Hydrogen Sulfide Formation in Oil and Gas
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Canadian Journal of Chemistry Hydrogen Sulfide formation in Oil and Gas Journal: Canadian Journal of Chemistry Manuscript ID cjc-2015-0425.R1 Manuscript Type: Article Date Submitted by the Author: 18-Nov-2015 Complete List of Authors: Marriott, Robert; University of Calgary Pirzadeh, Payman; University of Calgary Marrugo-Hernandez, Juan; University of Calgary Raval, Shaunak;Draft University of Calgary Keyword: hydrogen sulfide, sulfur, conventional, unconventional, sulfate reduction https://mc06.manuscriptcentral.com/cjc-pubs Page 1 of 32 Canadian Journal of Chemistry Hydrogen Sulfide formation in Oil and Gas Robert A. Marriott, * Payman Pirzadeh, Juan J. Marrugo H. and Shaunak Raval Department of Chemistry, University of Calgary 2500 University Drive NW, Calgary, Alberta * E-mail: [email protected] , Tel: +1-403-220-3144 Draft 1 https://mc06.manuscriptcentral.com/cjc-pubs Canadian Journal of Chemistry Page 2 of 32 Abstract Hydrogen sulfide (H 2S) can be a significant component of oil and gas upstream production, where H2S can be naturally generated in situ from reservoir biomass and from sulfate containing minerals through microbial sulfate reduction (MSR) and/or thermochemical sulfate reduction (TSR). On the other hand, the technologies employed in oil and gas production, especially from unconventional resources, also can contribute to generation or delay of appearance of H2S. Steam assisted gravity drainage (SAGD) and hydraulic fracturing used in production of oil sands and shale oil/gas, respectively, can potentially convert the sulfur content of the petroleum into H2S or contribute excess amounts of H 2S during production. A brief overview of the different classes of chemical reactions involved in the in situ generation and release of H 2S is provided in this work. Speciation calculations and Draftreaction mechanisms are presented to explain why TSR progresses at faster rates under low-pH. New studies regarding the degradation of a hydraulic fracture fluid additive (sodium dodeclysulfate) are reported for T = 200°C, p = 17 MPa and high ionic strengths. The absence of an ionic strength effect on the reaction rate suggests that the rate limiting step involves the reaction of neutral species, such as elemental sulfur. This is not the case with other TSR studies at T > 300°C. These two different kinetic regimes complicate the goal of extrapolating laboratory results for field specific models for H2S production. Keywords: hydrogen sulfide, sulfur, conventional, unconventional, sulfate reduction 2 https://mc06.manuscriptcentral.com/cjc-pubs Page 3 of 32 Canadian Journal of Chemistry Introduction Over the 50 year history of the Department of Chemistry at the University of Calgary, both industry and academic researchers have enjoyed a strong collaborative interface through Alberta Sulphur Research Ltd. (ASRL). As early as the 1940s, the oil and gas industry had begun reducing SO 2 emissions through H 2S separation and conversion to elemental sulfur through the Claus process. During the 1950s, increased production of sour gas (natural gas containing H 2S) in Canada, brought with it several new challenges, including sulfur deposition, increased corrosion, sulfur handling and transportation logistics. Moreover, a key component of the continued research activity in this field is the need for elemental sulfur or more specifically sulfuric acid, which is necessary to produce the massive quantities of fertilizer required to feed a much larger world population. Still, a compellingDraft fundamental question remains an active area of research: “where is all the H2S coming from?” Ignoring the cases where fluids from different subsurface zones become mixed, many hydrocarbon reservoirs contain native H 2S and CO 2 which have been geologically generated in situ . On average, sulfur constitutes about 1% of the dry mass of living organisms, with cysteine and methionine amino acids being the major contributors to this portion; therefore, some H2S can 1 come from the degradation of biomass. Sour gas fluids have been produced with up to 94% H 2S, suggesting that a large portion of H 2S has originated from sulfate minerals, especially in carbonate reservoirs. Other fluids can chemically produce H 2S through the various anthropogenic processes that are used activate the flow of hydrocarbon through formations and into wellbores. In either case, H 2S must be anticipated for a variety surface facilities, removed from sales fluids 3 https://mc06.manuscriptcentral.com/cjc-pubs Canadian Journal of Chemistry Page 4 of 32 (treated), chemically scavenged, recovered as elemental sulfur or other sulfur-bearing products, or returned to subterraneous formations via a process called acid gas