A
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ALBERTA SULPHUR RESEARCH LTD.
Center for Applied Catalysis and Industrial Sulfur Chemistry
University Research Centre, #6 – 3535 Research Road N.W.
Calgary, Alberta, Canada T2L 2K8
Country Code: 001 Area Code: 403
Office: 220 – 5346 Fax: 284 – 2054 E-mail: [email protected]
Website: www.albertasulphurresearch.ca
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ASRLCORERESEARCHPROGRAM
2015‐2016
Prepared by P.D. Clark
Director of Research, ASRL
and professor of Chemistry, University of Calgary
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Pietro Di Zanno ‐ AIR LIQUIDE GLOBAL E&C SOLUTIONS CANADA LP Pierre Blais ‐ BAKER HUGHES Elise Mophett ‐ BASF CATALYSTS LLC J. K. Chen ‐ CHEVRON ENERGY TECHNOLOGY COMPANY Vincent W. Wong ‐ FLUOR CORPORATION Jon Gorrie ‐ HUSKY ENERGY INC. Sander Kobussen ‐ JACOBS /COMPRIMO, SULFUR SOLUTIONS Nate Hatcher ‐ OPTIMIZED GAS TREATING INC. Alfred Keller ‐ PHILLIPS 66 COMPANY Bruce Klint ‐ SULPHUR EXPERTS INC. Gavin Proudfoot ‐ SUNCOR ENERGY Bill DeWees ‐ WORLEYPARSONS Paul Davis ‐ ALBERTA SULPHUR RESEARCH LTD. Peter Clark ‐ ALBERTA SULPHUR RESEARCH LTD. Norm Dowling ‐ ALBERTA SULPHUR RESEARCH LTD. Rob Marriott ‐ ALBERTA SULPHUR RESEARCH LTD. Melerin Madekufamba ‐ ALBERTA SULPHUR RESEARCH LTD. ASRL is a not-for-profit, self-governing Company in the Province of Alberta and
is affiliated with the Department of Chemistry, The University of Calgary
LISTOFCORERESEARCHPROJECTS
1. Decomposition of NH3 in the Claus Furnace Commercial Objective To obtain rate data for decomposition of NH3 under Claus furnace combustion conditions Project Description Previously, ASRL has deduced from individual component studies that decomposition of NH3 in a Claus combustion chamber occurs, in large part, by reaction with SO2 which is formed by the rapid oxidation of H2S in both the AG and SWSG. So rapid is the oxidation of H2S that it is unlikely that any of the extra O2 added for the NH3 is available for direct oxidation of NH3. Further analysis of the original ASRL data has led to publication of kinetic expressions for reactions of NH3 with all of the major components, with one exception, found a typical Claus furnace (Alberta Sulphur Research Ltd. Quarterly Bulletin No.171 Vol. LI No.3 October‐December, 2014, pp. 47‐74). That major exception is S2 but this possible conversion pathway was studied theoretically (Marriott, Lo and Clark, ASRL Chalk Talk, January 2015) and shown to be unimportant compared to reaction with SO2. In the 2015/16 period, studies will be conducted to determine global rates of conversion of NH3 under full feed conditions to ascertain the effects of sulfur species which form part of the Claus equilibria as these species can act chemically in the same way as SO2 (Figure 1). Figure1.FULLFEEDKINETICDATA
SWSG
[NH3, H2S, H2O]
Process Gas
Air
[H2S [H2O, CO2]
AG
2 H2S + SO2
[H2SXOY]
3/
2
S2 + 2 H2O
•
Obtain kinetics for 2:1 and 4:1 H2S / SO2 outlet ratio at respective
adiabatic temperatures [various tres]
•
Compare to equivalent NH3 / SO2 data set
Objective : Obtain full feed data sets for kinetic analysis
and determine efficacy of split flow designs
Specific objectives (a) Publish the results of the theoretical studies on conversion of NH3 by S2 (b) Conduct full feed experiments with AG/SWSG mixtures to determine global kinetics for NH3 conversion at Claus furnace conditions (see Figure 1) 2
2. Controlling Sulfur Pit Fires Commercial Objective To measure and understand flammability limits in a sulfur pit fire Project Description Sulfur stored in air drafted sulfur pits is held at a temperature range of 135 – 150° C, significantly below the auto‐ignition temperature of 240° C. However, fires occur quite frequently with static electricity and pyrrophoric iron sulfide being the most common ignition sources. The usual way of handling a pit fire is to purge the head space with low pressure steam which serves to extinguish the fire and cool the pit down. The question is how much steam and for how long. The last question is easily answered as time of steam flow relates to reduction of the internal pit temperature below the auto‐ignition temperature but how much steam is required to quench a fire is not clear. This matter relates to the flammability range for a steam, sulfur vapour air mixture. Although stopping air flow and introducing steam until all air is purged from the head space seems self evident, the educator systems and/or direct connection to the stack may prevent cessation of air flow, so requiring a detailed knowledge of the flammability limits for steam – air – sulfur vapour mixtures. Specific Objectives Review literature on sulfur flammability and conduct laboratory tests to determine effective steam – air ratios required to extinguish sulfur fires (Figure 2). Figure2.LIMITINGAIRCONCENTRATION(LAI)FORSULFURFIRES
