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Evaluation of H2S Scavenger Technologies GRI Report No. GRI-94/0197 By A. J. Foral and B. H. AI-Ubaidi The M.W. Kellogg Company 601 Jefferson Avenue P. O. Box 4557 Houston, Texas 77210-4557 F. M. Floyd, Project Manager Prepared for Gas Research Institute GRI Contract No. 5088-221-1753 Mr. Dennis Leppin, GRI Project Manager Note: Minor changes have been made to this help file that supersede the original GRI report. Changes were made to update information and clarify passages.

GRI Disclaimer

Leqal Notice This report was prepared by The M.W. Kellogg Company as an account of work sponsored by the Gas Research Institute (GRI). Neither GRI, The M.W. Kellogg Company, nor any person acting on behalf of either: A. Makes any warranty or representation, express or implied, with respect to the accuracy, completeness or usefulness of the information contained in this report, or that the use of any apparatus, method, or process disclosed in this report may not infringe privately-owned rights; or B. Assumes any liability with respect to the use of, or for damages resulting from the use of, any information, apparatus, method or process disclosed in this report.

Research Summary

Title Contractor Evaluation of H2S Scavenger Technologies The M.W. Kellogg Company GRI Contract No. 5088-221-1753 Principal Investigator Report Period Objective 01 June to 31 August 1993 The program objective was to establish the cost for removing Low level concentrations of hydrogen sulfide from a natural gas stream using commercially available scavengers. The scavengers were used in a batch process on a throw-away basis. No attempt was made to regenerate the scavenger in place. Related Topics: Technical Perspective Results Technical Approach Project Implications F.M. Floyd, Project Manager

Technical Perspective

A recent survey by Energy and Environmental Analysis, Inc. indicates that approximately 19 trillion cubic feet (TCF) of natural gas resides in major hydrogen sulfide-prone reserves in the United States. Currently about 15 percent of all gas produced is sour, much with low concentrations of hydrogen sulfide and also small volume flows. At low hydrogen sulfide concentrations, conventional hydrogen sulfide removal systems such as MEA (Monoethanol Amine), DEA (Diethanol Amine), MDEA (Methyldiethanol Amine), etc. are uneconomical. To treat such Low concentration, Low flow hydrogen sulfide-bearing streams to pipeline specifications numerous scavenger technologies have been developed. With the many choices and high operating costs characterized by most technologies, operators are faced with the difficult choice of selecting a treating option for their Low hydrogen sulfide concentration natural gas. The use of H2S scavengers by the natural gas industry has been growing significantly for removing Low concentrations of H2S (typically up to about 200 ppmv H2S depending on the gas flow rate), where conventional amine treating is not economically feasible. For years, the Iron Sponge and other nonregenerable processes were widely used by the industry to treat this gas. Heightened concerns about safety and environmental impact associated with spent material disposal have prompted the introduction and use of many new scavenger technologies. As environmental regulations have become stricter, a keen interest in identifying better and more environmentally-acceptable H2S scavenging technologies has emerged, generating a need for information on the application and performance of these technologies. In 1993, GRI initiated a research program in H2S scavenging spanning activities in technical evaluation, laboratory testing, and field evaluation. This study was undertaken to survey the available commercial scavenger technologies, identify their process capabilities and limitations and establish the relative Investment and operating costs associated with the technologies. The information resulting from this evaluation was used to screen those technologies with the greatest potential technical and economic merit for further study in GRI's field evaluation program. The scavenger systems evaluated were employed as a batch process with a twentyfive-day life on a throw-away basis. The scavenger systems are characterized by requiring minimum equipment to treat the gas to the desired level. Normally, two contactors are arranged in parallel or lead-lag flow. The lead-lag option offers greater utilization of the scavenger and greater flexibility in the scheduling of bed change-out. The designs developed in this study allowed the flexibility to operate in either parallel or lead-lag flow arrangement.

Results

This study established the relative capital and operating costs and acceptability for treating 2 MMSCFD of natural gas, containing 3, 60, and 100 lbs of sulfur/day as H2S, with the listed hydrogen sulfide scavenger technologies. The results indicated that the hydrogen sulfide scavengers used were appropriate for Low concentrations of H2S. Each scavenger had a maximum hydrogen sulfide concentration that it could economically treat, above which it would be more appropriate to use a continuously regenerative process, or an alternative scavenger. A relative Screening Index (SI) was developed. The SI took into account: Investment and operating costs, and subjective weightings of process reliability, ease of operation, operator acceptance, ease of spent material disposal, and winterization requirements. Based on the weighting factors used, results indicated that for a 3 lbs sulfur/day loading, the SulfaTreat Scavenger had the best rating and lowest total plant Investment. The Magnatreat M-401 scavenger had the lowest operating cost. For a 60 lbs sulfur/day loading, the SulfaTreat Scavenger still had the best rating and lowest total plant Investment. The Sulfa-Check 2420 scavenger had the lowest operating cost. For a 100 lbs sulfur/day loading, the SulfaTreat Scavenger still had the best rating and lowest total plant Investment. The Sulfa-Check 2420 scavenger had the lowest operating cost. Another evaluation was done to estimate the maximum economical H2S removal rate for each scavenger, based on a volume-specific scavenger capacity, 4' ID x 30' T/T vessel size, and 25-day change-out period. The scavenger Zinc Oxide (High Temperature) had the highest maximum economical loading of 300 lbs sulfur/day. The scavengers Sulfa-Check 2420, Scavinox, SulfaTreat, SulfaGuard and SulfuRid are limited to 200 lbs sulfur/day. The scavengers Sulfa-Scrub, Ecotreat and Iron Sponge are limited to 100 lbs sulfur/day. The scavenger Gas Treat 114 is limited to 80 lbs sulfur/day. The Magnatreat M-401 scavenger is limited to 60 lb sulfur/day. The scavengers Chemsweet and Activated Carbon Type CJ are limited to 40 lbs sulfur/day. The scavengers SulfuSorbTM and Caustic Soda are limited to 3 lbs sulfur/day. The results of the project provided much-needed information on the relative cost and acceptability of many commercial scavengers for treating Low H2S concentration natural gas. The information from this screening evaluation has been used in the development of the test plan for GRI's field evaluation of the more promising technologies. A scavenger system can be a useful process to treat gas of Low volume and/or Low concentration of hydrogen sulfide. While the capacity of the scavenger is an important design parameter, other characteristics of the system must be considered, such as the cost of material and the cost of spent material disposal. The GRI field evaluation work is playing a key role in the validation of the cost and performance of many of the scavengers. In summary, this preliminary review warrants further study, especially in areas such as material loadings, disposal, product availability, and site-specific factors.

Technical Approach

The list of hydrogen sulfide scavengers was generated by reference to literature describing where they have been used and to vendors who have the materials available. In general hydrogen sulfide scavenger technology is plagued by the vendors' desire to restrict information and the lack of reliable detailed design information. Many vendors provide only the capacity of the material for hydrogen sulfide and the cost of the scavenger. The design of the vessels is often left to the purchaser. Some of the scavenger systems evaluated in this study were designed from data in the literature, where the vendors had not provided the design information. Thus, the results of this study should be used for screening purposes only. The scavenger systems were generically divided into two classes, liquids and solids. The direction of flow was upward for liquid systems and downward in the solid systems. All systems were designed with a flow arrangement allowing for parallel flow through two beds or lead-lag flow through two beds. The advantage of the lead-lag arrangement allows for greater utilization of the scavenger and greater flexibility in scheduling bed change-outs. An inlet filter separator was provided for all systems. An outlet separator was provided for systems that used a liquid scavenger. Anti-foam injection systems were provided for liquid systems where such systems were indicated as being necessary by the vendor or based on the literature. All systems were considered to be batch processes with no continuous injection of scavenger or in-place regeneration. Some systems claim an advantage with continuous injection of the scavenger or staged regeneration, but these configurations were not evaluated. Some of the scavengers were marketed by more than one vendor under different names. For example, Sulfa-Scrub, SulfaGuard, Arlox HS-101, Magnatreat M-401 and Sulfa-Check are all similar materials. The commercial arrangements made in the past led to the proliferation of this material under different names. At this time the Tretolite Division of the Petrolite Corporation has obtained the patent covering the chemistry application of triazine, the base component of the Sulfa-Scrub scavenger (Tretolite 1994). Where vendors responded to our request for design information and gave a range of capacity for their scavenger for hydrogen sulfide, the average capacity was used to design contactor tower size and initial scavenger charge. A maximum vessel height of 30' T/T, and a 25-day run time were used as a basis for the study. All contactor towers were sized for velocities of less than the maximum superficial velocities recommended by the vendors.

Project Implications

Scavenging operations are of increasing importance to gas producers as production is increasingly sour. Very little information has been available to aid in rational process selection and to minimize producer operating costs. This study is GRI's first effort to provide a source of detailed information on the scavenger options. It was quickly decided that a computer program based on the information contained herein would be of considerable value and a further effort is underway to produce such a product, which has been named SeleXpert: H2S Scavenger Module. This program is expected to be released in its initial version in the second quarter of 1995. A prototype of the program has been developed that generates relative rankings of 15 commercial H2S scavenging technologies based on estimated Investment and operating costs; and system-default or user-defined subjective weighting factors. These weighting factors cover the categories referred to in this report as part of the Screening Index. As this report and the associated program are primarily based on vendor-provided and unverified information, a second major effort was undertaken to obtain field validation of scavenger performance for several representative scavengers of the major types, i.e., liquid, solid and direct injection approaches. The latter work has, at this time, resulted in a significant database of information on the liquid type in both laboratory and field environments, and the testing of SulfaTreat, a solid type. The data and performance information from the field evaluation will be incorporated in SeleXpert: H2S Scavenger Module.

