“…The hydrolysis of SDS is an autocatalytic process, where the presence of 1-dodecanol, low pH, and high-initial-concentration of SDS (above critical micelle concentration) accelerate the hydrolysis process. − In addition, earlier studies have shown that alcohols can undergo TSR reactions and produce comparable amounts of H 2 S with respect to equivalent unsaturated alkenes (at very low reaction rates) . Finally, it has been suggested that bisulfate anion (HSO 4 – ) rather than sulfate anion (SO 4 2– ) is the more reactive species involved in TSR that is eventually reduced to form a sulfide species; i.e., reaction kinetics are favored by acidic conditions. − Combining all these physicochemical features, it appears that SDS itself has all the required reactants to facilitate the TSR reaction under the right hydrothermal conditions. Following reactions –, a simplified reaction mechanism for the degradation of aqueous SDS in a sour shale reservoir is as follows:where the net reaction is…”
Section: Resultsmentioning
confidence: 99%
“…For conventional carbonate reservoirs, in addition to aquathermolysis and/or bacterial H 2 S generation, the thermochemical sulfate reduction (TSR) process is another pathway for generation of H 2 S under hydrothermal conditions. − With TSR, sulfate species are reduced under high-temperature and pressure at the expense of hydrocarbon oxidation; this process results in the formation of H 2 S, CO 2 and lighter hydrocarbons. − While TSR is a commonly accepted mechanism for the souring of conventional hot sour gas reservoirs, it is also well accepted that TSR proceeds very slowly over a geological time scale. − A simplified aqueous TSR mechanism for C x +1 H 2 x +4 in a conventional sour reservoir is given bywhere the net reaction for the oxidation of C 2+ species isBecause the hydrocarbon reduction (reaction ) is considered rate limiting and is very slow for light hydrocarbons, heavier hydrocarbons are required for more significant TSR rates. Simple saturated hydrocarbons, such as those found in low molecular weight gas reservoirs, do not react at an appreciable rate to see changes over the life of a production.…”
As natural gas production has shifted further from deep prolific gas reservoirs to shale gas, several questions are being addressed regarding fracturing technologies and the fate of chemical additives. A less investigated issue is the unexpected increase in produced hydrogen sulfide (H 2 S) from hot shale gas reservoirs. Understanding the source of H 2 S in shale reservoirs and managing low-levels of recovered elemental sulfur affects plans for future treatment, corrosion mitigation, and fracture fluid formulations. In this work we demonstrate that some typical ingredients of hydraulic fracturing fluids are not as kinetically stable as one might expect. Surfactants and biocides such as sodium dodecyl sulfate and glutaraldehyde are shown to undergo hydrolysis and thermochemical sulfate reduction reactions under moderate reservoir conditions, with H 2 S as the final product accompanied with long chain alcohols and hydrogen sulfate as long-lived intermediate species. This finding suggests that fracture fluid additives can be responsible for the delayed production of natural reservoir H 2 S.
“…The hydrolysis of SDS is an autocatalytic process, where the presence of 1-dodecanol, low pH, and high-initial-concentration of SDS (above critical micelle concentration) accelerate the hydrolysis process. − In addition, earlier studies have shown that alcohols can undergo TSR reactions and produce comparable amounts of H 2 S with respect to equivalent unsaturated alkenes (at very low reaction rates) . Finally, it has been suggested that bisulfate anion (HSO 4 – ) rather than sulfate anion (SO 4 2– ) is the more reactive species involved in TSR that is eventually reduced to form a sulfide species; i.e., reaction kinetics are favored by acidic conditions. − Combining all these physicochemical features, it appears that SDS itself has all the required reactants to facilitate the TSR reaction under the right hydrothermal conditions. Following reactions –, a simplified reaction mechanism for the degradation of aqueous SDS in a sour shale reservoir is as follows:where the net reaction is…”
Section: Resultsmentioning
confidence: 99%
“…For conventional carbonate reservoirs, in addition to aquathermolysis and/or bacterial H 2 S generation, the thermochemical sulfate reduction (TSR) process is another pathway for generation of H 2 S under hydrothermal conditions. − With TSR, sulfate species are reduced under high-temperature and pressure at the expense of hydrocarbon oxidation; this process results in the formation of H 2 S, CO 2 and lighter hydrocarbons. − While TSR is a commonly accepted mechanism for the souring of conventional hot sour gas reservoirs, it is also well accepted that TSR proceeds very slowly over a geological time scale. − A simplified aqueous TSR mechanism for C x +1 H 2 x +4 in a conventional sour reservoir is given bywhere the net reaction for the oxidation of C 2+ species isBecause the hydrocarbon reduction (reaction ) is considered rate limiting and is very slow for light hydrocarbons, heavier hydrocarbons are required for more significant TSR rates. Simple saturated hydrocarbons, such as those found in low molecular weight gas reservoirs, do not react at an appreciable rate to see changes over the life of a production.…”
As natural gas production has shifted further from deep prolific gas reservoirs to shale gas, several questions are being addressed regarding fracturing technologies and the fate of chemical additives. A less investigated issue is the unexpected increase in produced hydrogen sulfide (H 2 S) from hot shale gas reservoirs. Understanding the source of H 2 S in shale reservoirs and managing low-levels of recovered elemental sulfur affects plans for future treatment, corrosion mitigation, and fracture fluid formulations. In this work we demonstrate that some typical ingredients of hydraulic fracturing fluids are not as kinetically stable as one might expect. Surfactants and biocides such as sodium dodecyl sulfate and glutaraldehyde are shown to undergo hydrolysis and thermochemical sulfate reduction reactions under moderate reservoir conditions, with H 2 S as the final product accompanied with long chain alcohols and hydrogen sulfate as long-lived intermediate species. This finding suggests that fracture fluid additives can be responsible for the delayed production of natural reservoir H 2 S.