N2 (diluent)
N2, O2, SO2
mixing
Air
to scrubber
& vent
S8
T/C
1
2
to melt S and
initiate fire with air flow
vary N2 flow / concentration of air until flame extinguishes
3
calculate LOC = 0.209 x LAI
3
3. Corrosion in Tail Gas and Sulfur Pit Off‐Gas Lines Commercial Objective To understand the mechanisms of corrosion in Claus off‐gas lines Project Description Over the past year, our studies have shown that rapid carbon steel corrosion occurs ( ca. 70 mpy) when sulfur is deposited at conditions in which the water dew point is reached (ca. 70° C for tail gas lines). Such conditions could be attained in tail gas lines which are either poorly insulated or with insufficient heating. Also, it was shown that corrosion occurs at slow, but appreciable rates (5 – 7 mpy), when the surface of the carbon steel has a surface film of iron oxide (January, 2015 Chalk Talk). Here, it is proposed that the surface film promotes either the Claus reaction or oxidation of H2S to sulfur producing acidic species and more sulfur at the surface. Since these reactions also produce H2O at the surface, corrosion may occur even though no liquid water may have been present originally (Figure 3). Normally, one would expect rates of corrosion to increase with increasing temperature, but, in this case, it is assumed that corrosion will stop because of rapid loss of H2O from the surface. H2O is required to solvate the ferrous/ferric and sulfide species formed in the corrosion reactions. Consequently, future studies will address the impact of higher temperatures to conclude the ongoing work. Figure3.CORROSIONINCLAUSTAILGAS– PITOFFGASLINES
H2S, SO2
H2S / SO2
S8(vap), H2O
S8 / H2O
Incinerator
CO2 – N2
S8 deposition
Claus reaction
• Fe / S8
Fe S
• Claus H2 SX OY
‐ What is the rate of corrosion (carbon steel, SS, alloys) above / below sulfur dew point?
‐ Acidic corrosion?
Specific Objectives Conclude ongoing studies (Figure 4) and determine the impact of increasing temperature on corrosion of tail gas and pit off‐gas lines. Figure4.CORROSIONINCLAUSTAILGASANDPITOFFGASLINES
New and Continuing Research Item
• Complete work with “rusted” coupons over several cycles
and measure corrosion rates at higher temperatures (135 - 140°C)
• Determine composition of black film in rusted coupon experiments
• Examine corrosion rates for 316-SS
4
4. Degradation of Amines Commercial Objective To deduce the mechanism for degradation of some alkanolamines under contactor/regenerator conditions Project Description Over the last 4 years, ASRL has conducted a research program with the objective of determining mechanisms for degradation of alkanolamines used in gas sweetening. Studies on DEA and MDEA have shown that O2 ingress into the contactor would be a major contributing factor to amine degradation but, because O2 reacts quickly with H2S to form sulfur, amine degradation occurs by reaction with sulfur, most likely at the higher temperature condition found in the regenerator. Also, it has been shown that the consumption of O2 by H2S in the contactor is promoted by the FeS scale on the surface of all components of the contactor. Thus, sulfur formed by O2 ingress circulates through the system until it is fully consumed, under basic conditions, forming thiosulfate, or in amine degradation reactions. These latter reactions result in production of organosulfur compounds, some of which become hydrolyzed to classic amine products such as bicine. A similar observation has also been made for use of MDEA in tail gas units but, in this case, the sulfur is formed by breakthrough of SO2 to the amine unit. It has been suggested that this research be extended to study MEA, an amine still used in many gas processing applications. Specific Objectives To determine degradation pathways for MEA under both storage and application conditions (Figure 5) and examine the influence of pH on thiosulfate formation Figure5.DEGRADATIONOFMEA
