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With the issuance by the Alberta Energy Resources Conservation Board and Alberta Environment of their report entitled Sulphur Recovery Guidelines for Sour Gas Plants in Alberta in August of 1988, the requirement in Alberta to recover sulfur was broadened to a sulfur content of 1 tonne/D or greater in the inlet gas to a new sour-gas treating plant. This paper reviews the processes in use for recovering sulfur from sour-natural-gas streams that have a total sulfur content of 5 tonne/D or less. These processes are the modified Claus process, the recycle Selectox process, and the reduction/oxidation processes LO-CAT and SulFerox. While the modified Claus process is used in large sulfur-recovery plants, the other processes may be more economical for sulfur recovery on a small scale. A description of the sour-gas treating and sulfur-recovery processes is given, and a comparison of estimated capital and operating costs for typical sour-gas streams is provided.
All of the above processes are in operation in North America. Operating experiences with these processes in Alberta are discussed. The quality of the end-product sulfur varies among these processes, and the options for sulfur disposal are reviewed.
Approximately 40% of the natural gas produced to date in Alberta was sour; i.e., it contained some hydrogen sulfide (H2S). Most of the H2S that was extracted from the sour natural gas was treated in modified Claus plants to recover elemental sulfur. When the quantity of sulfur as H2S was less than 10 tonne/D entering a sour-gas plant (before 1989), the usual method of disposal of the sulfur was the flaring of the H2S and the CO2 through plant flare stacks by adding sweet gas to the acid-gas stream. After 1988 in Alberta sulfur had to be recovered if the gas contained 1 tonne/D or more in the sour gas of new plants.1 Between 1 and 5 tonne/D, the sulfur-recovery efficiency requirement is 70%.
Since 1989, several plants have been built in Alberta for the recovery of less than 5 tonne/D of sulfur. Various technologies have been applied to suit the particular situations. Capital and operating costs, as well as simplicity of operation, are the most common process-selection criteria for such small-scale sulfur-recovery facilities.
Nature of Sour Natural Gas
When raw natural gas produced from an underground reservoir contains more than the limit of H2S for sales gas, it has to be treated for the removal of most of the H2S. This is called gas sweetening. All raw sour natural gases also contain CO2. If a regenerative solvent is used for gas sweetening, the CO2 is extracted along with the H2S. These two gases are referred to as acid gases. When dealing with a sour gas that contains only a small amount of H2S (such as less than 1%), the content of CO2 is usually considerably greater than the H2S content. Upon regeneration of the sweetening solution, the resulting acid-gas stream may consist mainly of CO2. Such acid-gas streams are difficult to handle in a modified Claus plant. For this reason, other processes can be more economical on a small scale to recover the sulfur from such acid-gas streams that are lean in H2S.
The Sweetening Process
In most sulfur-recovery processes, the H2S and CO2 are first extracted from the sour natural gas by means of a sweetening solvent. There are various chemical and physical solvents available for this purpose.2 Fig. 1 illustrates the equipment used in such a process. The various options for the subsequent treatment of the acid gas stream for the recovery of 1 to 5 tonne of sulfur from the H2S form the basis for the remainder of this paper.
Modified Claus Process.
The modified Claus process consists of the following basic process equipment: inlet scrubber for acid gas; air blower; reaction furnace; heat-recovery boiler; condenser; one, two, or three sets of reheaters; catalytic converters and sulfur condensers/separators; and incinerator and stack.
The basic equipment is usually arranged in one of two modes, namely straight through or split flow.3 Fig. 2 illustrates the equipment for the split-flow process, which is the mode of operation used for lean-H2S acid-gas-feed streams to the sulfur plant, namely gases with an H2S content less than about 35% in the acid gas.
The chemical conversion of H2S to elemental sulfur occurs in two exothermic reaction steps. First, one-third of the H2S is burned with air to form sulfur dioxide (SO2) and water vapor, as in
This reaction occurs in the combustion zone of the reaction furnace. As soon as the above reaction takes place, a second reaction can occur between the remaining two-thirds of the H2S and the formed SO2, as in
The second reaction is an equilibrium reaction, which means that it does not go 100% to completion. Combining these two reactions results in the overall reaction of
In the split-flow mode, only about 35 to 45% of the total acid-gas stream is flowed through the reaction furnace, with the balance bypassing the combustion stage.