Executive Summary

Hydrogen sulfide scavengers have been used for many years. An example is the Iron Sponge scavenger which has been in use in Europe and the United States for over 100 years. Hydrogen sulfide scavengers are appropriate for use at the Low H2S concentrations where conventional chemical absorption and physical solvents are not economical. During recent years, hydrogen sulfide scavenger technology has expanded with many new materials coming on the market and others being discontinued. Heightened concerns about safety and environmental impact associated with spent material disposal have prompted the introduction and use of many new scavenger technologies. As environmental regulations have become stricter, a keen interest in identifying better and more environmentally-acceptable H2S scavengers has emerged, generating a need for information on the application and performance of these technologies. With many technology choices and the high operating costs characterized by most technologies, operators are faced with a difficult task of selecting a treating option for their Low hydrogen sulfide concentration natural gas. In 1993, the Gas Research Institute (GRI) initiated a research program in H2S scavenging spanning activities in technical evaluation, laboratory testing, and field evaluation. This study was undertaken under the auspices of GRI to survey the available commercial scavenger technologies, identify their process capabilities and limitations and establish the relative Investment and operating costs associated with the technologies for treating 2 MMSCFD of natural gas containing 3, 60, and 100 lbs of sulfur/day as H:S. The information resulting from this evaluation was used to screen these technologies with the greatest potential technical and economic merit for further study in GRI's field evaluation program. Many of the scavenger compositions were proprietary, thus requiring design data to be furnished by the vendors. All hydrogen sulfide scavengers were evaluated on the basis of a comparable flow arrangement. A batch system which could accommodate either lead-lag or parallel vessel arrangement was used for all scavengers, whether liquid or solid. The gas flow direction was upward for all liquid scavengers and downward for all solid scavengers. At a given flow rate, each scavenger system was designed from vendor data or design data provided in the literature. The total installed cost of each system was generated by Kellogg's inhouse Capcost Program. The preliminary observation was that many of the scavengers are sensitive to the maximum hydrogen sulfide concentration. Some of the scavenger vessels become extremely large at higher concentrations of hydrogen sulfide due to designed load capacity of the material. A relative total plant investment cost, relative operating cost and relative overall rating by Screening Index (SI) were calculated. The SI took into account: investment and operating costs, and subjective weightings of process reliability, ease of operation, operator acceptance, ease of spent material disposal, and winterization requirements. One of the scavengers' most significant aspects is the problem of the spent material disposal. Although not included in the operating cost calculations in this study, a potentially large portion of the operating cost for scavenger systems is the transportation and disposal of spent material. Some scavengers based on zinc compounds may require disposal in a hazardous landfill, while other scavengers require disposal in a nonhazardous landfill. Alternatively, the zinc compound in some of the scavengers can be disposed of by negotiation with a local commercial metal recycler. Because of the many state and local regulations which apply, site-specific information is required to quantify the disposal requirements. Furthermore, costs for transportation and disposal are also sitespecific, and can vary widely from operator to operator. With a few exceptions, even the vendors have little or no information to guide the user. Because of the many unknowns which exist, transportation and disposal costs were not quantified in this evaluation, but instead were addressed only qualitatively as part of the subjective criteria for screening: ease of spent material disposal.

Introduction

The objective of this evaluation was to determine the relative cost of removing hydrogen sulfide from a 2 MMSCFD natural gas stream. A stream containing up to 592 ppm(v) hydrogen sulfide (100 lbs sulfur/day) as well as 0.13% (mol) carbon dioxide was chosen for the design basis. The design basis of 100 lbs of sulfur/day was determined (based on engineering experience) to be a reasonable upper limit of the application of the technologies evaluated for the vessel size and bed life assumed. Twenty-one hydrogen sulfide scavengers which were listed in the literature as being commercially available were investigated. Hydrogen sulfide scavenger technology is not well developed. Many scavengers for hydrogen sulfide removal have been introduced to the industry, some of which have been removed for bad performance or replaced by other scavengers.

Very few vendors offered sufficient engineering data for detailed design of a scavenger system. In design.

Basis For Evaluation

The literature was scanned for commercially available hydrogen sulfide scavengers. A list of 21 scavengers was generated along with possible vendors. A vendor for each scavenger mentioned in the literature was not found, thus reducing the list evaluated to 15. The 15 vendors were sent a design inquiry. They were asked to provide vessel sizes, costs and sufficient basic engineering data on the capacity of the scavenger for hydrogen sulfide. Some vendors declined to provide design data. Design data in the literature was used in these cases. The scavenger evaluations were based on a batch system design operating with a 25-day bed or charge life. Each system had the necessary equipment to operate under either parallel or lead-lag flow arrangement. Only essential ancillary equipment was included: inlet filter separator, outlet separator for liquid systems only, initial charge for two beds. If the literature indicated that a given system was prone to foam, an antifoam injection package was included. No ancillary equipment was included for charging or draining the systems. It was assumed that the necessary equipment and labor would be rented on a per-job basis. The cost of bed or charge change was developed by escalating costs in the literature (Schaack and Chan 1989a). The evaluation was based on the relative cost of treating 2 MMSCFD of gas at the design conditions. The project was amortized over 5 years. Maximum economical H2S removal rate for each scavenger was estimated based on a vo!ume-specific scavenger capacity, 4' ID x 30' T/T vessel size, and 25-day change-out period.

Basis For Process Design

The systems were designed for the following: Feed Gas Basis Feed Gas Rate Pressure (psia) Temperature (oF) Gas Composition CH4 (mol%) H2S (ppmv) CO2 (mol%) H20 (mol%) (saturated) Location Product Gas Specifications H2S (maximum) 0.25 grains/100 SCF (-4.0 ppmv) CO2 (maximum) Bed Life 2.0 mol% 25 days 99.67 592 0.13 0.14 Gulf Coast USA 2.0 MMSCFD 1000 100

The design basis of 100 lbs of sulfur/day was determined (based on engineering experience) to be a reasonable upper limit of the application of the technologies evaluated for the vessel size and bed life assumed. · The scavenger vessels were to be designed at a lower superficial velocity than the maximum recommended by the literature or the vendor, Most of the liquid systems were to be designed as bubble towers except those where the literature or vendors suggested that packing be used. The 3 and 60 lbs sulfur/day evaluations were obtained by changing the sulfur loading only.

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Economic Criteria

· The total installed cost was generated by Kellogg's Capcost Program. Vendor budget quotations served as the basis of equipment cost for the filter separator, anti-foam injection package, and chemical injection packages. The scavenger contact vessel and outlet separator costs were determined from inhouse data. The operating cost was determined for recharging one bed assuming a 25-day bed life. The operating cost included the labor and equipment rental for changeout and the scavenger cost for one charge. Spent material transportation and disposal costs were not included in the operating cost calculation. · All costs were developed based on second-quarter 1993 U.S. dollars assuming a U.S. Gulf Coast installation.

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Assumptions and Limitations

All scavenger systems were designed as two contactor towers with flow arrangement that allows for both parallel and lead-lag flow. All scavenger systems had an inlet filter separator. All liquid scavengers had an outlet gas separator. Antifoam injection units were provided for liquid scavenger systems where indicated as being necessary or by the vendor or based on the literature. All scavenger systems were considered as batch processes with no continuous injection of scavenger or any in-place regeneration. Some scavenger systems may show an advantage with continuous injection of solvent or staged regeneration but these operations were not considered for this evaluation. Where vendors gave a range of capacity for their hydrogen sulfide scavenger, the average capacity was used to design contactor towers and scavenger charge. Related Topics: Economic Limitations

Economic Limitations

The most significant economic limitations were the cost of the scavenger charge and the disposal cost of the spent scavenger. Disposal of Spent Material Because of the many unknowns which exist, transportation and disposal costs were not quantified in this evaluation, but instead were addressed only qualitatively as part of the subjective criteria for screening: ease of spent material disposal. The disposal cost of a hazardous material is more than for a non-hazardous material. Although the spent material from some of the zinc oxide scavengers are classified as hazardous, sometimes the material can be recycled. As an example, from a typical zinc oxide scavenger system the spent material can be disposed of as follows: a) If the spent scavenger contains a high water and hydrocarbon content, the recycler would charge approximately $200/ton to dispose of the material. b) If the spent scavenger, in the form of a cake, contains a modest amount of water and hydrocarbon, the recycler would dispose of the material free of charge. c) If the spent scavenger, in the form of a cake, contains Low water and hydrocarbon, the recycler would pay the plant operator $100/ton to dispose of the material. The economic impact of zinc oxide disposal depends upon the analysis of the spent material. In this study, the worst-case scenario (a) was used to establish the subjective rating for ease of spent material disposal. Bed Change-Out Costs The operating cost of a scavenger system is the sum of the bed change out and scavenger material costs. No equipment was provided in the evaluation for loading the scavenger material or unloading the spent scavenger from the contactor vessel. Any equipment required was assumed to be rented on a per-job basis. The typical cost for change-out labor and equipment rental according to Schaack (1989) and escalated to 2nd Quarter 1993 is:

Scaven,qer Dichem (Liquid) Scavinox (Liquid) Chemsweet (Slurry) Ecotreat (Slurry) Sulfa-Check 2420 (Slurry) Iron Sponge (Solid)

Cost/Chanqe-Out $1,450 $1,400 $ 2,900 $ 2,900 $ 2,900 $10,875

The above costs were used in the study to estimate the bed change-out component of the operating cost. The change-out cost used for other solids was $5,438. The pyrophoric nature of ferrous sulfide contained in spent Iron Sponge requires special safety precautions during change-out. Also, the possibility of spent Iron Sponge fusing could require a high-pressure water jet for removal. The above reasons make spent Iron Sponge change-out a more time-consuming and expensive process compared to other solids. Hence,

an arbitrary factor of 1/2 was applied to the Iron Sponge change-out cost to arrive at the change-out cost of other solid scavengers. Other Economic Limitations The scavenger systems contained no rotating equipment. The anti-foam injection system used a small natural gas powered metering injection pump. All systems were designed to handle both parallel and lead-lag flow arrangements. The lead-lag arrangement allows greater chemical utilization and greater flexibility in scheduling bed change-out. An inlet filter separator was provided for all systems. Anti-foam injection was provided for liquid systems where indicated in the literature or by the vendor as a requirement. All systems were considered as batch processes with no continuous solvent injection or any in-place regeneration. Some systems may show an advantage with continuous solvent injection or staged regeneration, but those operations were not considered for this evaluation.