•
Determine kinetics of degradation of MEA under the following conditions
HO CH2 CH2 NH2(aq)
(Air)
Stability on
storage
H2S-CO2
[O2]
Effect of O2 (in situ S8)
at contactor and regenerator
conditions
H2S-CO2 [O2, FeS]
Influence of corrosion
scale on degradation
at contactor and
regenerator conditions
Objective : To compare MEA to DEA and MDEA
5
5. Formation of H2S in Shale Gas Reservoirs (Dr. Marriott, NSERCC – ASRL Professorship Program) Commercial Objective To understand and eventually estimate the delayed souring of shale gas reservoirs Project Description During the early evaluation of a shale gas fluid, H2S is often found in very small and sometimes negligible quantities; however, after some time (months) of production, H2S concentrations can increase and often show inconsistencies when compared to the early flow test results. While several mechanisms for reservoir souring can be considered, we have begun exploring the delayed souring of shale gas fluids through reactions involving fracture fluid additives. While the compatibility and performance of fracturing fluid additives have been investigated, little research has been conducted on the post‐fracturing fate of these components. Our initial work focused on the degradation and reaction of sodium dodecyl sulfate (SDS or SLS), an anionic surfactant used as a friction reducer and emulsion inhibitor. Laboratory studies demonstrated that native sulfide can be initially reduced and H2S is reproduced over a long period of time [P. Pirzadeh, K. L. Lesage and R. A. Marriott (2014) Hydraulic fracturing additives and the delayed onset of hydrogen sulfide in shale gas, Energy and Fuels 28(8), 4993‐5001; see figure 6]. Recent studies are focusing on the rapid reaction of oxygen (dissolved in the fracture fluid) with H2S to produce sulfur and sulfate. Sulfur and sulfate proceed to slowly oxidize other fracture fluid additives (e.g., guar) in order to reproduce the native H2S which was present before fracturing. Kinetic studies are being performed in order to gain a better understanding of these reactions under high‐temperature and high‐pressure conditions. This work is being supported by an NSERC discovery grant program. Specific Objectives Current studies are aimed at (i) the evaluation of the ionic strength dependence on the overall reaction rate for SDS and (ii) measuring the sulfur oxidation rates for a series of alcohols and other fracture fluid additives. Thermodynamic and kinetic modelling is ongoing. Figure6.ASIMPLIFIEDMECHANISMFORSDSDEGRADATION,
SCAVENGINGH2SANDRE‐RELEASEOFH2S
Fraction of H2S in production fluid
Hot reservoir
500 ppm H2S
(Native)
SLS + H2O
Intermediate temperature
Native reservoir H2S level
Cooler reservoir
Time after fracture
6
H2S breakthrough
6
6. Claus Conversion in Sulfur Condensers (Projects 6 and 7 received equal weighting for the TAC Members) Commercial Objective To enhance the efficiency of existing Claus sulfur recovery systems by catalytic conversion in the condenser Project Description Over the last two years, we have examined the potential for increasing conversion to sulfur in a standard Claus plant by incorporating catalyst in the condenser tubes. Calculations conducted for ASRL (D. Cicerone, 2013) reveal that a significant part of the tube remains in the gas phase offering the potential for further conversion to sulfur as the process gas temperature decreases in the tube. ASRL laboratory studies have shown that approximately 30 % extra conversion can be obtained. The improvement in sulfur conversion (Figure 7) illustrate that ca. 97 % conversion to sulfur can be realized after the first converter – condenser array suggesting a sulfur plant with reduced equipment needs (Figure 8) is plausible. The catalyst section after the WHB could be housed in a pipe or as part of the first condenser. This high temperature catalytic zone allows approximately 20 % extra conversion to sulfur and 96 % CS2 destruction when a high activity catalyst is used. Figure7.THEORETICALSTUDYONSULFURRECOVERYINASULFUR
PLANTUSINGHTCONVERTERANDCATALYTICCONDENSERS
Air
1st Converter
Steam
HT Converter
94% H2S 1% CS2
5% H2O
Catalytic Condenser
S8 = 97.0%
(91.3%)
H2O
2nd Converter