Below about 20% H2S in the acid-gas feed to a modified Claus plant, it becomes more difficult to operate the plant, as the flame in the reaction furnace becomes unstable. In such cases, the acid gas and air can be preheated before mixing in the front-end burner.4 The degree of preheating depends on the acid-gas composition. A flame temperature of about 1,000°C would provide for stable combustion in the reaction furnace.
Acid-Gas Enrichment. When the acid-gas stream contains less than 10% H2S, it may be too difficult to operate the facilities and achieve the necessary recovery efficiency in a split-flow modified Claus plant. In such a situation, the acid-gas stream can be treated in an additional sweetening step with a specialty solvent that preferentially absorbs the H2S and leaves most of the CO2 behind.5 Fig. 3 illustrates this process. Upon solvent regeneration, the acid-gas feed to the Claus plant is sufficiently enriched in H2S content so that a split-flow plant can achieve the necessary operating stability. The exit gas stream is disposed into the atmosphere through an incinerator and stack.
Selectox and Recycle-Selectox Processes.
The Selectox and recycle-Selectox processes were developed in the late 1970's as an adaptation of the Beavon Sulfur Removal/Selectox Tail Gas Cleanup process (BSR/Selectox).
Proceqsing of sulfiir containing criides has alwayci created a hydrogen sulfide disposal problem to petroleum refiners. As morr btringent air pollution laws are enacted, this problcm will herome more acute. A new proce95 fur converting hydrogen sulfide to sulfur has been developed in the laboratoriei of The Atlantic Refining Company. This process uses a basic aqueous solution of a multivalent ion such as iron in conjunction with a chelating agent to absorb hydrogen sulfide and oxidize it to sulfur. The iron is reoxidieed by air either concurrently or separately to make a continuous operation. The oulfnr is formed as a finely divided solid which may be recovered by settling, filtration or p-eferahly as a liqiiiri h? heating the suspension ahnve the melting point of Sulfur. This process shows promioe of providing: 1. A simple system which may nperate on concentrated hydrogen sulfide streams or dilute hydrogen sulfide-hydrocarbon streams. In the latter, essentially complete hydrogen sulfide removal has been obtained.
In the Steam-Assisted Gravity Drainage (SAGD) thermal recovery process, high pressure and high temperature saturated-steam is injected into a bitumen-bearing oil sands formation. For most operations, the steam temperature ranges from about 200 to 260?C and thus under these conditions, the bitumen, in the presence of high temperature steam condensate, undergoes hydrous pyrolysis, i.e. aquathermolysis, yielding acid gases such as hydrogen sulfide and carbon dioxide. Current SAGD thermal reservoir simulation models in the literature often take into account complex spatial heterogeneity of the geology and oil composition and the physics of heat transfer, multiphase flow, gas solubility effects, and viscosity variations with temperature, however, few have taken the chemistry of SAGD into account. Here, we have added aquathermolysis reactions to thermal reservoir simulation model to understand reactive zones in the SAGD process and how the process generates acid gases via aquathermolysis. Given the requirement to constrain or handle sulfur emissions from thermal recovery processes, it is necessary to understand both the physical and chemical sides of the processes. Here, we have explored the possibility of triggering the Claus process underground for in situ scavenging of hydrogen sulfide during SAGD. The application of the research results is specifically to SAGD although the results could be extended to Cyclic Steam Stimulation as well. The results demonstrate that SAGD is not only a physical process that operates largely under gravity drainage but that it is also a chemically reactive process which generates hydrogen sulfide and carbon dioxide. The results also demonstrate that hydrogen sulfide generation reactions occur where there is sufficient heat, water, and oil and thus, the reactive zones are mainly at the edges of the steam chamber and in the liquid pool that sits above the production well. Injecting very small amount of sulfur dixode along with steam could result in initiation of Claus reaction underground resulting into conversion of hydrogen sulfide into liquid sulfur. The results of this study are significant given regulated emission limits of hydrogen sulfide from SAGD operations in Alberta, Canada, and moreover, the ability to potentially reduce emissions by altering the operating strategy or through in situ hydrogen sulfide scavengers offers an elegant way to meet these regulations.