Caustic-Based

Caustic Soda Wash The Caustic Soda wash (This section describes the conventional caustic process; a licensed caustic process is offerred by Merichem Company. See Merichem Help File) is one of the oldest chemical absorption processes for removing small quantities of CO2 and H2S from natural gas and refinery gases (Raab 1976; Manieh and Ghorayeb 1981). A schematic diagram of the Caustic Soda process is depicted in Figure 7.1. The Caustic Soda process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. The inlet sour gas containing CO2 and H2S is first passed through an Inlet Filter Separator (101L) so that entrained liquid droplets are removed from the feed gas stream. Typical contaminants may include distillate, water, solids, and/or other treating chemicals. The batch process uses a charge of 15% wt caustic soda in each vessel. The untreated gas is purged through each vessel until the first vessel is not producing the desired specification; then, the first vessel is isolated and the spent solution is drained and then recharged with new solution. The recharged vessel is placed in service downstream of the other batch vessel. This arrangement allows for the maximum utilization of the caustic charge without making off-specification product or interrupting the gas flow. The major disadvantage of this scavenger system is that the carbon dioxide in the inlet gas consumes caustic and must be considered in the caustic soda consumption rate which reduces the life of a given charge. Carbon dioxide absorption and reaction with the caustic can be minimized by limiting the contact time, as H2S reacts faster than CO2. The sour inlet gas enters the bottom of a carbon steel Contactor (101E-NB) where the H2S and CO2 can be absorbed by maintaining a proper residence contact time between the gas and alkaline (NaOH) liquid in a batch mode operation. The Outlet Separator 101F is used to knock out any liquid carryover from Contactor (101E-NB). The configuration shown in Figure 7.1 is one where the alkaline solution is discarded because CO2 forms a non-regenerable product with the caustic. This is typical of wet scrubbing operations in which both acid gases ( H2S and CO2) are absorbed. To improve the contact of the liquid charge with the gas, the tower is equipped with a polyethylene packing. The system assumes that a 15-18% wt caustic solution can be purchased so that no mixing equipment is included in the system. Hence, the safety hazard of establishing and handling the solution is reduced. The caustic soda scavenger technology has been used in the industry for many years and considerable information is available in the public domain. The fresh scavenger composition is sodium hydroxide and water. The spent scavenger contains sodium hydroxide, sodium carbonate, sodium bicarbonate, sodium sulfide and water. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations. If they are, they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.3. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. Sodium hydroxide is listed under the current regulations. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table," Sodium hydroxide and sodium sulfide are listed under the current regulations. d) Superfund Amendments and Reorganization of 1986 (SARA) Title Ill. e) Occupational Safety and Health Administration (OSHA) with recommendations from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Sodium hydroxide has a published exposure limit set by this regulation.

Local or state regulation may limit the handling and disposal of the spent scavenger. Sodium hydroxide is listed under state regulation in Massachusetts, New Jersey and Pennsylvania, but not in California. Sodium sulfide is listed under the state regulations in Massachusetts and New Jersey, but not in California and Pennsylvania.

Ecotreat (Slurrisweet)

The Ecotreat process, previously known as Slurrisweet, is no lonqer commercially available. The process is a non-regenerative batch-type cycle which selectively removes H2S in the presence of CO2 (Schaack and Chan, 1989). The process basically uses a reactive iron compound in slurry form to be contacted with the natural gas. Figure 7.2 shows a schematic flow diagram for a typical Ecotreat acid gas treating unit. The major equipment includes an Inlet Filter Separator (301L), Contactor (301E-NB), and an Outlet Gas Separator (301F). The Ecotreat process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. No data are available for Ecotreat, so data available in the literature for Slurrisweet were used for the evaluation. The system is similar to the caustic wash in terms of using the lead-lag arrangement. The solution contains a slurry of aqueous iron oxide. To be able to meet the predicted capacity, air or oxygen must be added to oxidize the ferrous sulfide formed. To establish the contact between the slurry and the gas to be treated the tower must be packed with polyethylene pall rings (Schaack and Chan, 1989a). The inlet gas stream enters the unit through a small Inlet Filter Separator (301L) to separate out any entrained liquid, salt water, and any liquid hydrocarbon in the gas stream. The sour gas stream then passes into the bottom of the Contactor (301E-NB). The vertical vessel is filled approximately three-fourths full with polyethylene pall rings and contains the liquid Ecotreat treating solution to a level of about one-half full in the vessel. In this vessel the H2S in the gas stream reacts with the highly reactive iron compound material in the Ecotreat solution to remove the hydrogen sulfide from the gas stream. An antifoam solution (302L) is usually added to the system to eliminate any foaming tendencies that may occur inside the contactors. As the system is subject to severe foaming, the system requires an anti-foam injection system. In addition, a dispersant must be added to the system (not shown in Figure 7.2) to maintain the slurry in suspension. The treated gas passes to an Outlet Gas Separator (301F) to knock out any carryover of chemical solution from the contactor vessel into the gas pipeline. To increase the efficiency of the Ecotreat solution, a small amount of oxygen is added. There are some hazards involved in this, but corrosion, according to the vendor, is not a problem. Although significant costs may be involved, Schaack and Chan (1989) indicated the disposal of the scavenger consisted of separating the bulk of the water from the solid. The water can be disposed of down hole after compatibility test and plugging potentials are checked out. The solids can then be disposed in accordance with current regulations. The fresh scavenger contains the known components ferric oxide (hematite) and ferroso ferric oxide (magnetite). The spent scavenger contains the known components ferric oxide (hematite), ferroso ferric oxide (magnetite), ferric sulfide, ferrous sulfide (troilite), ferroso ferric sulfide, iron pyrite and sulfur. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations. If they are, they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." Ferric oxide (hematite) is listed under the current regulations. d) Superfund Amendments and Reorganization of i986 (SARA) Title iii.

e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Ferric oxide (hematite) has a published exposure limit set by these regulations. Local or state regulations may limit the handling and disposal of the spent scavenger. Ferric oxide (hematite) is listed under the regulations of the states of Massachusetts, New Jersey and Pennsylvania.

Iron Sponge

The Iron Sponge process, currently licensed by Connelly-GPM Inc., is one of the oldest scavengers for removing H2S and mercaptans from natural gas, with no interference by CO= concentration (Anerousis and Whitman 1985). Iron Sponge originated in Europe more than a century ago and it is still being used to treat natural gas today (Duckworth and Geddes, 1965). The process is a non-regenerative batch-type cycle and is schematically shown in Fi.qure 7.3. The sour feed gas passes through an Inlet Filter Separator (401L) so that entrained liquid droplets are removed from the feed gas stream. The gas then passes through the top of the Contactor (401E-NB) loosely packed with Iron Sponge. Two contactors are normally employed in lead/lag arrangement, where one bed is contacting the inlet gas while the other spent bed is being dumped and cleaned. The sponge consists of wood shavings impregnated with a hydrated form of iron oxide. The wood shavings serve as a carrier for the active iron oxide powder. Hydrogen sulfide is removed by reacting with iron oxide to form ferric sulfide. It should be noted here that the gas should be wet when passing through an Iron Sponge bed as drying of the bed will cause Iron Sponge to lose its capacity for reactivity. If the gas is not already water-saturated or if the influent stream has a temperature greater than 120F, water with soda ash is sprayed into the top of the contactor to maintain the desired moisture and alkaline conditions during operation. Recent regulations have become more restrictive in the method of classification and disposal of spent Iron Sponge. As there is a potential of exposure to toxic off gas and possible spontaneous combustion of the spent material when exposed to air, the material has come under the new regulations. The fresh scavenger contains the known components of iron oxide and wood shavings. The spent scavenger contains the known components of iron oxide wood shavings and iron sulfide. There also is a potential of having the following components if caustic soda is added for pH control: sodium hydroxide, sodium carbonate, sodium bicarbonate and sodium sulfide. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations and if they are they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. Sodium hydroxide is listed under the current regulations. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." Sodium hydroxide, sodium sulfide, iron oxide and iron sulfide are listed under the current regulations. d) Superfund Amendments and Reorganization of 1986 (SARA) Title II1. e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Sodium hydroxide and iron oxide are listed under the current regulations. Local or state regulations may limit the handling and disposal of the spent scavenger. As an example, sodium hydroxide and iron rust oxide are listed as hazardous substances in Massachusetts, New Jersey and Pennsylvania under the current regulations.

SulfaTreat

The SulfaTreat process, currently licensed by The SulfaTreat Company, is a patented batch-type process for the selective removal of hydrogen sulfide ( H2S ) and mercaptans (RSH), from natural gas, carbon dioxide (CO2) and air. The process is dry, using no free liquids, and can be used for all natural gas applications where a batch process is suitable. The SulfaTreatTM system is a more recent development using iron oxide on a porous solid material. Unlike Iron Sponge, the SulfaTreatTM material is non-pyrophoric. The SulfaTreatTM material has a higher capacity than Iron Sponge on a volumetric or mass basis. However, the economic capacity (pounds of sulfur removed per dollar of material) is somewhat lower than Iron Sponge (mid-1996 pricing). Despite this lower economic capacity than Iron Sponge, it has other qualities that give it an advantage. Generally SulfaTreatTM has a lower pressure drop and it does not tend to bridge over. SulfaTreatTM beds are easier to change out due to its particle size and shape. The uniform shape and size also allows for greater utilization of capacity. Carryover of liquid hydrocarbon and methanol has minimal effect on its hydrogen sulfide capacity. A schematic diagram of the process is depicted in Figure 7.4. The inlet gas stream enters the unit through a small Inlet Separator (501L) to separate out any entrained liquid, salt water, and any liquid hydrocarbon in the gas stream. The sour feed gas then passes to the top of the Contactor (501E-NB). The SulfaTreat product is a dry, granular, free-flowing material of uniform porosity and permeability. Also, the SulfaTreat product only reacts with sulfur-containing compounds. This eliminates any side reactions with CO2 which could reduce its efficiency. The reaction rate increases with temperature. As an example, from 40F to 130F the reaction rate increases by a factor of six. Operation below 40F is not recommended. Furthermore, high temperature could lead to bed drying. As the SulfaTreat bed dries out, the rate of reaction decreases. Optimum efficiency may require measuring water content of the gas and injecting a sufficient amount of water into the influent gas to maintain a water-saturated gas and evidence of free water in the outlet gas. The fresh scavenger contains the known components of ferric oxide (hematite) and ferrosoferric oxide (magnetite). The spent scavenger contains the known component iron pyrite. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations. If they are, they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." Ferric oxide (hematite) is listed under the current regulations. d) Superfund Amendments and Reorganization of 1986 (SARA) Title II1. e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Ferric oxide (hematite) has a published exposure limit set by these regulations. Local or state regulations may limit the handling and disposal of the spent scavenger. Ferric oxide (hematite) is listed under the regulations of the states of Massachusetts, New Jersey and Pennsylvania. The vendor claims that the spent material can be disposed of in a Class 2 landfill (non-hazardous) or buried on location. Disposal depends on local regulation (Gas Sweetener Bulletin).