“…From these results, it may be concluded that some surface species, for example, adsorbed elemental sulfur, which formed from H 2 S and accumulated over the sorbent, contributed to the Hg removal even after the H 2 S feed was stopped. Considering the low mercury removal efficiency at reactor temperatures above 200 °C, it is likely that the elemental sulfur, which has an approximate melting point of 116 °C, is volatile at high temperatures and thus part of it may be released from the reactor. It is very likely that lattice oxygen and/or chemisorbed oxygen supported the transformation of H 2 S to active surface sulfur, which is active at 150 °C and can react with Hg 0 to form stable HgS. , The possible heterogeneous reactions over CeTi sorbents are proposed to be as follows:normalH2normalSfalse(normalgfalse)+normalO*→normalSfalse(adfalse)+normalH2normalOnormalSfalse(adfalse)+Hg→HgSS (ad) is active surface sulfur, and O* is surface oxygen of the CeTi sorbent. 3 Hg 0 removal efficiency with and without H 2 S injection.…”
A series of CeO2-TiO2 (CeTi) sorbents with different CeO2/TiO2 mass ratios were prepared by an impregnation method and employed to remove elemental mercury (Hg(0)) in simulated syngas. The CeTi sorbents with a CeO2/TiO2 mass ratio of 0.2 exhibited superior Hg(0) removal efficiency from 80 to 150 °C, which could be ascribed to the greater amount of surface chemisorbed oxygen resulted from Ce(3+) on the sample surface. H2S was the most effective syngas component responsible for Hg(0) removal. The use of 400 ppm H2S resulted in 98% Hg(0) removal efficiency under the experimental conditions. H2 and CO had a negligible effect on the efficiency of Hg removal. In the presence of H2S, a prohibitive effect of HCl and NH3 on Hg(0) removal was observed because of the consumption of the surface oxygen. Water vapor also inhibited Hg(0) removal due to competitive adsorption with H2S. Hg(0) removal over CeTi sorbents was proposed to follow the Eley-Rideal mechanism, in which active surface sulfur reacts with gas-phase Hg(0). This large oxygen storage capacity of CeTi sorbents is quite favorable to H2S catalytic oxidation and Hg(0) emission control in an extremely reducing environment, such as when there is a deficiency of O2.
“…As a result of these slow kinetics, the majority of the laboratory TSR experiments are carried out at temperatures above 250ºC up to 600 ºC in order to obtain enough product to overcome analytical sensitivity. 21 The reported activation energies for TSR range between E a = 77 and 250 kJ mol -1 , depending on the reaction conditions and reactants/products involved. 20,25,14 Various laboratory results show that the kinetics of TSR depends on the type of organic reductants, dissolved sulfate species and a variety of intermediate sulfur species.…”
Hydrogen sulfide (H2S) 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 and (or) thermochemical sulfate reduction. 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 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 H2S during production. A brief overview of the different classes of chemical reactions involved in the in situ generation and release of H2S is provided in this work. Speciation calculations and reaction mechanisms are presented to explain why thermochemical sulfate reduction progresses at faster rates under low pH. New studies regarding the degradation of a hydraulic fracture fluid additive (sodium dodecly sulfate) 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 thermochemical sulfate reduction studies at T > 300 °C. These two different kinetic regimes complicate the goal of extrapolating laboratory results for field-specific models for H2S production.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