This document is an expanded abstract.
Sulfur compounds present in crude oil and gas are absorbed primarily in the form of acid gas (H2S and CO2) and then converted to elemental sulfur in the sulfur recovery units (SRU). To comply with the increasing environmental standards on sulfur emissions, SRUs are required to achieve Sulfur recovery efficiency ranging from 98% to 99.99%. The existing technologies for higher sulfur recovery induce very high cost additions to an already economically deficient SRU. To reduce the SRU costs, a modified thermal section is proposed in this study to increase the sulfur recovery efficiency in the relatively inexpensive Claus furnace in order to reduce the number of expensive catalytic units required to meet the environmental standards. The modified SRU is based on double-stage acid gas combustion taking place in two Claus furnaces, along with the intermediate withdrawal of sulfur and H2O exiting the first furnace. The SRU’s conventional and modified thermal sections are simulated using industrial plant data and a detailed reaction mechanism. Compared to the conventional thermal section, Sulfur recovery efficiency increased from 63% to 75% due to a shift in the Claus equilibrium reactions towards Sulfur production (2H2S + SO2 ⇌ 3S + 2H2O), as both H2O and sulfur were withdrawn in the modified case. To determine the overall Sulfur recovery efficiency, the 2-stage and 3-stage catalytic sections combined with the conventional or modified thermal sections were simulated. In comparison, the overall Sulfur recovery efficiency (thermal + catalytic sections) in the modified thermal section increased remarkably from 96.5% to 98% with the 2-stage and from 97.6% to 98.6% with the 3-stage catalytic units. The higher amount of sulfur captured in the modified thermal section resulted in the decreased concentrations of H2S, SO2, H2, CO and H2O in the effluent gas, which helped to reduce the processing load/requirements in catalytic units. These results will assist in providing guidelines to reduce the number of expensive catalytic units to decrease the operating cost of SRUs.
Despite an apparent abundance of elemental sulfur at this time, a recentsurvey and forecast of sulfur supply and demand by Stanford Research Institute,reported in Chemical and Engineering News, indicates that reserves of Fraschsulfur may reach a peak and decline in the face of a rising demand forbrimstone during the next decade. There is little doubt that economic pressurewill dictate that sulfur be recovered from sources now considereduneconomical.
For example, consider the sweetening of sour natural gas as practiced by thepetroleum industry. At present and for many years past, producers andtransporters of natural gas have removed hydrogen sulfide by a variety ofprocesses, notably water-amine, glycol-amine, phenolate, hot carbonate, ironsponge, etc. But sulfur is recovered from these acid gas streams only when itcan be produced at rates of 10 tons per day or more by various modifications ofthe Claus process. As a result, a large volume of sour gas is processed dailyin hundreds of small sweetening plants. The off-gases, containing hydrogensulfide, are vented and burned, representing a substantial loss of a valuable,exhaustible resource. Obviously, improvement is a matter of economics madepossible by a higher price for sulfur, or recovery process improvement, or acombination of both.
The purpose of this paper is to present a new process development forsweetening sour gas and for effecting simultaneous recovery of elementalsulfur. Based on a reaction mechanism discovered by F. M. Townsend, the processhas been developed by the authors to the pilot plant stage and it is known asthe "Townsend Process". This process has several notable features: [a]Gas is sweetened and its sulfur compounds are converted to elemental sulfur inone step, [b] the sweet residue gas is effectively dehydrated, [c] the processis virtually insensitive to carbon dioxide, [d] it appears to be adaptable to acomplete range of H2S content regardless of whether gas sweetening or sulfurrecovery is the prime objective, and [e] it can replace the Claus process inconverting off-gases from sweetening processes of various types, and itpromises to be especially effective where the CO2 and/or heavier hydrocarboncontent of such mixtures is excessively high.