Zinc Oxide (High Temperature)

The Zinc Oxide (High Temperature) process is a batch non-regenerative process employed primarily for polishing applications to remove trace amounts of H2S and mercaptans from natural gas and liquid hydrocarbons. The adsorption process is normally carried out at a high temperature (200-750F) so that sulfur compounds can be removed totally. Recently, ICl claimed that a new zinc oxide based adsorbent has been developed to give more porous structure and higher surface area to make Low temperature operation more attractive. The new lower temperature adsorbent was not evaluated in this study. Figure 7.-5 shows a typical flowsheet for the zinc oxide desulfurization process. The reaction rate of hydrogen sulfide with zinc oxide to form zinc sulfide increases with temperature. To get an acceptable reaction rate the inlet gas is heated to 300F by utilizing a gas-gas heat exchanger and a fired heater. The treated gas is further cooled in an air cooler to 100F (Carnell 1986). Liquid hydrocarbon does not contaminate the zinc oxide bed (Camell 1986). The zinc oxide scavenger technology is well established. Granular zinc oxide has been used for many years to remove hydrogen sulfide and mercaptans from natural gas and associated gas that is used as feed to produce hydrogen. The nickel catalyst used in production of hydrogen is easily poisoned by sulfur, thus the granular zinc oxide operating at high temperature removes the sulfur compounds to a level of less than 0.1 ppm which protects the nickel catalyst. Granular zinc oxide has been used on an offshore platform in the North Sea to remove hydrogen sulfide (Carnell 1986). The inlet sour gas passes through an Inlet Filter Separator (601L) to separate out any entrained liquid or salt water in the gas stream. The gas then passes through a two-stage preheating process Gas/Gas Exchanger (601C) and Gas Heater (601B) to raise the temperature of the gas high enough before entering the Contactor (601E-NB). The heated gas then enters the top of the contactor where the hydrogen sulfide is removed by reaction with the granular zinc oxide packed in the fixed bed. The two contactors are in a lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being cleaned and recharged with fresh zinc oxide. Carnell (1986) indicated the discharged, spent, zinc oxide is normally sold for metal recovery. No credit for metal recovery was taken in this study, however. The fresh scavenger contains the known component zinc oxide. The spent scavenger contains the known components of zinc oxide and zinc sulfide. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations. If they are, they may present a disposal problem. a) Resource Conservation and Recovery ACt (RCRA) from 40 CFR 261.33. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." d) Superfund Amendments and Reorganization of 1986 (SARA) Title II1. Zinc oxide and zinc sulfide are listed under the current regulation. e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Zinc oxide has published exposure limits set by these regulations. Local or state regulations may limit the handling and disposal of the spent scavenger. The zinc oxide is considered as a hazardous substance in Massachusetts, New Jersey and Pennsylvania.

Chemsweet

The Chemsweet process, licensed by NATCO, Division of National Tank Company, is a non-regenerative batch process for selectively removing H2S from natural gas. The white powder product, Chemsweet, is a mixture of zinc oxide, zinc acetate, water and a dispersant to keep the solid (zinc oxide) particles in suspension. The pH of the Chemsweet slurry is Low enough to prevent any significant absorption of CO2 when the ratio of CO2 to H2S is high (NATCO 1982). The spent scavenger normally contains an aqueous slurry of zinc sulfide and approximately 85% wt water (NATCO 1982). The hydrogen sulfide scavenger, Chemsweet, is an aqueous slurry of specially formulated zinc oxide. Liquid hydrocarbon must be removed from the feed to prevent contamination of the zinc oxide. Figure 7.6 shows a schematic flow diagram for a typical Chemsweet acid gas treating unit. The major equipment includes an Inlet Filter Separator (701L), Contactor (701E-A/B), and an Outlet Gas Separator (701F). The Chemsweet process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other spent bed is being drained and cleaned. The inlet sour gas passes through an Inlet Filter Separator (701L) to separate out any entrained liquid or salt water in the gas stream. The gas then enters the bottom of the Contactor (701E-A) where the hydrogen sulfide is removed by reaction with the solid slurry. The other Contactor (701 E-B) is cleaned and recharged with fresh Chemsweet. The treated gas passes out to an Outlet Gas Separator (701F) to prevent any carry over of chemical solution from the contactor vessels into the gas pipeline. The fresh scavenger contains the known components of zinc oxide and water. The spent scavenger contains the known components of zinc oxide, zinc sulfide and water. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations and if they are they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." d) Superfund Amendments and Reorganization of 1986 (SARA) Title II1. Zinc oxide and zinc sulfide are listed under current regulations. e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Zinc oxide has published exposure limits set by these regulations. Local or state regulations may limit the handling and disposal of the spent scavenger. The zinc oxide is considered as a hazardous substance in Massachusetts, New Jersey and Pennsylvania. The vendor claims in most cases spent scavenger can be disposed of in a landfill site. Do not heat the spent scavenger or allow it to stand in an open vesel, as the H2S could be released. The fresh scavneger is not considered to be hazardous,

SulfuSorb

The SulfuSorb process, currently licensed by Calgon Carbon Corporation, is one of the scavengers for removing H2S from natural gas streams. The scavenger SulfuSorb comes in two types, SulfuSorb and SulfuSorb 12. The SulfuSorbm's are specially-impregnated granular activated carbons. They were designed for vapor-phase application to remove hydrogen sulfide and Low molecular weight organic sulfur compounds. A copper compound is used to impregnate the granular activated carbon (Calgon 1978). High molecular weight hydrocarbons contaminate the SulfuSorbTM by masking the impregnated activated carbon. The SulfuSorbTM in a properly operated unit can remove hydrogen sulfide to 0.2 ppm in the treated gas. The SulfuSorbTM scavengers are more suited when the inlet gas contains 10 ppm or less of hydrogen sulfide (Calgon 1978). The process, schematically shown in Figure 7.7, operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being dumped and replaced. The sour feed gas passes through an Inlet Filter Separator (1101L) to remove any entrainment liquid droplets from the feed gas stream. The gas then passes through the top of the Contactor (1101E-NB) loosely packed with metal-oxide-impregnated activated carbon products. Hydrogen sulfide is removed by adsorption on the dry activated-carbon bed (Calgon 1978). The system is suited for regeneration in place with a significant reduction in capacity for sulfur (Calgon 1978). The fresh scavenger contains the known components of activated carbon and a copper compound as the impregnated material. The spent scavenger contains the known components of activated carbon and copper sulfide. The components in the new and spent scavenger may or may not be listed under one or more of the following regulations. If they are, they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. Copper compounds are listed under the current regulations. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." Activated carbon is listed under the current regulations. d) Superfund Amendments and Reorganization of 1986 (SARA) Title III. e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Local or state regulations may limit the handling and disposal of the spent scavenger. The vendor claims that for the SulfuSorb material with copper impregnation only, disposal is by land fill.

Activated Carbon Type CJ

The CJ activated carbon process, currently licensed by Barnebey & Sutcliffe Corp., is one of the H2S scavengers for removing H2S and mercaptans from natural gas in non-oxygen atmospheres. The Activated Carbon Type CJ hydrogen sulfide scavenger is made from chemically impregnated activated carbon. The material used to impregnate the carbon is ferric oxide. The ferric oxide impregnate increases the capacity for hydrogen sulfide eight fold over the unimpregnated activated carbon. The process is a non-regenerative batch-type cycle, and is schematically shown in Figure 7.8. The sour feed gas passes through an Inlet Filter Separator (2101L) to remove entrained liquid droplets from the feed gas stream. The gas then passes through the top of the Contactor (2101 E-NB) loosely packed with activated carbon type CJ. Type CJ is a metal oxide-treated carbon with high selectivity towards hydrogen sulfide. The fresh scavenger contains the known components of activated carbon and ferric oxide. The spent scavenger contains the known components of activated carbon, ferric oxide and spent iron oxide. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations. If they are, they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." Activated carbon and spent iron oxide are listed under the current regulations. d) Superfund Amendments and Reorganization of 1986 (SARA) Title III. e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Local or state regulations may limit the handling and disposal of the spent scavenger. The vendor did not provide any information on the handling or disposal of this scavenger.

Nitrite-Based

Sulfa-Check 2420 The Sulfa-Check process, licensed by Nalco/Exxon Energy Chemicals, L.P., is a direct liquid-phase oxidation process using an aqueous solution of salt oxidizers such as sodium nitrite. The process is generally operated at ambient temperature, used for selectively removing H2S and mercaptans from sour gas in the presence of CO2 (Bhatia and AIIford 1986), and produces a by-product slurry of sulfur and sodium salts. A schematic diagram of the batch non-regenerative process is shown in Figure 7.9. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. As shown in this figure, the inlet sour gas is first passed through an Inlet Filter Separator (201L) so that entrained liquid droplets are removed from the feed gas stream. The sour inlet gas enters the bottom of a Contactor (201E-NB) where acid gases ( H2S and CO2) react with the alkaline solution of salt oxidizers such as sodium nitrite. As the system tends to foam, provision is made for an anti-foam injection system to inject Sulfa-Check E22 and E25 anti-foam agents on a continuous basis. In the Sulfa-Check process, the effects of all reactions between H2S, CO2 and the nitrite solution are controlled by selecting the proper parameters such as pH and contact time so that H2 S reacts to form sulfur with a minimum amount of CO2 reacting with the alkaline solution. The treated gas leaves the top of the contactor and passes through an Outlet Gas Separator (201F), where any solvent carried over is removed. According to the manufacturer, the system must be maintained below 100F. The following must be considered when using Sulfa-Check 2420: 1. The Sulfa-Check process may generate nitrogen oxide but does not normally generate nitrogen dioxide. 2. Nitrogen dioxide can cause corrosion in a wet environment which could oxidize some elastomers and plastic seals and reduce the ability of people to detect some odorant. 3. Ammonia can be produced when fresh Sulfa-Check 2420 is installed and when the concentration of carbon dioxide is less than 0.1 percent. This is a transient effect which only occurs at the beginning of a cycle. Carbon steel is suitable for material of construction for major pieces of equipment. The primary solids in the spent solution are sulfur and sodium bicarbonate. The acidification of spent slurry will not cause hydrogen sulfide evolutions. The fresh scavenger contains the known components of sodium nitrite, sodium hydroxide and water. The spent scavenger contains the known components of sodium nitrite, sodium hydroxide, water, ammonia, nitric oxide, sodium carbonate, sodium bicarbonate, sodium nitrate, sodium sulfate, tetrathionate and sulfur. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations. If they are, they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. Nitric oxide is listed under the current regulations. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. Sodium nitrite, sodium hydroxide, ammonia, sodium bisulfide, ammonium carbonate and nitric oxide are listed under the current regulations. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table."

Sodium nitrate, sodium hydroxide, sodium nitrite, nitric oxide, ammonia, sodium sulfide, sodium bisulfide, ammonium carbonate and sulfur are listed under the current regulations. d) Superfund Amendments and Reorganization of 1986 (SARA) Title III. Ammonia and nitric oxide are listed under the current regulations. e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Nitric oxide, ammonia, sulfur and sodium hydroxide have published exposure limits set by these regulations. Local or state regulations may limit the handling and disposal of the spent scavenger. Refer to Table 8.1 for the components regulated in the states of California, Massachusetts, New Jersey and Pennsylvania. According to Bhatia (1986), the spent slurry from the Sulfa-Check process was classified as a nonhazardous waste by the U.S. Environmental Protection Agency, fourteen state agencies and the U.K. Department of Energy.