S8 = 78.9%
(73.9%)
• Plant operated at a 2:1 ratio
• ( ___%) = Plant without catalytic condensers or HT converter
• HT converter operating temperatures is 375°C
• 1st converter operating temperatures are 240°C and 301°C
for plants with and without catalytic condensers
• 2nd converter operating temperatures are 185°C and 213°C
for plants with and without catalytic condensers
• 3rd converter operating temperatures are 157°C and 178°C
for plants with and without catalytic condensers
• All converters operated with a 10°C dewpoint margin
S8 = 99.5%
• Assumes 21 % steady‐state conversion in HT converter
(99.0%)
and 30% steady‐state conversion in catalytic condensers
Catalytic Condenser
S8 = 99.1% (97.8%)
3rd Converter
Catalytic Condenser
Tail Gas Unit
7
Figure8.RESULTSOFSULFURRECOVERYINASULFURPLANTUSING
HTCONVERTERANDCATALYTICCONDENSERS
Air
1st Converter
Steam
HT Converter
94% H2S 1% CS2
5% H2O
Catalytic Condenser
S8 = 97.0%
H2O
TGTU
S8 = 78.9%
• Plant operated at a 2:1 ratio
• HT converter operating temperatures is 375°C
• 1st converter operating temperatures are 240°C and 301°C
for plants with and without catalytic condensers
• 1st converter operated with a 10°C dewpoint margin
• Assumes 21 % steady‐state conversion in HT converter
and 30% steady‐state conversion in catalytic condensers
S8 = 99 % +
Liquid Sulfur (S8)
After 1st converter catalytic condenser stage, process gas can be sent to directly send
to TGTU. No need of 2nd and 3rd converter stage.
HT converter enhanced the CS2 conversion and may reduce the dissolved H2S level
in liquid S8 in the furnace condenser.
The objective of the future work is to validate that the catalytic sections in a catalytic condenser operate in the gas phase (Figure 9) and to determine space velocities required for the various condenser conditions. Figure9.FUTUREWORK
For catalytic condenser experiment at converter stage: Planning to have a
condenser made from glass instead of stainless steel, to see the deposition
of liquid sulfur on the catalyst bed during Claus reaction at sub-dew point
temperature.
Stainless steel
Glass
Condenser Condenser
Claus conversion at high space velocity 10,000 h-1 or above will be
investigated both at thermal stage HT converter, as well as at 1st converter
stage catalytic condenser.
Specific objectives Use a glass condenser reactor to ascertain mode of operation of a catalytic condenser and determine conversion factors (sulfur and CS2) for specific catalysts (ASRL high performance and standard alumina). A study will also be performed to determine if NH3 conversion occurs in the high temperature catalytic condenser. 8
7. Primary Upgrading of Oil Sands Bitumen for Transportation (Projects 6 and 7 received equal weighting for the TAC Members) Commercial Objective To reduce the viscosity of oil sands bitumen so removing the need for use of diluents during transportation Project Description It has been shown that oil sands bitumen can be converted to a low viscosity material with reduced sulfur content and increased API by heating with small quantities (5 ‐ 15 %) of synthetic crude oil (SCO). This relatively simple process (Figure 10) has the potential to greatly improve the economics of bitumen transportation because diluents, either SCO or hydrocarbon condensates, now used in 30 and 50 % volumes respectively, are no longer required to achieve pipeline specifications. This potential technology also would enable an approximate 40 % increase in existing pipeline capacity. Figure10Update:PRIMARYUPGRADINGOFOILSANDSBITUMEN
A Possible Process Scheme Using Synthetic Crude Oil
Off-gases [H2S, C1-C5, CO2, NH3]
Raw
Bitumen
(S  5 wt %)
•
T ≈ 400 - 425°C
Synthetic
crude oil
S ~ 0.1 wt %
Crude oil mixture Filtration Pipeline
[S  2.5 wt %]
Updated results presented (Chalk Talk, Jan. 2015)
•
Key Conclusion
 Ratio SCO: Bitumen --- 5:95-25:75
 Temperature --- 400°C-415°C (to prevent
coking)
 Time --- 0-60 minutes
•
Test other Bitumen and light crude oils
Since further development of this process requires testing in a continuous flow mode, ASRL has contacted member companies to raise funds for such a test program. These efforts will be coordinated by ASRL and Alberta Innovates, an organization founded by the Alberta Government for the purpose of developing new technology to facilitate oil sands developments. The general objectives of this ASRL Special Project are outlined in Figure 11. Figure11.PRIMARYUPGRADINGOFBITUMENFORDILUENT‐FREE