injection. The first portion of this study contains a brief review of three reservoir souring mechanisms: (i) aquathermolysis, (ii) microbial sulfate reduction (MSR) and (iii) thermal sulfate reduction (TSR). All three mechanisms can be responsible for the appearance of native H 2S (natural) and anthropogenic H2S (caused by production stimulation). With the non-biological cases of H 2S production, there have been several laboratory and field studies aimed at understanding and modelling H 2S production kinetics. In the more recent cases, it has been noted that (a) many laboratory experiments require higher-than-reservoir temperatures to effectively study reaction rates and (b) extrapolating the kineticDraft results to reservoir temperatures may be flawed due to different mechanisms in various temperature regimes. Further information is required in this area to build fit-for-purpose models to estimate the extent and timing of H 2S concentration changes over the life of commercial production. New experiments into shale gas souring are reported here, where TSR involving fracture fluid additives can result in (a) the scavenging of native reservoir H 2S during stimulation and (b) the regeneration of H 2S after hydrocarbon production begins. Like previous TSR studies, we have recently investigated reaction rates involving sodium dodecyl sulfate at high-ionic strengths and T = 200°C. Results reported in this study show no significant change in reaction rate with increased ionic strength, suggesting that the rate limiting step involves a reaction between two neutral reactants. Alternatively, higher-temperature TSR experiments from literature suggest that ionic strength does increase reaction rates. Re-analyzing the latter results suggest that the 4 https://mc06.manuscriptcentral.com/cjc-pubs Page 5 of 32 Canadian Journal of Chemistry dominant controlling mechanisms for laboratory reactions at T > 300°C is thermolysis rather than S° reduction, dominant at T < 300°C. These two different kinetic regimes must be considered and distinguished (if possible) when extrapolating TSR rates from high-temperature laboratory experiments to reservoir conditions. 2. Primary Sources of H 2S in Produced Hydrocarbons 2.1 Aquathermolysis (Cyclic Steam Stimulation and Steam Assisted Gravity Drainage) While many hydrocarbon reservoirs will contain native or natural H2S (considered sour), many heavy oil reservoirs are sweet with the majority of sulfides being bound within organosulfur species or metal sulfide. Examples include the oil sands within Northern Alberta and Venezuela. While the later bituminous hydrocarbonDraft reserves do not contain native H2S, the stimulation of flow by the introduction of high-pressure steam causes the thermochemical production of H 2S, CO 2, CO, H 2, CH 4 and other minor hydrocarbons. As a result, the associated sour gases produced at surface often contains up to ca. 5% H 2S which must be removed (treated) and converted to elemental sulfur (recovered) to avoid extraneous SO2 emissions. Because steam reformation is too slow at in situ steam stimulation conditions, the steam reformation of hydrogen and subsequent hydrogenation of organosulfur compounds is rarely considered as the major pathway for H2S production. As a result the hot liquid water phase is thought to be the reactant contributing to H 2S production. High-temperature liquid water undergoes increased dissociation, thereby allowing for several reactions between liquid water and organic molecules which would otherwise not proceed at temperatures less than T = 200°C. For 200 < T < 300°C (accompanied by high-pressures) the complex reactions between water and 5 https://mc06.manuscriptcentral.com/cjc-pubs Canadian Journal of Chemistry Page 6 of 32 hydrocarbons are referred to as “aquathermolysis” whereas at T > 300°C, hydrous pyrolysis or thermal cracking is the major contributor to hydrocarbon reactions.2,3,4 These two different chemical regimes were defined through the early work of Clark and Hyne, 3 who studied the formation of CO 2 and H 2S through aquathermolysis of alkyl sulfides, thiophenes and sulfide containing asphaltenes. The C-S bond is weak in comparison to C-C bonds; therefore, reaction with high-temperature acidic H2O or H 2 normally comes at the expense of more organosulfur species when compared to non-sulfur-containing hydrocarbons. Clark et al .3 later found that, in general, sulfur containing asphaltenes lead to the majority of produced H 2S. Near 300°C and above, various high-valence cations are also thought to provide a catalytic effect. 3 It should be noted that the degradation of organosulfur species and H 2S production through aquathermolysis does not lead to a significant desulfurisationDraft of the oil, i.e. , normally not considered worthwhile process for partial oil upgrading.