Sulfa-Scrub

The Sulfa-Scrub process, licensed by Petrolite Corporation, Tretolite Division, is a non-regenerative batch process for selectively removing H2S and mercaptans from natural gas. The treating chemical, SulfaScrub, is a novel class of alkanolamines known as tria7ines. The Sulfa-Scrub instantaneously reacts with H2S, but reacts minimally with CO2 (Dillon 1991). At this time the Tretolite Division of the Petrolite Corporation has obtained the patent covering the chemistry application of triazine, the base component of the Sulfa-Scrub scavenger (Tretolite 1994). Sulfa-Scrub reacts with hydrogen sulfide to form a stable, water soluble product that is easily removed from the system. The reaction products can include bis-dithiazine and dithiazine. Sulfa-Scrub scavenger is an aqueous solution of 48-50% by weight of the triazine-based scavenger (Dillon 1991). Fi,qure 7.10 shows a schematic flow diagram for a typical Sulfa-Scrub acid gas treating unit. The major equipment includes an Inlet Filter Separator (1201L), Contactor (1201E-NB), and an Outlet Gas Separator (1201F). The Sulfa-Scrub process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. The inlet sour gas passes through an Inlet Filter Separator (1201L) to separate out any entrained liquid or salt water in the gas stream. The gas then enters the bottom of the Contactor (1201 E-A) where the hydrogen sulfide is then removed by reaction with the Sulfa-Scrub material. The other Contactor (1201E-B) is cleaned and recharged with fresh triazine. The treated gas passes to an Outlet Gas Separator (1201F) to prevent any carryover of chemical solution from the contactor vessels into the gas pipeline. Free hydrocarbon condensate must be removed from the inlet feed for satisfactory operation (Dillon 1991). Originally the material used in the Sulfa-Scrub scavenger had been marketed to several distributors who sold the material under their own trade names of SulfaGuard, Magnatreat M-401, Arlox HS-101 and SulfaCheck TX. This has led to some misunderstanding in the use of the material but with new commercial agreements, the Petrolite Corporation is the sole distributor in the United States under the Tretolite Division with trade name Sulfa-Scrub HSW-7OOL. The fresh scavenger contains the known components of triazine, methanol and water. The spent scavenger contains the known components of triazine, bis-dithiazine, dithiazine, methanol and water. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations and if they are they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. Methanol is listed under the current regulations. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. Methanol is listed under the current regulations. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." Methanol and monoethanol amine are listed under the current regulations. d) Superfund Amendments and Reorganization of 1986 (SARA) Title II1. Methanol is listed under the current regulations. e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Provinc. P. nf Alberta's Occupational and Health and Safety Act (Canada). Methanol and monoethanol amine are listed under the current regulations.

Local or state regulations may limit the handling and disposal of the spent scavenger. Refer to Table 8.1 for the components regulated in the states of California, Massachusetts, New Jersey and Pennsylvania. Although an expensive disposal method, the vendor claims that the spent Sulfa-Scrub scavenger can be disposed of in a non-hazardous disposal well. The vendor has had several environmental analyses conducted on the spent Sulfa-Scrub solution to verify that it is non-hazardous (Dillon 1991). Some operators have found it was to their advantage to use the spent Sulfa-Scrub scavenger solution as a corrosion inhibitor in appropriate aqueous systems (Dillon 1991),

SulfaGuard

The SulfaGuard process, licensed by Coastal Chemical Company, is a non-regenerative batch process for selectively removing H2S from natural gas. The treating chemical, SulfaGuard, is a complex class of amine/amino alcohol resin in an aqueous methanol solution. It is a triazine-based scavenger. The SulfaGuard solution rapidly reacts with H2S, but minimally absorbs CO= because it is sterically hindered (Coastal Report 1993). SulfaGuard converts the hydrogen sulfide to a non-hazardous sulfur/amine compound and organic thioalcohol (mercaptan) polymer. The reaction with hydrogen sulfide does not form any insoluble precipitants. The scavenger is used as a 50% aqueous solution (Coastal 1993). Fi.qure 7.11 shows a schematic flow diagram for a typical SulfaGuard acid gas treating unit. The major equipment includes an Inlet Filter Separator (1501L), Contactor (1501 E-NB), and an Outlet Gas Separator (1501F). The SulfaGuard process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. The inlet sour gas passes through an Inlet Filter Separator (1501L) to separate out any entrained liquid or salt water in the gas stream. The gas then enters the bottom of the Contactor (1501 E-A) where the hydrogen sulfide is removed by reaction with the amine/amino alcohol resin to form stable, water soluble products that may be easily removed from the system. The other Contactor (1501E-B) is cleaned and recharged with fresh SulfaGuard and placed in series with Contactor (1501E-A). The treated gas passes out to an Outlet Gas Separator (1501F) to prevent any carryover of chemical solution from the contactor vessels into the gas pipeline. The fresh scavenger contains the known components of triazine, methanol, monoethanol amine and water. The spent scavenger contains the known components of triazine, bis-dithiazine, dithiazine, methanol, monoethanol amine and water. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations. If they are, they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. Methanol is listed under the current regulations. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. Methanol is listed under the current regulations. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." Methanol and monoethanol amine are listed under the current regulations. d) Superfund Amendments and Reorganization of 1986 (SARA) Title III. Methanol is listed under the current regulations. e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Methanol and monoethanol amine are listed under the current regulations. Local or state regulations may limit the handling and disposal of the spent scavenger. Refer to Table 8.1 for the components regulated in the states of California, Massachusetts, New Jersey and Pennsylvania. The vendor claims the reaction product can be used as a corrosion inhibitor or that it can be disposed of in a disposal well or any non-hazardous waste disposal site.

Sulfix 100

Sulfix 100 - Replaced by Magnatreat M-401, Arlox HS 101, Sulfa-Check TX The vendor indicated that the scavenger Sulfix 100 was not suitable for this evaluation requirement. The vendor replaced Sulfix 100 with Magnatreat M-401. The Magnatreat M-401 process, licensed by Baker Performance Chemicals, Inc., is a non-regenerative batch process for selectively removing H=S from natural gas. The Magnatreat product is a mixture of triazine and water. The reaction between Magnatreat M-401 and H2S is complex and consists of series of reactions with the formation of a cyclic sulfur product known as bis-dithiazine and dithiazine. Figure 7.12 shows a schematic flow diagram for a typical Magnatreat acid gas treating unit. The major equipment includes an Inlet Filter Separator (1701L), Contactor (1701 E-A/B), and an Outlet Gas Separator (1701F). The Magnatreat process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. The inlet sour gas passes through an Inlet Filter Separator (1701L) to separate out any entrained liquid and salt water in the gas stream. The gas then enters the bottom of the Contactor (1701 E-A) where the hydrogen sulfide is then removed by its reaction with the Magnatreat product to form stable, water soluble products that may be easily removed from the system. The other Contactor (1701E-B) is cleaned and recharged with fresh Magnatreat M-401 and placed in series with Contactor (1701 E-A). The treated gas passes to an Outlet Gas Separator (1701F) to prevent any carryover of chemical solution from the contactor vessel into the gas pipeline. The fresh scavenger contains a proprietary formulation and methanol. The spent scavenger contains methanol and unknown components because of the proprietary formulation of the fresh scavenger. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations. If they are, they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. Methanol is listed under the current regulations. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. Methanol is listed under the current regulations. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." Methanol is listed under the current regulations. d) Superfund Amendments and Reorganization of 1986 (SARA) Title II1. Methanol is listed under the current regulations. e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Methanol is listed under the current regulations. Local or state regulations may limit the handling and disposal of the spent scavenger. Methanol is listed under state regulations for California, Massachusetts, New Jersey and Pennsylvania. The vendor claims the spent scavenger is non-hazardous under 29 CFR 1910.1200.

Gas Treat 114

The hydrogen sulfide scavenger, Gas Treat 114, has replaced Gas Treat 102. The Gas Treat 114 process, licensed by Champion Technologies Inc., is a non-regenerative batch process for selectively removing hydrogen sulfide from natural gas. The treating chemical, Gas Treat 114, is a novel class of alkylamine. The Gas Treat 114 instantaneously reacts with H=S, but does not react with CO2. The scavenger is made up of 30% Gas Treat 114 and 70% water. Figure 7.13 shows a schematic flow diagram for a typical Gas Treat acid gas treating unit. The major equipment includes an Inlet Filter Separator (1401L), Contactor (1401E-NB), and an Outlet Gas Separator (1401F). The Gas Treat process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet feed gas while the other spent bed is being drained and cleaned. The inlet sour gas passes through an Inlet Filter Separator (1401L) to separate out any entrained liquid and salt water in the gas stream. Liquid hydrocarbons must be removed from the feed to the scavenger system. The gas then enters the bottom of the Contactor (1401 E-A) where the hydrogen sulfide is then removed by the reaction with the alkylamine to form stable, water soluble products that may be easily removed from the system. The other Contactor (1401E-B) is cleaned and recharged with fresh Gas Treat 114. The treated gas passes to an Outlet Gas Separator (1401F) to prevent any carryover of chemical solution from the contactor vessels into the gas pipeline. The fresh scavenger contains an alkylamine and water. The scavenger is claimed to be a proprietary formulation. The spent scavenger contents are unknown. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations. If they are, they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." d) Superfund Amendments and Reorganization of 1986 (SARA) Title II1. Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Local or state regulations may limit the handling and disposal of the spent scavenger. The vendor claims the disposal of the expended solvent for inland use can be done in a Class II, nonhazardous waste system.

SulfuRid

The SulfuRid process, licensed by Weskem-Hall Inc., is a non-regenerative batch process for selectively removing H2S from natural gas. The treating chemical, SulfuRid, is a high molecular weight, cyclic tertiary amine. The SulfuRic] chemical rapidly reacts with H2S (Weskem Report 1993). Enough data were furnished by the vendor to size the vessel and the cost of operation (Weskem 1993). Figure 7.14 shows a schematic flow diagram for a typical SulfuRid acid gas treating unit. The major equipment includes an Inlet Filter Separator (1601L), Contactor (1601E-NB), and an Outlet Gas Separator (1601F). The SulfuRid process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. The inlet sour gas passes through an Inlet Filter Separator (1601L) to separate out any entrained liquid or salt water in the gas stream. The gas then enters the bottom of the Contactor (1601E-A) where the hydrogen sulfide is removed by reaction with a cyclic tertiary amine to form stable, water soluble products that may be easily removed from the system. The other Contactor (1601 E-B) is cleaned and recharged with fresh SulfuRid and placed in series with Contactor (1601 E-A). The treated gas passes to an Outlet Gas Separator (1601F) to prevent any carryover of chemical solution from the contactor vessels into the gas pipeline. The fresh scavenger contains proprietary compounds. The spent scavenger contains proprietary components. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations and if they are they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table/' d) Superfund Amendments and Reorganization of 1986 (SARA) Title III. e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Local or state regulations may limit the handling and disposal of the spent scavenger. The vendor claims the reacted by-products of the scavenger are water soluble salts that present no disposal problems. The salts, when in a water solution, may be injected into most licensed salt water disposal wells.