TRANSPORTATION
New Objectives:
1. Conduct preliminary economic study (underway by Mike Priaro,
Consulting Engineer)
2. Announce to ASRL members as Special Project
3. Work with ASRL members, AIEES and PTAC to raise funding for
pilot scale work (Special Project)
Specific Objective To organize a Special Project with participation of ASRL member companies 9
8. Determine Reaction Pathways for Methanol Decomposition in the Claus Furnace Commercial Objective Determine pathways for conversion of methanol in the Claus furnace Project Description Methanol can be found in acid gas as a consequence of its use as a hydrate inhibitor in natural gas production or due to its application in some gas processing technologies. Although methanol can be removed from acid gas by water washing before introduction into the Claus furnace, this step is avoided if at all possible. Equilibrium calculations suggest that methanol should decompose to CO/H2 at Claus furnace conditions but decomposition by other pathways or by oxidations involving sulfur species is also likely (Figure 12) and may give rise to kinetic products (CS2). In particular, the fate of methanol in a Claus furnace operating at low temperature (< 1,000° C) is of some concern as products could be formed which may have a deleterious impact on the downstream catalytic stages. Thus, the overall objective of this project is to determine methanol decomposition pathways under Claus furnace reaction conditions. Figure12.THEEFFECTOFMETHANOLONTHECLAUSFURNACE
DECOMPOSITION OF CH3OH IN CLAUS FURNACE
H2S / CO2
[H2O, CH3OH]
Claus converters
Hydrate inhibitor
Liq. S8
CH3 OH CO + 2 H2
CH3 OH H2 + H
H
CH3 OH + ½ O2
H2O + H
H
C=O
C=O
• Rxns with sulfur species (H2S, S2, SO2)
Specific objectives To determine the fate of methanol in the Claus furnace using acid gas compositions found in applications where methanol can be present (Figure 13) Figure13.METHANOLDECOMPOSITIONINTHECLAUS
FURNACE
Studies in Progress (March – June 2015)
1. Methanol decomposition in H2S / CO2 acid gas at 900, 1,000, 1,100
and 1,200°C [achieved by altering H2S / CO2 ratio].
2. Determine CH3 OH decomposition pathways from preceding study
Future Work
1. Effect of CH3OH and CH3OH decomposition products on the
catalytic converters.
10
9. Destruction of HCN in the Claus Furnace Commercial Objective To determine conditions for destruction of HCN in the Claus Furnace Project Description Coal gasification plants result in the production of acid gas which contains H2S, CO2 and HCN. The HCN is usually present in low quantities (< 1 %) but because CO2 may be present in large quantity, low adiabatic temperatures are experienced in the combustion chamber. At present, very little is known about the conversion of HCN under Claus combustion conditions although it is theorized that NH3 would be an intermediate product (Figure 14). The overall objective of this project will be to determine the mechanistic pathways and products of HCN destruction. [Note: this project can only be conducted if a suitable laboratory location can be fitted with HCN detectors] Specific objectives Determine mechanistic pathways for conversion of HCN and conditions required for complete HCN destruction (Figure 14) Figure14.DESTRUCTIONOFHCNINTHECLAUSFURNACE
11
10. The Dissociative Claus Process (Projects 10, 11, 12 and 13 received equal weighting from the TAC Members) Commercial Objective To explore H2S dissociation as a means of sulfur recovery Process Description Although H2S dissociation is well known as a means of converting H2S to sulfur, with production of H2 as a by‐product, no commercial process has been developed. The basic failings of all previous attempts are that the energy requirement to drive this endothermic process and procedures for H2 separation render the overall process uneconomic. The process outlined in Figure 15 shows utilization of the hydrogen product as fuel for the dissociation energy requirement, and, in principle, illustrates a simple and high thermal efficiency technology. The H2 is separated by conventional technology (Figure 15). Only very limited laboratory studies have been performed to date but results of these experiments suggest key factors are the need for rapid heat up and quenching of inlet and product gases. Loss of H2 and sulfur during quenching limits the amount of energy that can be delivered by combustion of H2 in the furnace, as well as lowering yields per pass. Nevertheless, the potential reduction in residence time and flow rates in comparison to the standard modified Claus process make the dissociative Claus process an attractive option. Figure15.THEDISSOCIATIVECLAUSPROCESS
