulfur species k in reaction r ar. 47(1).. Perez-Perez A.D.d petroleum products. J. D. Aquathermolysis of Heavy Oils. Energy & Fuels. Hongfu. V. MacDonald.. 2011. I. J. Simulation of Hydrogen Sulfide and Carbon Dioxide Production during Thermal Recovery of Bitumens. N. Beicip-Franlab. E. 2005..100–111. 38-44. 2010.. Lapucha. Energy & Fuels ( 6).0 Reference Manual.L. 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