Magnatreat M-118W

The Magnatreat M-118W process, licensed by Baker Performance Chemicals, Inc., is a non-regenerative batch process for selectively removing H2S from natural gas. The Magnatreat product is a mixture of formaldehyde, methanol and water. The reaction between Magnatreat M-118W and H2S is complex and consists of a series of reactions with the formation of a cyclic sulfur product known as trithiane and medium- and long-chain mercaptans (Schaack and Chan 1989). Similar to Scavinox and Dichem, Magnatreat M-118W has been taken off the market at this time (Schaack 1989). Fi.qure 7.15 shows a schematic flow diagram for a typical Magnatreat M-118W acid gas treating unit. The major equipment includes an Inlet Filter Separator (801L), Contactor (801E-A/B), and an Outlet Gas Separator (801F). The Magnatreat process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. The inlet sour gas passes through an Inlet Separator (801L) to separate out any entrained liquid and salt water in the gas stream. The gas then enters the bottom of the Contactor (801E-A) where the hydrogen sulfide is then removed by the reaction with the Magnatreat product. The treated gas passes to an Outlet Gas Separator (801F) to prevent any carryover of chemical solution from the contactor vessels into the gas pipeline. The spent scavenger contains the known components of formaldehyde, methanol and water. The spent scavenger contains various forms of trithiane belonging to a family of complex chemicals known as formthionals. Also according to Schaack and Chan (1989), one characteristic of the formaldehyde-based scavenger is the formation of water soluble, medium- and long-chain mercaptans. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations. If they are, they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. Formaldehyde and methanol are listed under the current regulation. a) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. Formaldehyde and methanol are listed under the current regulation. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." Formaldehyde and methanol are listed under the current regulation. d) Superfund Amendments and Reorganization of 1986 (SARA) Title II1. Formaldehyde and methanol are listed under the current regulations. e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Formaldehyde and methanol have published exposure limits set by these regulations. Local or state regulations may limit the handling and disposal of the spent scavenger. Refer to Table 8.1 for the components regulated in the states of California, Massachusetts, New Jersey and Pennsylvania. Schaack and Chan (1989) indicated that Magnatreat M-118W or similar formaldehyde-based chemicals are safe to use if handled properly. Also, Schaack and Chan (1989) indicated Alberta's Energy Resource Conservation Board has approved the spent formaldehyde-based chemical for deep well disposal. However, the compatibility of the formation and the risk of plugging must be checked. Formaldehyde is suspected of having carcinogenic potential (MSDS).

Scavinox

The Scavinox process is a non-regenerative batch process for selectively removing H2S from natural gas. The Scavinox product exhibits similar behavior to Magnatreat M-118W in its formulation. The hydrogen sulfide scavenger, Scavinox, is a formaldehyde-based solvent. The scavenger is made up of approximately 60% formaldehyde and 40% methanol. The reaction with hydrogen sulfide is complex with the product being various forms of trithiane. These belong to a family of complex chemicals called formthionals. Some of the side reactions form products of medium- and long-chain mercaptans which are water soluble. These mercaptans give the spent scavenger a very distinctive and objectionable odor (Schaack 1989a). Similar to Magnatreat M-118W and Dichem, Scavinox has been taken off the market at this time (Schaack 1989). The odor-causing mercaptans have contaminated the treated gas where it caused problems with downstream equipment such as a regeneration system in a glycol dehydrator system and drip pots in piping (Schaack 1989a). The fresh scavenger solution has a freezing point of approximately -58F which may be an advantage in cold climates. Fi.qure 7.16 shows a schematic flow diagram for a typical Scavinox acid gas treating unit. The major equipment includes an Inlet Filter Separator (901L), Contactor (901E-NB) and an Outlet Gas Separator (901F). The Scavinox process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. The inlet sour gas passes through an Inlet Filter Separator (901L) to separate out any entrained liquid or salt water in the gas stream. The gas then enters the bottom of the Contactor (901E-A) where the hydrogen sulfide is removed by reaction with the Scavinox material. The other Contactor (901E-B) is cleaned and recharged with fresh Scavinox. The treated gas passes to an Outlet Gas Separator (901F) to prevent any carryover of chemical solution from the contactor vessels into the gas pipeline (Schaack and Chart 1989a). The fresh scavenger contains the known components of formaldehyde, methanol and water. The spent scavenger contains the known components of formaldehyde, methanol, water, and various forms of trithiane belonging to a family of complex chemicals known as formthionals. Also according to Schaack and Chan (1989), one characteristic of the formaldehyde-based scavenger is the formation of water soluble, medium- and long-chain mercaptans. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations and if they are they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. Formaldehyde and methanol are listed under the current regulation. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. Formaldehyde and methanol are listed under the current regulation. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." Formaldehyde and methanol are listed under the current regulation. d) Superfund Amendments and Reorganization of 1986 (SARA) Title III. Formaldehyde and methanol are listed under the current regulations. e) Occupational Safety and Health Administration (OSHA) with recommendation from the

American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Formaldehyde and methanol have published exposure limits set by these regulations. Local or state regulations may limit the handling and disposal of the spent scavenger. Refer to Table 8.1 for the states of California, Massachusetts, New Jersey and Pennsylvania for the components regulated. Schaack and Chan (1989) indicated that Scavinox or similar formaldehyde-based chemicals are safe to use if handled properly. Also, Schaack and Chan (1989) indicated Alberta's Energy Resource Conservation Board has approved the disposal of spent formaldehyde-based chemical for deep well disposal. However, the compatibility of the formation and the risk of plugging must be checked. Because of the odor, formaldehyde-based scavengers such as Scavinox require special care to be used in design to reduce handling and direct contact of the chemical by operating personnel. Formaldehyde is suspected of having carcinogenic potential (MSDS).

Prohib 196

The Prohib 196 process is a non-regenerative batch process for selectively removing H2S from natural gas. The Prohib 196 product exhibits similar behavior to Magnatreat M-118W in its formulation. Prohib 196 is one of the hydrogen sulfide scavengers that is based on the formaldehyde/methanol solution. The reaction with hydrogen sulfide produces hydroxy/methyl mercaptan and dimercaptan methyl ether. The mercaptans produce the characteristic offensive odor. In addition, the scavenger produces a sticky white jelly that has fouled downstream equipment (Schaack 1989a). The scavenger is a flammable liquid which requires the same precaution as the other formaldehyde/methanol based chemicals. The fresh and spent solvent are not considered to be corrosive thus carbon steel material of construction is satisfactory (Schaack 1989a). Fi,qure 7.17 shows a schematic flow diagram for a typical Prohib 196 acid gas treating unit. The major equipment includes an Inlet Filter Separator (1001L), Contactor (1001 E-NB), and an Outlet Gas Separator (1001F). The Prohib 196 process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. The inlet sour gas passes through an Inlet Filter Separator (1001L) to separate out any entrained liquid or salt water in the gas stream. The gas then enters the bottom of the Contactor (1001 E-A) where the hydrogen sulfide is removed by reaction with the Prohib 196 material. The other Contactor (1001E-B) is cleaned and recharged with fresh Prohib 196. The treated gas passes to an Outlet Gas Separator (1001 F) to prevent any carryover of chemical solution from the contactor vessels into the gas pipeline. The fresh scavenger contains the known components of formaldehyde, methanol and water. The spent scavenger contains the known components of formaldehyde, methanol, water, and various forms of trithiane belonging to a family of complex chemicals known as formthionals. Also according to Schaack and Chart (1989), one characteristic of the formaldehyde-based scavenger is the formation of water soluble, medium- and long-chain mercaptans. The components in the fresh and spent scavenger may or may not be listed under one or more of the following regulations and if they are they may present a disposal problem. a) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.33. Formaldehyde and methanol are listed under the current regulation. b) Comprehensive Emergency Response Compensation and Liability Act 1980 (CERCLA) from 40 CFR Part 302 Table 302.4. Formaldehyde and methanol are listed under the current regulation. c) Department of Transportation (DOT) from 49 CFR 172.102 "Hazardous Material Table." Formaldehyde and methanol are listed under the current regulation. d) Superfund Amendments and Reorganization of 1986 (SARA) Title II1. Formaldehyde and methanol are listed under the current regulations. e) Occupational Safety and Health Administration (OSHA) with recommendation from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). Formaldehyde and methanol have published exposure limits set by these regulations. Local or state regulations may limit the handling and disposal of the spent scavenger. Refer to Table 8.1 for the components regulated in the states of California, Massachusetts, New Jersey and Pennsylvania. Schaack and Chart (1989) indicated that Prohib 196 or similar formaldehyde-based chemicals are safe to

use if handled properly. Also, Schaack and Chan (i989) indicated Alberta's Energy Resource

Conservation Board has approved the disposal of spent formaldehyde-based chemical for deep well disposal. However, the compatibility of the formation and the risk of plugging must be checked. Formaldehyde is suspected of having carcinogenic potential (MSDS)

Dichlor

The Dichlor process, licensed by Exxon Chemical Company, is a non-regenerative batch process for selectively removing H2S from natural gas. A schematic diagram of the Dichlor process is depicted in Figure 7.18. The Dichlor process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. The inlet sour gas containing CO2 and H=S is first passed through an Inlet Filter Separator (1901L) so that entrained liquid droplets are removed from the feed gas stream. Typical contaminants may include distillate, water, solids, and/or other treating chemicals. The sour inlet gas enters the bottom of a carbon steel Contactor (1901E-A/B) where the H2S can be absorbed selectively from the sour gas containing CO2. Selectivity is achieved by maintaining a proper residence contact time between the gas and Dichlor (chlorine dioxide) liquid in a batch mode operation. The treated gas leaves the top of the contactor and passes through a two-phase scrubber, Outlet Gas Separator (1901 F), where any solvent carried over is removed. Because the vendor did not supply any design information and no data were found in the literature, the Dichlor process was not evaluated in this study.