P.D. CLARK, 28 Feb 2014
CH4/H2S/CO2
Amine
Unit
CH4 (H2O)
H2S [CO2,
H2O,CH4]
Tube Furnace WHB
Air
Steam (Amine Plant)
Flue Gas (N2, H2O, CO2, (ppmv SO2) ~1400°C
/\/\/\/\/\/\/
Re‐heat
Co‐Mo
H2O
Liquid S8
H2S re‐cycle (H2O) MDEA
H2 [CO, CO2]
[N2 also if NH3 is present]
Specific Objectives The aims of research on this topic would be to study methods for rapid heat and quenching of process gas streams and determine the impact of impurities in the acid gas (hydrocarbons, NH3) (Figure 16). Figure16.THEDISSOCIATIVECLAUSPROCESS
New Objectives:
H2S /
CO2
Use inert packing to
improve heat transfer
Gas sampling
Increase sampling efficiency
to reduce H2 /S2 back reaction
Overall: Complete studies for publication
12
11. Sulfur Recovery in Supercritical CO2 (Dr. Marriott, NSERC – ASRL Professorship Program) (Projects 10, 11, 12 and 13 received equal weighting from the TAC Members) Commercial Objective To explore the high‐pressure oxidation of low‐level H2S (<1%) in dense phase CO2 fluids Project Description Many low‐H2S fluids result in low H2S acid gas (< 1%; e.g., acid gas removal from shale gas fluids); therefore, conventional Claus recovery is not viable and scavenging technologies may not serve the larger scale of production. In some cases, it is beneficial for the cryogenic removal of low quality acid gas from a producing fluid which results in dense‐phase high‐pressure fluid (ExxonMobil CFZ, Total SPREX). Depending on the permitting of injection zones or the planned use of CO2 for enhanced oil recovery, the low‐levels of H2S will need to be removed from the CO2 fluid. Because dense‐phase CO2 will lower the temperature of the sulfur dew point (sulfur solubility in CO2 is larger than ambient pressure conditions), it may be possible to oxidize the H2S within the supercritical CO2 phase. Lower‐temperatures and higher pressures should increase recovery; however, temperatures in excess of 160°C may result in catalyst fouling. Early work is targeting a high‐pressure catalyst process between 125 and 150°C. New sulfur solubility data for elemental sulfur in supercritical CO2 are essential for the proper sulfur recovery process design and identifying the H2S concentration limits for this process. This work is being supported by an NSERC discovery grant program. Specific Objectives Before high‐pressure heterogeneous catalysis experiments can be planned, initial studies are aimed at measuring the sulfur solubility in high‐pressure CO2, Figure 17. Figure17.SULFURSOLUBILITYINSUPERCRITICALCO2
Keller transducer
SFT‐10 liquid CO2 pump
(maintaining CO2 pressure) GC oven (T control)
CO2 gas flow meter
Poppet valve 50 cm3 Sulfur column
Glass‐wool traps
CO2 (l)
Closed
Open
2
13
12. Thiol and Oxygen Removal before Amine Contact (Projects 10, 11, 12 and 13 received equal weighting from the TAC Members) Commercial Objective To explore the potential for supported nano‐gold catalysts within selective oxygen and thiol removal beds Project Description Several amine systems are not equipped to efficiently remove low‐levels of thiols. In addition, some production systems on vacuum or after flowback will show small quantities of oxygen which increase amine degradation and subsequently increase sacrificial amine make‐up. Could a guard bed system be used to protect the amine process (Figure 18)? Thiols are selectively adsorbed to gold in silica/gold froth floatation processes. Previous ASRL research has shown that supported nano‐gold is an effective oxidation catalyst. This early exploratory study will determine if gold catalysts (or aqueous gold suspensions) could be used to (i) selectivity remove thiols from produced fluids and provide a low temperature oxidation surface for the removal of small quantities of oxygen. Figure18.THIOLANDO2 REMOVALBEFOREAMINECONTACTOR
FEF
(CH4/H2S/
CO2/H2O)
To Amine
4O2 + 8H2S
S8 + 8H2O
Adsorbing
Bed
Desorbing
Bed
RSH(g) + A*
ARSH
Air or acid gas?
(CH4/H2S/CO2/O2/RSH/H2O)
Specific Objective Determine the thiol/H2S selectivity for (a) an ASRL nano‐gold catalyst, (b) a commercial supported gold catalyst and/or (c) suspended colloidal particles. If there is sufficient selectivity and/or oxidation activity, representative gas feeds and regeneration with hot acid gas will be explored. 14
13. Examination of VLE Data for Oil Mixtures (Projects 10, 11, 12 and 13 received equal weighting from the TAC Members) Commercial Objectives To determine VLE data for H2O + oil mixtures Project Description Crude oils, crude oil mixtures (dilbit, syn‐bit) are transported through pipelines and by rail in tank cars. Pipeline lengths range from short gathering lines to thousands of kilometers. Safe operation of these systems requires that the potential for corrosion be understood and minimized, which, in turn requires a knowledge of water content of the oil and the distribution of gases (H2S, CO2, CH4) between the phases. The National Energy Board of Canada requires that water content be < 0.5 % (is this low enough to prevent condensation of an aqueous phase?). In principle, VLE for such systems can be calculated using existing model data, but these models require a very complete characterisation of the oils which is often not available. Thus, the overall aim of this project is to obtain VLE data for some available oil mixtures and compare to pure hydrocarbons of known water solubility. In addition, measurements will be made to determine the efficacy of oil blankets for SW storage systems (Figure 19). Figure19.VLEMEASUREMENTSFOROIL‐ WATER‐ GASSYSTEMS
Study of SW Systems
• How quickly does H2S – NH3 saturate oil
layer?
H2S – NH3
NH3 – H2S
Oil layer • Does H S – NH partition to gas phase?
2
3
H 2O
• If air drafted – does S8 form in oil layer?
Specific objectives Measure VLE for selected oil – water – gas systems (Figure 20) and SW storage tanks (Figure 19) Figure20.UPDATE:MEASUREMENTOFVLEDATAFORPROCESSOIL–
WATER‐GASSYSTEMS.
Specific objectives:
(a) Literature search on available VLE data for CO2 and H2S in
water/oil and brine/oil systems.
(b) Design experiments to measure VLE data for such systems under
the following conditions: T = 25 - 80ºC, H2S/CO2 partial pressures
0 - 200 psig, oil 5-50 API.
(c) Derive model for the VLE data based on API.
15
14. Use of Aqueous Sulfites for H2S Scavenging Commercial Objective To explore the potential of aqueous sulfites for H2S scavenging Project Description Aqueous sulfites (ammonium or sodium) may represent a means of removing H2S for sour gases which contain relatively little total sulfur (up to 5 ton/day) as the products (thiosulfates, Figure 21) could be marketable commodities. Although it is well known that H2S reacts with sulfites, the chemistry is complex and dependent on pH. To date, sulfite‐based technology has not been developed commercially so it is proposed that ASRL review any published data and present a position paper to the membership on this topic. Figure21.H2SSCAVENGERSFORSMALLSCALETREATMENTS
(Member Suggestion)
Cleaned gas
Natural Gas/
Process Gas
(H2S)
Inorganic
Sulfites
Use or disposal
• Mx (SO3)y H2S
Mx (S2O3)y + S8 ?
• Are kinetics sufficient? Can a useful product be made? [eg. (NH4)2 S2O3]
Specific Objective Review literature on sulfites scavenging and publish a synopsis of existing work in the ASRL QB 16
15. Membrane Separation of Acid Gases Commercial Objective To develop improved membranes for separation of H2S and CO2 from hydrocarbon gases Project Description Membrane separation of acid gases from methane and other hydrocarbons has been a subject of considerable interest for many years as such systems should have a lower energy cost than conventional amines and other solvents. Working systems have been introduced to field applications but selectivity of existing membranes is insufficient to meet many potential applications. Selectivity is achieved by altering the surface properties of the exterior membrane surface such that the species to be removed are adsorbed preferentially. This is a significant challenge for acid gases as CO2 is a non‐polar, linear molecule whereas H2S has a permanent dipole. Given the large amount of work that has been conducted in this area by commercial laboratories, it is suggested that a review of existing membrane systems be conducted to ascertain what areas could be addressed in the ASRL laboratories. Specific Objective Review patent and open literature on membranes used for acid gas separations. 17