Surflo 2341

The Surflo 2341 process, licensed by Exxon Chemical Company, is a non-regenerative batch process for selectively removing H2S from natural gas. A schematic diagram of the Surflo 2341 process is depicted in Figure 7.19. The Surflo 2341 process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. The inlet sour gas containing CO2 and H2S is first passed through an Inlet Filter Separator (2001L) to remove entrained liquid droplets from the feed gas stream. Typical contaminants may include distillate, water, solids, and/or other treating chemicals. The sour inlet gas enters the bottom of a carbon steel Contactor (2001E-A/B) where the H2S can be absorbed selectively from the sour gas containing CO=. Selectivity is achieved by maintaining a proper contact time between the gas and Surfio 2341 (chlorine dioxide) liquid in a batch mode operation. The treated gas leaves the top of the contactor and passes through a two-phase scrubber, Outlet Gas Separator (2001F), where any solvent carried over is removed. Because the vendor did not supply any design information and no data were found in the literature, the Surflo 2341 process was not evaluated in this study.

MADS (Sulfur Resistant Molecular Sieve)

The MADS process, a sulfur resistant molecular sieve licensed by UOP (Universal Oil Products), is a nonregenerative batch process for selectively removing H2S from natural gas. Figure 7.20 shows a schematic flow diagram for a typical MADS acid gas treating unit. The major equipment includes an Inlet Filter Separator (1301 L) and Contactor (1301 E-A/B). The MADS process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. The inlet sour gas passes through an Inlet Filter Separator (1301L) to separate out any entrained liquid or salt water in the gas stream. The gas then enters the bottom of the Contactor (1301 E-A) where the hydrogen sulfide is removed by adsorption on the molecular sieves. The other Contactor (1301E-B) is cleaned and recharged with new molecular sieves. Because the vender declined to give any design data for this system and no design data were found in the literature, the MADS process was not evaluated in this study. The material was recently removed from the market (Wolfe 1993).

Inhibit 101

The Inhibit 101 system, licensed by Stoller Enterprises, Inc., is a non-regenerative batch process for selectively removing H2S from natural gas. A schematic diagram of the Inhibit 101 process is depicted in Figure 7.21. The Inhibit process operates on a batch cycle. Two contactors are normally used in lead/lag arrangement, where one is contacting the inlet gas while the other (spent) bed is being drained and cleaned. The inlet sour gas containing CO2 and H2S is first passed through an Inlet Filter Separator (1801L) so that entrained liquid droplets are removed from the feed gas stream. Typical contaminants may include distillate, water, solids, and/or other treating chemicals. The sour inlet gas enters the bottom of a carbon steel Contactor (1801E-NB) where the H2S can be absorbed selectively from the sour gas containing CO2. Selectivity is achieved by maintaining a proper contact time between the gas and Inhibit 101 (amine sulfide) liquid in a batch mode operation. The treated gas leaves the top of the contactor and passes through a two-phase scrubber, Outlet Gas Separator (1801F), where any solvent carried over is removed. Because the vendor did not provide design data and no design data were found in the literature, the Inhibit 101 system was not evaluated in this study.

Method of Evaluation

Screening Index (SI) The hydrogen sulfide scavengers were evaluated by a screening index (SI). The SI was determined using seven parameters having values between 0 (worst) and 5 (best). The parameters for each scavenger were multiplied by a weighting factor, and summed: this sum is the SI. This method was introduced by Schaack and Chan (1989a), called by them the Index of Selection, lOS. The parameters and weighting factors are listed below.

Parameter Total Plant Investment Operating Cost Process Reliability (PR) Winterization (W) Ease of Operation (EOP) Operator Acceptance (OA) Ease of Disposal of Spent Material (DOSM): Hazardous Non-hazardous Hazardous and recyclable

Weighting Factor 0.2 1.0 1.0 0.2 0.5 0.4

0.0 0.4 0.8

Non-hazardous and recyclable 1.0 The highest theoretical value obtainable by a scavenger (assuming each parameter equal to 5, and the spent material being non-hazardous and recyclable) is thus 21.5. All scavenger systems were normalized to this highest theoretical SI (21.5). Refer to Tables 9.1, Table 9.2, and Table 9.3. The SI has been used in this evaluation for screening purposes only, and the ratings and weighting factors used are specific only to this particular evaluation. The ratings and weighting factors applicable to another situation may be different than those used herein. Several of the parameters are subjective in nature, and were assigned values based upon engineering experience and judgment based upon the data available at the time. These values could change. For example, future environmental regulations could affect the handling and disposal of scavenger materials, which would require use of a different set of DOSM factors for those materials. The values used in this study are presented below.

Scavenqer SulfaTreatTM Zinc Oxide MagnaTreat M-401

PR 5 5 3

W 5 4 4

EOP 5 4 4

OA 5 4 4

DOSM 5 4 4

DOSM factor 1.0 0.8 0.4

SulfaCheck 2420 Scavinox SulfuRid Iron Sponge

4 3 3 5

4 4 4 4

4 4 3 4

5 0 4 2

3 0 4 2

0.4 0 0.4 0

SulfaScrub EcoTreat SulfaGuard Gas Treat 114 ChemSweet C.J. Carbon Caustic Soda

4 2 4 4 3 3 4

4 2 4 4 2 5 2

4 2 4 4 2 3 3

4 3 4 4 3 4 4

5 0 5 4 0 3 0

1.0 0.4 1.0 0.4 0 0.4 0

SulfuSorbTM 2 5 4 3 5 0.4 The methods for obtaining the other parameter (operating cost and total plant Investment) ratings are presented in the following sections. Related Topics: Operating Cost Total Plant Investment Estimated Maximum Economical Sulfur Removal Rate Disposal Regulations

Operating Cost

The operating cost for each hydrogen sulfide scavenger system was determined for recharging one bed. A bed life of 25 days was set for comparison purposes. The operating cost included the labor and equipment rental for changeout and the scavenger cost for one charge. Spent material transportation and disposal costs were not included in the operating cost calculation. The operating costs of each system were compared to the scavenger system that was determined to have the lowest operating cost. Thus the relative cost of each system was established. Refer to Tables 9.4 through 9.6. It is recognized that each scavenger has an optimum bed life for each specific site condition. However, a 25-day bed life was considered adequate for screening purposes in this study.

Total Plant Investment

The Total Plant Investment (TPI) was determined by the procedure as outlined below: Field Costs: Equipment Cost xx Bulk Material Cost xx Subcontract Cost xx Material Related Cost xx Construction Cost xx xxx --> Total Field Cost xxx Engineering (40% of Home Office Cost) xx Procurement (4% of Home Office Cost) xx Home Office Construction Support (20% of Home Office Cost) xx Total Home Office Cost (12% of Field Cost) xxx --> Base Plant Cost (Field Cost Plus Home Office Cost) Project Contingency (20% of Base Plant Cost) Total Facilities Investment (Base Plant Cost + Project Contingency) Plus Initial Charge of Chemical Startup Cost (10% of Ann Op Cost) xx xx

xxx xxxx xxx xxxx

Paid-Up Royalties (3% of Total Facilities Investment) xx

XXX -->

Total Plant Investment (TPI) xxxx The TPI was determined for each scavenger system. The relative Total Plant Investment was established by companng the TPI ot each scavenger system to the system that had the lowest TPI. Refer to Table 9.7, Table 9.8, and Table 9.9.

Estimated Maximum Economical Sulfur Removal Rate

A separate screening analysis was done to estimate the maximum economical sulfur removal rate for each scavenger. A vessel size of 4' ID x 30' TFF and 25-day life were assumed. Although not used with the Screening Index directly, the resulting table (Table 9.10) could serve as a preliminary screening tool based only on sulfur to be removed. The vessel size of 4' ID x 30' T/T was assumed to be the maximum size that could be conveniently utilized in an average scavenger application. The volume rate of inlet gas dictates the diameter of the vessel required. Thus, the gas flow rate was variable for each scavenger's maximum superficial velocity and was not considered in this separate evaluation. In addition, the cost of the vessel and the scavenger did not enter into this calculation. For the rest of the study scavenger comparisons were based on sulfur loading only. The scavengers were then subjected to a detailed design where parameters of gas pressure, gas flow rate, minimum and maximum superficial velocity, expansion of liquid, head space and loading capacity of the scavenger were considered.

Disposal Regulations

A tabulation, Table 8.1a, Table 8.1b, and Table 8.1c, was made of the components that are known and expected in the fresh and spent scavenger and the various regulations affecting handling and disposal of the scavenger. The regulations considered in these evaluations were five federal and four state. The federal regulations included: a) Department of Transportation (DOT) from 49 CFR 172.101 "Hazardous Materials Table." b) Resource Conservation and Recovery Act (RCRA) from 40 CFR 261.23. c) Comprehensive Emergency Response Compensation and Liability Acts 1980 (CERCLA) from CFR Part 30Z Table 302.4. d) Superfund Amendments and Reorganization of 1986 (SARA) Title III. e) Occupational Safety and Health Administration (OSHA) with recommendations from the American Conference of Governmental Industrial Hygienists (ACGIH), the National Institute of Occupational Safety and Health (NIOSH) and the Province of Alberta's Occupational and Health and Safety Act (Canada). The state regulations included: g) California Safe Drinking Water and Toxic Enforcement Act of 1986 "Proposition 65," "Chemical Known to the State to Cause Cancer or Reproductive Toxicity, "April/1993.

h) Massachusetts Substance List, Massachusetts Department of Public Health. i) "Right to Know Hazardous Substance List," New Jersey. j) Hazardous Substance List from the 1990 Hazardous Substance Survey Form (HSSF), Commonwealth of Pennsylvania's Department of Labor and Industry. Only four state regulations were included in the tabulation due to limitation of data readily available. Local regulations should also be consulted to establish additional handling and disposal requirements. All the data presented in the tabulation were taken from "The Book of Chemical Lists Volume I and I1" produced by Shafer Environmental Associates, Ltd and published by Business and Legal Reports, Inc. To use the tabulation take Sulfa-Scrub scavenger as an example. The triazine and the reaction products, bis-dithiazine and dithiazine are not listed under any regulation considered. The other components included in the fresh scavenger are methanol and monoethanolamine. Methanol is also listed under the federal regulations of DOT, RCRA, CERCLA, SARA and OSHA. Methanol is listed under state regulations of California, Massachusetts and Jew Jersey. Monoethanolamine is listed under federal regulations of DOT and OSHA. Monoethanolamine is listed under state regulations of Massachusetts, New .Jersey and Pennsylvania.

Relative Screening Index (SI)

The hydrogen sulfide scavengers were evaluated by the Screening Index correlation. The Relative Screening Index was determined for each by comparison to the maximum Screening Index, 25.5. The scavenger with the best Relative Screening Index was SulfaTreatTM at all three sulfur capacities evaluated:

Capacity Lbs Sulfur/Day Relative Screeninq Index 3 60 0.95 0.99

100 0.99 The next best rated scavenger was SulfaGuard at all three sulfur capacities evaluated:

Capacity Lbs Sulfur/Day Relative Screeninq Index 3 60 0.90 0.89

100 0.89 The lowest SI-rated scavenger was SulfuSorbTM at all three sulfur capacities evaluated:

Capacity Lbs Sulfur/Day Relative Screeninq Index 3 60 0.42 0.38

100 0.38 Refer to Table 9.1, Table 9.2, and Table 9.3 for the relative SI ratings of all scavengers evaluated.

Relative Operating Cost

The operating cost included the labor, equipment rental and scavenger cost for one bed changeout. Spent material transportation and disposal costs were not included in the operating cost calculation. The Relative Operating Cost was determined by comparing each scavengeds operating cost with the scavenger that had the lowest operating cost. The lowest Relative Operating Cost was exhibited by the System 17 Magnatreat M-401 scavenger for the 3 lbs sulfur/day capacity, while the lowest relative operating cost was exhibited by System 2 Sulfa-Check 2420 scavenger for the 60 and 100 lbs sulfur/day capacities. The scavenger with the highest Relative Operating Cost was System 11 (SulfuSorbTM) for all sulfur capacities evaluated. This is due to SulfuSorbTM'S significantly higher material cost. While the scavenger with the highest and lowest relative operating costs were consistent (highest-System 11 SulfuSOrbTM; and lowest-System 8 Magnatreat M-118W and System 2 Sulfa-Check 2420) some of the other scavengers showed a wide variation in cost with sulfur capacity. As examples consider System 16 SulfuRid and System 4 Iron Sponge:

System 16 SulfuRid: Sulfur Capacity lb/dayRelative Operatin,q Cost 3 60 100 System 4 Iron Sponge: Sulfur Capacity lb/dayRelative Operatin,q Cost 3 60 6.140 1.580 1.073 1.416 1.803

100 1.342 Refer to Table 9.4, Table 9.,5, and Table 9.6 for the relative operating costs of all the scavengers evaluated.

Relative Total Plant Investment

The lowest-cost scavenger for the three capacities of 3, 60 and 100 lbs sulfur/day was the System 5 SulfaTreatTM Scavenger. The highest-cost scavenger varied with the sulfur capacity.

Sulfur Capacity lb/day 3 60

Hi,qhest Total Plant Investment System 1 Caustic Soda System 1 Caustic Soda

100 System 11 SulfuSorbTM Refer to Tables 9.7, Table 9.8. and Table 9.9 for the relative total plant Investments of all the scavengers evaluated.

Estimated Maximum Effective Sulfur Removal

System 6 Zinc Oxide had an estimated maximum effective sulfur removal of 300 lbs sulfur per day for the vessel size and turnaround chosen. Five systems had an estimated maximum effective sulfur removal of 200 lbs sulfur per day, they included:

System 2 System 9 System 5 System 15

Sulfa-Check 2420 Scavinox SulfaTreatTM SulfaGuard

System 16 SulfuRid Four systems had an estimated maximum effective sulfur removal of less than 100 lbs sulfur per day, they include:

System 12 System 3 System 4

Sulfa-Scrub Ecotreat Iron Sponge

System 14 Gas Treat 114 The System 17 Magnatreat M-401 had an estimated maximum effective sulfur removal of less than 80 lbs sulfur per day. Two systems had an estimated maximum effective sulfur removal of less than 60 lbs per day, they included:

System 7

Chemsweet

System 21 Activated Carbon Type CJ Two systems had an estimated maximum effective sulfur removal of less than 3 lbs per day, they included:

System 11 System 1

SulfuSorbTM Caustic Soda

Refer to Table 9.10 for the estimated maximum effective sulfur removal of all scavengers evaluated. For a different size vessel and assumed bed life the maximum sulfur capacity will change. However, the relative positions should not change.

Additional Comments

In the literature additional scavengers were found. While most of these materials are primarily used in the drilling, completion and workover fluids area, some might be appropriate for removing hydrogen sulfide from natural gas. None of these materials were considered in this evaluation (World Oil 1993). The current study involves only a few of the H2S scavengers that are available but were selected for their specific application. Table 10.1 contains additional scavengers that should be considered for future evaluation.

Conclusions

Under the conditions considered, the SulfaTreatTM System was the most favored scavenger technology based on the Relative Screening Index and Relative Total Plant Investment. The SulfaTreatTM System is easy to handle both for charging and removal of spent beds. The disposal of spent scavenger presented only a minimal problem; the spent scavenger can be deposited in a Class I non-hazardous landfill or recycled for other uses. A potential application of the spent scavenger as a soil additive has been proposed. While the formaldehyde-methanol based scavengers, such as Scavinox, have some advantages in relative operating cost, they have a distinct disadvantage in ease of handling because of their offensive odor and the probability of formaldehyde being a human carcinogen. Both the fresh and spent scavenger have a very offensive odor and suspected carcinogen qualities. Several scavengers are based on hexahydrotriazine, such as Sulfa-Scrub, SulfaGuard and Magnatreat M401. The results varied slightly among the scavengers although data was furnished by various vendors. While the Relative Operating Cost for these scavengers was unfavorable, the advantage of ease of handling both the fresh and spent solutions must be considered. The spent scavenger has a potential for use as a corrosion inhibitor. In the future the single source for this type of scavenger may be the Petrolite Corporation, Tretolite Division, who has obtained the patent covering the chemistry application of triazine, the base component of the Sulfa-Scrub scavenger. The H2S scavenger technologies appear to be under considerable dynamic change. Many vendors market numerous scavengers. Many scavengers are being introduced and others are being withdrawn from the market. Several scavengers have been renamed and reintroduced. The use of common names by the various vendors has led to some confusion. The data provided by most vendors are insufficient, and the engineering design of equipment is left to the user to develop. The evaluation of H2S scavenger technologies indicated that the design basis of 592 ppm(v) as hydrogen sulfide was the upper limit of the application of these technologies for the vessel size and bed life assumed. With larger vessels and/or shorter bed lives that limit could be extended. The evaluation also revealed that each H2S scavenger had an indicated maximum effective sulfur removal at the design conditions. For example, Zinc Oxide (High Temperature), Sulfa-Check 2420, Scavinox, SulfaTreatTM, SulfaGuard and SulfuRid can remove sulfur in excess of 100 lbs sulfur/day. However, in excess of 100 lbs sulfur/day a regenerative type system such as MDEA or DGA may show an economic advantage.

References

Anerouis, J. P., Whitman, S. K. 1985 "Iron Sponge: Still a Top Option for Sour Gas Sweetening" Oil and Gas Journal Tulsa: PennWell Publishing Co., 71-76. Baker Performance Chemical Inc. 1994. Personal communication. Bhatia, K., AIIford K. T. 1986 "One-Step Process Takes U2S from Gas Stream" Oil and Gas Journal Tulsa: PennWell Publishing Co., October 20, 44-49. Bhatia, K., 1992 "Application of Sulfa-Check in the Gas Industry." Paper published in the Proceedings of the Gas Research Institute Liquid Redox Sulfur Recovery Conference, Austin, October 4-6.

Calgon, 1978 "Sulfur Control with Metal Oxide- Impregnated Carbon." Houston. Carnell, P. J. H. "New Fixed-bed Adsorbent for Gas Sweetening." Oil and Gas Journal. Tulsa: PennWell Publishing Co., August 18, 59-62. Coastal Chemical Company 1993 "Coastal Chemical Report." Houston. Coastal Chemical Company 1994. Personal communication. Dillon, E. T. 1991 "Gas Sweetening with a Novel and Selective Alkanolamine." Paper presented at the 70th Annual Gas Processors Association (GPA), San Antonio, March 11-12. Duckworth, G. L., Geddes, J. H. 1965. "Iron Sponge Process Works Well at Retlow." Hydrocarbon Processing. Houston: Gulf Publishing Co., Vol 44, No. 9, 179-182. Manieh, A. A., Ghorayebn, 1981 "How to Design a Caustic Wash." Hydrocarbon Processing. Houston: Gulf Publishing Co., September, 143-144. Manning, W. P., Trahan, D. O. 1992 "Batch Gas Sweetening Process." Paper presented at the 1992 Gas Research Institute Liquid Redox Sulfur Recovery Conference. Austin, October 4-6. NATCO 1982 "Efficient, Economical Gas Sweetening Systems." Houston. Raab, M. 1976 "Caustic Scrubbers Can Be Designed for Exacting Needs." Oil and Gas Journal Tulsa: PennWell Publishing Co., October 11,120-125. Samuels, A. 1990. "Hydrogen Sulfide Removal System Shows Promise Over IRON SPONGE." Oil and Gas Journal. Tulsa: PennWell Publishing Co., January 23, 51-55. Schaack, J. P., Chart, F. 1989a. "Formaldehyde - Methanol, Metallic-Oxide Agents Head Scavenger List." Hydrogen Sulfide Scavenging 1. Oil and Gas Journal. Tulsa: Pennwell Publishing Co., January 23, 51-55. Schaack, J. P., Chan, F. 1989b. "Caustic-Based Process Remains Attractive." Hydrogen Sulfide Scavenging 2. Oil and Gas Journal. Tulsa: Pennwell Publishing Co., January 30, 81-82. Schaack, J. P., Chan, F. 1989c. "Process Design Guide-lines Vary Widely." Hydrogen Sulfide Scavenging 3. Oil and Gas Journal. Tulsa: Pennwell Publishing Co., February 20, 45-48. Schaack, J. P., Chart, F., 1989d. "Cost Estimating Depends on Location, Material." Hydrogen Sulfide Scavenging - End. Oil and Gas Journal. Tulsa: Pennwell Publishing Co., February 27, 90-91. The SulfaTreat Co. 1992. "Sour Gas Sweetening with SulfaTreat®. Paper presented to the Technical Committee of the 1992 GRI Liquid Redox Sulfur Recovery Conference. Austin, October 4-6. Tretolite Division, Petrolite Corp. 1994. Personal communication. Petroleum Engineer International. 1981 "Unit Cuts Gas Sweetening Cost." Staff Report. Denver: Had Publishing Co., August. Weskem Inc. 1993 "Weskem Technical Report." Houston. World Oil. 1993 "Classifications of Fluid Systems." Houston: Gulf Publishing Co., June, 69-104.

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